FORM 10-K - StockProInfo

Transcription

FORM 10-K
XTO ENERGY INC - XTO
Filed: March 07, 2005 (period: December 31, 2004)
Annual report which provides a comprehensive overview of the company for the past year
Table of Contents
10-K - FORM 10-K FOR THE PERIOD ENDED DECEMBER 31, 2004
Part III
PART I
Items 1. and 2. BUSINESS AND PROPERTIES
Item 3. LEGAL PROCEEDINGS
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
Item 5.
Item 6.
Item 7.
Item
7A.
Item 8.
Item 9.
Item
9A.
Item
9B.
MARKET FOR REGISTRANT S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Item 11. EXECUTIVE COMPENSATION
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
INDEX TO EXHIBITS
EX-2.2 (AGREEMENT AND PLAN OF MERGER)
EX-2.3 (AMENDED AGREEMENT AND PLAN OF MERGER)
EX-12.1 (COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES)
EX-21.1 (SUBSIDIARIES OF XTO ENERGY)
EX-23.1 (CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM)
EX-23.3 (CONSENT OF MILLER AND LENTS)
EX-31.1 (SECTION 302 CERTIFICATION OF CEO)
EX-31.2 (SECTION 302 CERTIFICATION OF CFO)
EX-32.1 (SECTION 906 CERTIFICATION OF CEO AND CFO)
Table of Contents
Index to Financial Statements
2004
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
⌧
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
OR
�
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number: 1-10662
XTO Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware
75-2347769
810 Houston Street, Fort Worth, Texas
76102
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code (817) 870-2800
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common Stock, $.01 par value, including preferred
stock purchase rights
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes
⌧ No �
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to be the best
of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form
10-K. ⌧
Indicate by checkmark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes
⌧ No �
Aggregate market value of the Common Stock based on the closing price on the New York Stock Exchange as of June 30, 2004 (the last business day of its most
recently completed second fiscal quarter), held by nonaffiliates of the Registrant on that date was approximately $7.3 billion.
Number of Shares of Common Stock outstanding as of February 25, 2005 (as adjusted for the four-for-three stock split to be effected March 15, 2005) 347,389,307
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Part III of this Report is incorporated by reference from the Registrant’s definitive Proxy Statement for its Annual Meeting of Stockholders, which will be filed
with the Commission no later than April 29, 2005.
Source: XTO ENERGY INC, 10-K, March 07, 2005
Table of Contents
XTO ENERGY INC.
2004 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page
Item
Part I
1. and 2.
3.
4.
Business and Properties
Legal Proceedings
Submission of Matters to a Vote of Security Holders
1
16
17
Part II
5.
6.
7.
7A.
8.
9.
9A.
9B.
Market for Registrant’s Common Equity and Related Stockholder Matters
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
18
19
21
40
42
42
42
42
Part III
10.
11.
12.
13.
14.
Directors and Executive Officers of the Registrant
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
Certain Relationships and Related Transactions
Principal Accountant Fees and Services
43
43
43
43
43
Part IV
15.
Exhibits and Financial Statement Schedules
44
Table of Contents
PART I
Items 1. and 2. BUSINESS
AND PROPERTIES
General
XTO Energy Inc. and its subsidiaries (“the Company”) are engaged in the acquisition, development, exploitation and exploration of producing oil and gas
properties, and in the production, processing, marketing and transportation of oil and natural gas. The Company was formerly known as Cross Timbers Oil
Company and changed its name to XTO Energy Inc. in June 2001.
On February 15, 2005, our Board of Directors declared a four-for-three stock split to be effected on March 15, 2005. All common stock shares and per
share amounts in this Form 10-K have been retroactively restated for the effect of this stock split.
Our corporate internet web site is www.xtoenergy.com. We make available free of charge, on or through the investor relations section of our web site, our
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the
Securities and Exchange Commission.
We have grown primarily through strategic acquisitions of proved oil and gas reserves, followed by development and exploitation activities and acquisition
of additional interests in or near such acquired properties. We expect growth in the immediate future to continue to be accomplished through a combination of
acquisitions and development. During 2005, we plan to continue to review strategic acquisition opportunities including property divestitures by major energy
related companies, public exploration and development companies and private energy companies. Completion of additional acquisitions will depend on the
quality of properties available, commodity prices and competitive factors.
Our corporate headquarters are located in Fort Worth, Texas at 810 Houston Street (telephone 817-870-2800). Our proved reserves are principally located
in relatively long-lived fields with well-established production histories concentrated in the following areas:
•
Eastern Region, including the East Texas Basin and northwestern Louisiana;
•
Barnett Shale of North Texas;
•
San Juan and Raton basins of northern New Mexico and southern Colorado;
•
Arkoma Basin of Arkansas and Oklahoma;
•
Permian Basin of West Texas and southeastern New Mexico;
•
Hugoton Field of Oklahoma and Kansas;
•
Anadarko Basin of Oklahoma;
•
Green River and Powder River basins of Wyoming;
•
Uinta Basin of Utah;
•
Middle Ground Shoal Field of Alaska’s Cook Inlet; and
•
South Texas Region.
We use the following volume abbreviations throughout this Form 10-K. “Equivalent” volumes are computed with oil and natural gas liquid quantities
converted to Mcf, or natural gas converted to Bbls, on an energy equivalent ratio of one barrel to six Mcf.
•
•
•
•
•
•
•
•
•
Bbl
Bcf
Bcfe
BOE
Mcf
Mcfe
MMBtu
Tcf
Tcfe
Barrel (of oil or natural gas liquids)
Billion cubic feet (of natural gas)
Billion cubic feet equivalent
Barrels of oil equivalent
Thousand cubic feet (of natural gas)
Thousand cubic feet equivalent
One million British Thermal Units, a common energy measurement
Trillion cubic feet (of natural gas)
Trillion cubic feet equivalent
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Our estimated proved reserves at December 31, 2004 were 4.71 Tcf of natural gas, 38.5 million Bbls of natural gas liquids and 152.5 million Bbls of oil,
based on December 31, 2004 prices of $5.69 per Mcf for gas, $28.24 per Bbl for natural gas liquids and $41.03 per Bbl for oil. On an energy equivalent basis, our
proved reserves were 5.86 Tcfe at December 31, 2004, a 40% increase from proved reserves of 4.18 Tcfe at the prior year end. Increased proved reserves during
2004 were primarily the result of acquisitions and development and exploitation activities. On an Mcfe basis, 72.3% of proved reserves were proved developed
reserves at December 31, 2004 . During 2004, our average daily production was 834,572 Mcf of gas, 7,484 Bbls of natural gas liquids and 22,696 Bbls of oil.
Fourth quarter 2004 average daily production was 915,905 Mcf of gas, 8,628 Bbls of natural gas liquids and 33,494 Bbls of oil.
Our properties have relatively long reserve lives and highly predictable production profiles. Based on December 31, 2004 proved reserves and projected
2005 production from properties owned as of December 31, 2004, the average reserve-to-production index of our proved reserves is 15.1 years. In general, these
properties have extensive production histories and production enhancement opportunities. While the properties are geographically diversified, the major
producing fields are concentrated within core areas, allowing for substantial economies of scale in production and cost-effective application of reservoir
management techniques gained from prior operations. As of December 31, 2004, we owned interests in 18,104 gross (8,455.8 net) producing wells, and we
operated wells representing 88% of the present value of cash flows before income taxes (discounted at 10%) from estimated proved reserves. The high proportion
of operated properties allows us to exercise more control over expenses, capital allocation and the timing of development and exploitation activities in our fields.
We have a substantial inventory of between 3,100 and 3,850 potential development drilling locations. Drilling plans are primarily dependent upon product
prices, the availability and pricing of drilling equipment and supplies, and gathering, processing and transmission infrastructure.
We employ a disciplined acquisition program refined by senior management to expand our reserve base in core areas and to add new core areas. Our
engineers and geologists use their expertise and experience gained through the management of existing core properties to target properties to be acquired with
similar geological and reservoir characteristics.
We operate gas gathering systems in several of our core producing areas. We also operate gas processing plants in East Texas, the Hugoton Field and the
Cotton Valley Field of Louisiana. Our gas gathering and processing operations are only in areas where we have production and are considered activities that
facilitate our natural gas production and sales operations.
We market our gas production and the gas output of our gathering and processing systems. A large portion of our natural gas is processed, and the resultant
natural gas liquids are marketed by unaffiliated third parties. We use fixed-price physical sales contracts and futures, forward sales contracts and other price risk
management instruments to hedge pricing risks.
History of the Company
The Company was incorporated in Delaware in 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986
through 1989. Our initial public offering of common stock was completed in May 1993.
During 1991, we formed Cross Timbers Royalty Trust by conveying a 90% net profits interest in substantially all of the royalty and overriding royalty
interests that we then owned in Texas, New Mexico and Oklahoma, and a 75% net profits interest in seven nonoperated working interest properties in Texas and
Oklahoma. Cross Timbers Royalty Trust units are listed on the New York Stock Exchange under the symbol “CRT.” From 1996 to 1998, we purchased
1,360,000, or 22.7%, of the outstanding units, at a total cost of $18.7 million. In August 2003, our Board of Directors declared a dividend of 0.0044 units of the
trust for each share of our common stock outstanding on September 2, 2003. As a result of this dividend, all of the 1,360,000 trust units were distributed on
September 18, 2003.
In December 1998, we formed the Hugoton Royalty Trust by conveying an 80% net profits interest in principally gas-producing operated working interests
in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were
conveyed to the trust in exchange for 40 million units of beneficial interest. We sold 17 million units in the trust’s initial public offering in 1999 and 1.3
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million units pursuant to an employee incentive plan in 1999 and 2000. We own the remaining 54% of the units, which we account for as producing properties.
Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol “HGT.”
Industry Operating Environment
The oil and gas industry is affected by many factors that we generally cannot control. Governmental regulations, particularly in the areas of taxation,
energy and the environment, can have a significant impact on operations and profitability. Crude oil prices are determined by global supply and demand. Oil
supply is significantly influenced by production levels of OPEC member countries, while demand is largely driven by the condition of worldwide economies, as
well as weather. Natural gas prices are generally determined by North American supply and demand. Weather has a significant impact on demand for natural gas
since it is a primary heating resource. Its increased use for electrical generation has kept natural gas demand elevated throughout the year, removing some of the
seasonal swing in prices. See “Significant Events, Transactions and Conditions – Product Prices” in Part II, Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations, regarding recent price fluctuations and their effect on our results.
Business Strategy
The primary components of our business strategy are:
•
acquiring long-lived, operated oil and gas properties, including undeveloped leases,
•
increasing production and reserves through aggressive management of operations and through development, exploitation and exploration activities,
•
hedging a portion of our production to stabilize cash flow and protect the economic return on development projects and acquisitions, and
•
retaining management and technical staff that have substantial experience in our core areas.
Acquiring Long-Lived, Operated Properties. We seek to acquire long-lived, operated producing properties that:
•
contain complex multiple-producing horizons with the potential for increases in reserves and production,
•
produce from non-conventional sources, including tight natural gas reservoirs, coal bed methane and natural gas-producing shale formations,
•
are in core operating areas or in areas with similar geologic and reservoir characteristics, and
•
present opportunities to reduce expenses per Mcfe, and lower the rate of potential increases to expenses per Mcfe, through more efficient operations.
We believe that the properties we acquire provide opportunities to increase production and reserves through the implementation of mechanical and
operational improvements, workovers, behind-pipe completions, secondary recovery operations, new development wells and other development activities. We
also seek to acquire facilities related to gathering, processing, marketing and transporting oil and gas in areas where we own reserves. Such facilities can enhance
profitability, reduce costs, and provide marketing flexibility and access to additional markets. The ability to successfully purchase properties is dependent upon,
among other things, competition for such purchases and the availability of financing to supplement internally generated cash flow.
We also seek to acquire undeveloped properties that potentially have the same attributes as targeted producing properties.
Increasing Production and Reserves. A principal component of our strategy is to increase production and reserves through aggressive management of
operations and low-risk development. We believe that our principal
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properties possess geologic and reservoir characteristics that make them well suited for production increases through drilling and other development programs.
We have generated an inventory of between 3,100 and 3,850 potential drilling locations. Additionally, we review operations and mechanical data on operated
properties to determine if actions can be taken to reduce operating costs or increase production. Such actions include installing, repairing and upgrading lifting
equipment, redesigning downhole equipment to improve production from different zones, modifying gathering and other surface facilities and conducting
restimulations and recompletions. We may also initiate, upgrade or revise existing secondary recovery operations.
Exploration Activities. During 2005, we plan to focus our exploration activities on projects that are near currently owned productive fields. We believe that
we can prudently and successfully add growth potential through exploratory activities given improved technology, our experienced technical staff and our
expanded base of operations. We have allocated approximately $30 million of our $850 million 2005 development budget for exploration activities.
Hedging Activities. To reduce production price risk, we enter futures contracts, collars and basis swap agreements, as well as fixed price physical delivery
contracts. Our policy is to routinely hedge a portion of our production. While there is a risk we may not be able to realize the full benefit of rising prices,
management plans to continue its hedging strategy because of the benefits provided by predictable, stable cash flow, including:
•
ability to more efficiently plan and execute our development program, which facilitates predictable production growth,
•
ability to help assure the economic return on strategic acquisitions,
•
ability to enter long-term arrangements with drilling contractors, allowing us to continue development projects when product prices decline,
•
more consistent returns on investment, and
•
better utilization of our personnel.
Experienced Management and Technical Staff. Most senior management and technical staff have worked together for over 20 years and have substantial
experience in our core operating areas. Bob R. Simpson and Steffen E. Palko, co-founders of the Company, were previously executive officers of Southland
Royalty Company, one of the largest U.S. independent oil and gas producers prior to its acquisition by Burlington Northern, Inc. in 1985.
Other Strategies. We may also acquire working interests in nonoperated producing properties if such interests otherwise meet our acquisition criteria. We
attempt to acquire nonoperated interests in fields where the operators have a significant interest to protect, including potential undeveloped reserves that will be
exploited by the operator. We may also acquire nonoperated interests in order to ultimately accumulate sufficient ownership interests to operate the properties.
We also attempt to acquire a portion of our reserves as royalty interests. Royalty interests have few operational liabilities because they do not participate in
operating activities and do not bear production or development costs.
Royalty Trusts and Publicly Traded Partnerships. We have created and sold units in publicly traded royalty trusts. Sales of royalty trust units allow us to
more efficiently capitalize our mature, lower-growth properties. We may create and distribute or sell interests in additional royalty trusts or publicly traded
partnerships in the future.
Business Goals. In January 2005, we announced a strategic goal for 2005 of increasing production by 21% to 23% over 2004 levels. To achieve this
growth target, we plan to drill about 735 (560 net) development wells and perform approximately 540 (400 net) workovers and recompletions in 2005.
We have budgeted $850 million for our 2005 development program, which is expected to be funded by cash flow from operations. We plan to spend $400
million in the Eastern Region of East Texas and northwestern Louisiana, $170 million in the Barnett Shale of North Texas, $85 million in the Raton, San Juan
and Uinta basins, $85 million for programs in the Permian Basin, and $80 million in the Arkoma Basin and Mid-Continent Region. We expect to spend $30
million for exploration.
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Table of Contents
While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2005. If acquisition,
development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, issuance
of public or private debt or equity, or asset sales. Strategic property acquisitions during 2005 may alter the amount currently budgeted for development and
exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2005 to focus on opportunities offering the highest rates
of return. We also may reevaluate our budget and drilling programs in the event of significant changes in oil and gas prices. Our ability to achieve production
goals depends on the success of our planned drilling programs or property acquisitions made in place of a portion of the drilling program.
The weak U.S. dollar, raw material shortages and strong global demand for steel have continued to tighten steel supplies and cause prices to remain high.
In response, we have increased our tubular inventory and have negotiated supply contracts with our vendors to support our development program. While we
expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production
growth and increasing development costs.
Acquisitions
During 2001, we acquired predominantly gas-producing properties for a total cost of $242 million. In January 2001, we acquired gas properties in East
Texas and Louisiana for $115 million from Herd Producing Company, Inc., and in February 2001, we acquired gas properties in East Texas for $45 million from
Miller Energy, Inc. and other owners. In August 2001, we acquired primarily underdeveloped acreage in the Freestone area of East Texas for approximately $22
million. The 2001 acquisitions increased reserves by approximately 248.3 Bcf of natural gas, approximately 50% of which were proved undeveloped.
During 2002, we acquired gas-producing properties for a total cost of $358.1 million. In May 2002, we acquired properties in the Powder River Basin of
Wyoming for $101 million. These properties were immediately exchanged with Marathon Oil Company for properties with the same value in East Texas and
Louisiana. In July, we purchased gas-producing properties in the San Juan Basin of New Mexico for $43 million and in December 2002, we purchased coal bed
methane gas-producing properties located in the San Juan Basin of New Mexico for $153.8 million from J.M. Huber Corporation. The 2002 acquisitions
increased reserves by approximately 330.4 Bcf of natural gas, 2.2 million Bbls of natural gas liquids and 449,000 Bbls of oil. Approximately 10% of these
reserves were proved undeveloped.
During 2003, we acquired gas-producing properties for a total cost of $629.5 million. In April 2003, we acquired natural gas and coal bed methane
producing properties in the Raton Basin of Colorado, the Hugoton Field of southwestern Kansas and the San Juan Basin of New Mexico and Colorado for $381
million from Williams of Tulsa, Oklahoma. In June 2003, we acquired coal bed methane and gas-producing properties in the San Juan Basin of New Mexico and
Colorado from Markwest Hydrocarbon, Inc. for $51 million. In October 2003, we announced the completion of property transactions which increased our
positions in East Texas, Arkansas and the San Juan Basin of New Mexico for a total cost of $100 million. The 2003 acquisitions increased reserves by
approximately 465.7 Bcf of natural gas, 4.5 million Bbls of natural gas liquids and 2.2 million Bbls of oil. Approximately 12% of these reserves were proved
undeveloped.
During 2004, we acquired producing properties for a total cost of $1.9 billion. In January 2004, we acquired producing properties in East Texas and
northwestern Louisiana for $243 million from multiple parties. From February through April, we purchased $223.1 million of properties located primarily in the
Barnett Shale of North Texas and in the Arkoma Basin. Two of these acquisitions were purchases of corporations that primarily owned producing and
nonproducing properties. Purchase accounting adjustments related to these acquisitions included a $72.3 million deferred income tax step-up adjustment. During
April, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and in the Powder River Basin of Wyoming from ExxonMobil
Corporation for $336 million, including a contingent payable of up to $5 million dependent on earnings from one property in the following year. In August, we
acquired properties from ChevronTexaco Corporation for a purchase price of $930 million, as adjusted for subsequent purchase of properties that were subject to
preferential purchase rights. These properties expand our operations in our Eastern Region, the Permian Basin and Mid-Continent Region and add new coal bed
methane properties in the Rocky Mountains and a new operating region in South Texas. All 2004 acquisitions are subject to typical post-close adjustments. Our
2004 acquisitions increased reserves by approximately 716.5 Bcf of natural gas, 2.9
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million Bbls of natural gas liquids and 98.2 million Bbls of oil. Approximately 18% of these reserves were proved undeveloped.
In January 2005, we announced an agreement to purchase privately held Antero Resources Corporation, a prominent Barnett Shale producer, for cash and
equity consideration valued at approximately $685 million. Consideration includes $337.5 million in cash, 13.3 million shares of our common stock and
five-year warrants to purchase another 2 million shares of our common stock at $27 per share. The purchase agreement was amended in February 2005 to include
Antero’s gas gathering assets and related bank debt of $175 million. The transaction is expected to close April 1, 2005. The booked acquisition cost will include
customary non-cash adjustments, including a step-up adjustment for deferred income taxes. The cash consideration for the acquisition will be initially provided
through cash flow from operations and existing bank credit facilities.
Significant Properties
The following table summarizes proved reserves and discounted present value, before income tax, of proved reserves by major operating areas at
December 31, 2004:
Proved Reserves
Gas
(Mcf)
Natural Gas
Liquids
(Bbls)
(Bbls)
Natural Gas
Equivalents
(Mcfe)
Oil
Discounted
Present Value
before Income Tax
of Proved Reserves
(in thousands)
Eastern Region
San Juan Basin and Rocky Mountain Area
Permian Basin and South Texas Region
Arkoma Basin and Mid-Continent Region
Hugoton Royalty Trust (a)
North Texas Region
Alaska Cook Inlet
Other
2,523,826
895,802
240,613
651,624
281,506
117,546
—
3,586
4,791
33,266
399
—
—
—
—
—
8,117
12,442
108,764
5,010
2,405
23
14,986
759
2,601,274
1,170,050
895,591
681,684
295,936
117,684
89,916
8,140
$ 5,442,885
2,253,065
2,019,883
1,529,162
573,865
205,381
197,221
15,587
44.5%
18.4%
16.5%
12.5%
4.7%
1.7%
1.6%
0.1%
Total
4,714,503
38,456
152,506
5,860,275
$ 12,237,049
100%
(a)
Includes 192,719,000 Mcf of gas and 1,647,000 Bbls of oil and discounted present value before income tax of $403,441,000 related to our ownership of
approximately 54% of Hugoton Royalty Trust units at December 31, 2004. The remainder is our retained interests in the properties underlying the trust’s
net profits interests.
Eastern Region
We began operations in the East Texas area in 1998 with the purchase of 251 Bcfe of reserves in eight major fields. These properties are located in East
Texas and northwestern Louisiana and produce primarily from the Rodessa, Travis Peak, Cotton Valley sandstone, Bossier sandstone and Cotton Valley
limestone formations between 7,000 feet and 13,000 feet. During 2004, we increased our position in the Eastern Region with the purchase of 102 Bcfe of proved
reserves in Franklin, Freestone, Limestone and Anderson counties of Texas and Claiborne Parish of Louisiana. Development in the East Texas area has more
than doubled reserves since we began operations, and we now have an interest in more than 375,000 gross (258,000 net) acres and a current development
inventory of 1,450 to 1,700 wells. We own an interest in 1,935 gross (1,726.5 net) wells that we operate and 447 gross (72.1 net) wells operated by others. We
also own the related gathering facilities. In 2004, we expanded our gathering system to more than 600 miles and our treating capacity to more than 700,000 Mcf
per day.
Freestone Trend
The Freestone Trend area is located in the western shelf of the East Texas Basin in Freestone, Robertson, Limestone and Leon counties. This area includes
the Freestone, Bald Prairie, Bear Grass, Oaks, Teague, Farrar, Dew and Luna fields and was our most active gas development area in 2004, where 185 gross
(166.1 net) gas wells were
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drilled and 14 workovers were performed. In 2004, we increased our acreage position to 225,000 gross (166,500 net) acres in this area and have a development
inventory of 1,100 to 1,300 wells. Initial development was concentrated in the Travis Peak formation, but is now focused on multi-pay development of the deeper
horizons, including the Cotton Valley and Bossier sandstones and Cotton Valley limestone. We plan to continue our expansion efforts in this area by drilling
approximately 175 wells and performing about 26 workovers in 2005. In 2002, we completed a 27-mile pipeline system that connects the major fields and allows
multiple exit points for marketing. During 2004, we continued expansion of the pipeline and gathering systems with the completion of an amine plant and a sour
treating facility. We plan to complete an additional sour treating facility during the first half of 2005. These improvements have increased our pipeline capacity to
over 700,000 Mcf per day. We will continue to construct and operate infrastructure or contract additional pipeline capacity to support our drilling activity.
Other Eastern Region Fields
Other fields in the Eastern Region include the Opelika, Willow Springs, Whelan, Oak Hill and Carthage fields in the East Texas area and the Middlefork,
Oaks/Colquitt, Cotton Valley and Logansport fields in northwestern Louisiana. With our 2004 acquisitions, we increased our position in these areas, which
provides opportunities for field extensions and infill drilling. In 2004, we drilled 37 gross (27.0 net) wells and performed 22 workovers in the other Eastern
Region fields. In 2005, we plan to drill ten wells in the Carthage area, 27 wells in northwestern Louisiana and 25 wells in various fields and perform 28
workovers and recompletions. As a part of our 2002 acquisition from Marathon, we acquired an interest in a Cotton Valley gas plant that we now operate. This
plant processes approximately 38,000 Mcf of gas per day and extracts 1,825 Bbls of natural gas liquids per day, primarily from the surrounding operated wells.
North Texas Region
Barnett Shale
The Barnett Shale is the largest natural gas field in Texas and covers 15 counties. Our operations in the Barnett Shale began in January 2004 with the
acquisition of 118 Bcfe of reserves. We have continued to expand our acreage positions and, by year end, had leased more than 80,000 net acres and identified
250 to 300 potential drilling locations. We drilled 20 gross (18.4 net) wells in 2004, ten of which were horizontal wells. In January 2005, we announced the
acquisition of Antero Resources Corporation, including 440 Bcfe of proved reserves and a gas gathering system. This acquisition will make us the second largest
producer in the Barnett Shale and will increase our net acreage holdings to 148,000 acres. We plan to drill 120 to 130 Barnett Shale wells in 2005.
San Juan Basin and Rocky Mountain Area
Our San Juan Basin and Rocky Mountain Area includes properties in the San Juan and Raton basins of New Mexico and Colorado, as well as properties in
the Powder River Basin of Wyoming and the Uinta Basin of Utah. We have now identified 575 to 775 potential drilling locations to develop these complex,
multi-pay basins where we own an interest in 1,892 gross (1,625.2 net) operated wells and 2,337 gross (286.4 net) wells operated by others.
San Juan Basin
The San Juan Basin of northwestern New Mexico and southwestern Colorado contains the largest deposit of natural gas reserves in North America. Our
San Juan Basin drilling has focused on the Fruitland Coal formation at shallow intervals of 3,000 feet or less and the Mesaverde and Dakota formations at depths
of 3,000 to 7,500 feet. We own an interest in 1,194 gross (990.0 net) wells that we operate and 2,288 gross (279.8 net) wells operated by others. In 2004, we
participated in the drilling of 102 gross (71.8 net) wells and completed 177 workovers. During 2005, we plan to drill up to 75 wells and perform approximately
200 workovers and recompletions, including installation of as many as 70 wellhead compressors and 130 pumping units.
Raton Basin
In 2003, we acquired natural gas and coal bed methane properties in the Raton Basin of Colorado. The Raton Basin is characterized by shallow prolific
coal bed methane production, low development cost, available gas market access points and significant development opportunities. Producing formations include
the Raton Coals at depths of 500
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to 1,800 feet and the Vermejo Coals at depths of 800 to 2,500 feet. We own an interest in 238 gross (237.9 net) wells that we operate. We drilled 38 gross (38.0
net) wells and performed ten workovers in this area in 2004 and plan to drill 20 wells and perform 30 workovers in 2005.
Rocky Mountains
Hartzog Draw Unit. During 2004, we acquired a 78.6% working interest in this 35,000 acre unit in northeastern Wyoming from ExxonMobil. We have
initiated a program to optimize secondary recovery operations and drill additional wells. In the Powder River Basin, coal bed methane development from the
shallow Fort Union coal bed zones (Big George), delineated under 12,500 net acres, offers immediate opportunities for new production and reserves. We drilled
31 gross (10.0 net) wells in 2004. We plan to drill approximately 25 to 50 wells and perform 67 workovers in this area in 2005.
Uinta Basin. During 2004, as a part of our ChevronTexaco acquisition, we expanded our coal bed methane operations with the purchase of 67 Bcfe of
proved reserves in the Buzzard Bench Field of Emery County, Utah. This property in the Ferron sand and coal play is an offset to the Drunkard’s Wash Field. We
have identified 100 to 150 potential well locations in this area where we own an interest in 93 gross (70.3 net) operated wells and 5 gross (1.3 net) wells operated
by others. We drilled three gross (2.5 net) wells in 2004 and plan to drill 15 wells in 2005.
Permian Basin and South Texas Region
Permian Basin
During 2004, we acquired approximately 80 million BOE of proved reserves in 16 counties in the Permian Basin of West Texas and New Mexico from
ChevronTexaco. Primary producing fields in the area include Yates, Goldsmith, Eunice Monument, Fullerton and Puckett. We have a development inventory of
between 475 and 575 potential well locations where we plan to use our secondary recovery expertise to enhance operations and expand development
opportunities. We also purchased from ExxonMobil operated interests in the Wasson, Russell, Champmon and Bruce fields and nonoperated working interests in
the Flanagan and Wasson fields.
Yates Field. The Yates Field, discovered in 1926, is located in southeastern Pecos County, Texas. We own nonoperated interests in 442 gross (127.8 net)
wells, and most production is from the San Andres formation. Results have been improved using carbon dioxide injection and horizontal sidetrack wells. In 2005,
the operator plans to drill approximately 110 horizontal sidetrack wells.
Goldsmith Field. The Goldsmith Field, located in Ector County, Texas, is a multi-pay zone field including production from the San Andres, Upper and
Lower Clearfork, Devonian and Ellenburger formations at depths ranging from 4,000 to 9,000 feet. The field consists of multiple waterflood units in the
Clearfork formation and adjacent units are currently being developed on 10 to 20-acre spacing. We plan to drill 17 wells and perform 30 workovers in this area in
2005.
Russell Field. As a result of acquiring additional working interests from ExxonMobil in 2004, we now have a working interest in excess of 97% in most of
our Russell Field wells. Producing formations include the Devonian and Clearfork, as well as exploration potential in the Ellenburger and Granite Wash
formations. We drilled seven gross (6.8 net) wells in 2004 and began a 3-D seismic study in February 2005. We plan to drill approximately 21 wells and perform
30 workovers in this area in 2005.
University Block 9 Field. The University Block 9 Field is in Andrews County, Texas. We own interests in 81 gross (77.3 net) operated wells. Productive
zones include the Wolfcamp, Pennsylvanian and Devonian. Development potential includes proper wellbore utilization, recompletions, infill drilling and
waterflood improvement. We drilled four gross (4.0 net) wells in 2004 and performed four workovers. During 2005, we plan to drill up to 13 wells.
Prentice Field. The Prentice Field is in Terry and Yoakum counties, Texas, and produces from the Clearfork and Glorieta formations. This field has been
separated into several waterflood units for secondary recovery operations. Development potential exists through infill drilling and waterflood improvement. We
operate the Prentice Northeast Unit, where we have a 91.6% working interest in 216 wells. We also own interests in 71 gross (2.9 net) nonoperated wells. During
2004, we continued our 10-acre development program by drilling nine gross (8.2 net) vertical wells and
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performing two workovers. We plan to continue our expansion of the potential infill area by drilling as many as ten wells in 2005.
Wasson Field. The Wasson Field is in Gaines and Yoakum counties, Texas and produces from the San Andres formation. We acquired the Mahoney lease
in 2004 from ExxonMobil and became operator. This property is being carbon dioxide flooded and recent development has included fracturing and restimulation.
The Cornell Unit has development potential that exists through infill drilling and waterflood improvement. We increased our working interest in this unit to
99.8% in 2004 as a result of the ExxonMobil acquisition. In 2004, we drilled three gross (2.1 net) 10-acre infill oil wells and three gross (2.1 net) gas cap wells in
the Cornell Unit, and in 2005 we plan to drill 15 oil wells and two gas cap wells.
South Texas Region
We acquired 54 Bcfe of proved reserves in nine South Texas counties as a part of our 2004 ChevronTexaco acquisition. The Fashing Field, located in
Atascosa County, primarily produces from the Edwards Limestone reservoir at depths ranging from approximately 10,000 to 11,000 feet. We have identified 20
to 40 potential well locations in this region and plan to drill six wells in 2005.
Arkoma Basin and Mid-Continent Region
The Arkoma Basin extends from central Arkansas into southeastern Oklahoma and is known for low production decline rates, multiple formations and
complex geology. We control 40% of Arkansas production from the Arkoma Basin and are the largest natural gas producer in the state with over 600,000 gross
acres of leasehold. With the addition of our leasehold acreage in eastern Oklahoma, we have interests in approximately 800,000 gross acres in the Arkoma Basin.
We own an interest in 1,261 gross (895.9 net) wells which we operate and 982 gross (169.5 net) wells operated by others. Our fault-block analysis technique has
identified trapped hydrocarbons in offsetting and new reservoirs across the basin. During 2004, we drilled 98 gross (51.7 net) wells and completed 43 workovers,
17 of which were stimulation/recompletions and four of which were wellhead compressor installations. We plan to drill approximately 56 wells and perform up
to 55 workovers in 2005.
Hugoton Royalty Trust
A substantial portion of properties in western Oklahoma, the Hugoton area and the Green River Basin of the Rocky Mountains are subject to an 80% net
profits interest conveyed to the Hugoton Royalty Trust as of December 1998. We sold 45.7% of our Hugoton Royalty Trust units in 1999 and 2000.
Western Oklahoma
We are one of the largest producers in the Major and Woodward counties, Oklahoma area of the Anadarko Basin. We operate 575 gross (489.6 net) wells
and have an interest in 139 gross (36.6 net) wells operated by others. Development in Major County focuses on mechanical improvements, restimulations and
recompletions to shallower zones and development drilling. During 2004, we participated in the drilling of 12 gross (8.6 net) wells in the northwestern portion of
the county, targeting the Mississippian and Chester formations, and performed eight workovers. We plan to drill eight wells and perform ten workovers in Major
County during 2005. We also drilled 12 gross (9.5 net) Chester formation wells in Woodward County. In 2005, we plan to drill up to ten wells and to perform as
many as five workovers.
We operate a gathering system and pipeline in the Major County area. The system collects gas from over 400 wells through 300 miles of pipeline. Current
throughput is approximately 15,000 Mcf per day, 70% of which is produced from Company-operated wells. Gas is processed at a third party plant and then
transmitted to an interstate pipeline.
Hugoton Area
The Hugoton Field covers parts of Texas, Oklahoma and Kansas and is one of the largest domestic gas fields with an estimated five million productive
acres. We own an interest in 373 gross (350.5 net) operated wells and 78 gross (18.9 net) wells operated by others. During 2004, we continued our restimulation
program in the Chase intervals with 33 restimulations. We plan to drill as many as seven wells and perform 50 Chase restimulations during 2005.
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Approximately 75% of our Hugoton gas production is delivered to the Tyrone Plant, an operated gas processing plant. Improvements in the Hugoton area
have included the acquisition of low pressure gathering lines and installation of lateral compressors that lowered the line pressure and increased production.
Green River Basin
The Green River Basin is located in southwestern Wyoming. We have interests in 195 gross (193.5 net) operated wells and 34 gross (4.3 net) wells
operated by others in the Fontenelle Field area. Gas production is from the Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet.
Development potential for this area includes deepening and opening new producing zones in existing wells, drilling new wells and adding compression to lower
line pressures. During 2004, we drilled seven gross (7.0 net) wells and performed 13 workovers. During 2005, we plan to perform seven workovers and drill up
to ten wells in the Green River Basin.
Alaska Cook Inlet
We own a 100% working interest in two State of Alaska leases and offshore installations in the Middle Ground Shoal Field of the Cook Inlet. The
properties include 27 wells, two platforms set in 70 feet of water about seven miles offshore, and a 50% interest in operated production pipelines and onshore
processing facilities. The field has produced more than 130 million Bbls and is separated into East and West flanks by a crestal fault. Waterflooding of the East
Flank has been successful, but the West Flank has not been fully developed or efficiently waterflooded. Production is from multiple zones within the Tyonek
formation. We drilled two sidetrack wells in 2004 and plan to drill one East Flank well and one West Flank well in 2005.
Reserves
The following terms are used in our disclosures of oil and natural gas reserves. For the complete detailed definitions of proved, proved developed and
proved undeveloped oil and gas reserves applicable to oil and gas registrants, reference is made to Rule 4-10(a)(2)(3)(4) of Regulation S-X of the Securities and
Exchange Commission, available at its web site http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Proved reserves - Estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geologic and engineering data, appear with
reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.
Proved developed reserves - Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating
methods.
Proved undeveloped reserves - Proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required.
Estimated future net revenues - Also referred to herein as “estimated future net cash flows.” Computational result of applying current prices of oil and gas
(with consideration of price changes only to the extent provided by existing contractual arrangements, other than hedge derivatives) to estimated future
production from proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be
incurred in developing and producing the proved reserves.
Present value of estimated future net cash flows - The computational result of discounting estimated future net revenues at a rate of 10% annually. The
present value of estimated future net cash flows after income tax is also referred to herein as “standardized measure of discounted future net cash flows” or
“standardized measure.”
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The following are estimated quantities of proved reserves and related cash flows as of December 31, 2004, 2003 and 2002:
December 31
2004
2003
2002
(in thousands)
Proved developed:
Gas (Mcf)
Natural gas liquids (Bbls)
Oil (Bbls)
Mcfe
Proved undeveloped:
Gas (Mcf)
Oil (Bbls)
Mcfe
Total proved:
Gas (Mcf)
Oil (Bbls)
Mcfe
Estimated future net cash flows:
Before income tax
After income tax
Present value of estimated future net cash flows, discounted at 10%:
Before income tax
After income tax
3,252,711
30,019
134,382
4,239,117
2,651,259
28,187
47,882
3,107,673
2,042,661
19,367
47,178
2,441,931
1,461,792
8,437
18,124
1,621,158
992,980
6,491
7,549
1,077,220
838,520
6,066
9,171
929,942
4,714,503
38,456
152,506
5,860,275
3,644,239
34,678
55,431
4,184,893
2,881,181
25,433
56,349
3,371,873
$ 23,605,059
$ 16,238,874
$ 16,700,605
$ 11,558,304
$ 10,165,876
$ 7,148,542
$ 12,237,044
$ 8,402,443
$ 8,607,001
$ 5,989,685
$ 5,281,077
$ 3,756,442
Miller and Lents, Ltd., an independent petroleum engineering firm, prepared the estimates of our proved reserves and the future net cash flows (and related
present value) attributable to proved reserves at December 31, 2004, 2003 and 2002. As prescribed by the Securities and Exchange Commission, such proved
reserves were estimated using oil and gas prices and production and development costs as of December 31 of each such year, without escalation. None of our
natural gas liquid proved reserves are attributable to gas plant ownership. Year-end 2004 average realized prices used in the estimation of proved reserves were
$5.69 per Mcf for gas, $28.24 per Bbl for natural gas liquids and $41.03 per Bbl for oil. See Note 15 to Consolidated Financial Statements for additional
information regarding estimated proved reserves.
In our prior reports, the estimated future net cash flows from proved reserves and related present value amounts were reported before reduction for
estimated operated overhead expense. Operated overhead is a component of production expense in the consolidated income statements and is an allocation from
general and administrative expense of the costs estimated to support the production function. As part of its periodic review of our filings, the staff of the
Securities and Exchange Commission concluded that production expense components for proved reserve disclosures should be consistent with components of
production expense recorded in the financial statements. Accordingly, we have restated estimated future net cash flows and the related present value amounts for
all years presented, resulting in a reduction to these amounts of approximately 2% at December 31, 2003 and 3% at December 31, 2002.
Estimated future net cash flows, and the related 10% discounted present value, of year-end 2004 proved reserves are significantly higher than at year-end
2003 because of increased reserves related to acquisitions and development and higher oil and natural gas liquids prices used in the estimation of year-end proved
reserves. Year-end 2003 product prices were $5.71 per Mcf for gas, $23.17 per Bbl for natural gas liquids and $30.55 per Bbl for oil.
Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective
process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function
of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition,
physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as
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well as economic factors such as change in product prices, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will
vary from reserve estimates.
During 2004, we filed estimates of oil and gas reserves as of December 31, 2003 with the U.S. Department of Energy on Form EIA-23 and Form EIA-28.
These estimates are consistent with the reserve data reported for the year ended December 31, 2003 in Note 15 to Consolidated Financial Statements, with the
exception that Form EIA-23 includes only reserves from properties that we operate.
Exploration and Production Data
For the following data, “gross” refers to the total wells or acres in which we own a working interest and “net” refers to gross wells or acres multiplied by
the percentage working interest owned by us. Although many wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the
ratio of oil to gas production.
Producing Wells
The following table summarizes producing wells as of December 31, 2004, all of which are located in the United States:
Operated Wells
Nonoperated Wells
Gross
Net
Gross
Gas
Oil
6,683.5
2,027.5
5,667.9
1,643.5
4,308.5
5,084.5
Total
8,711.0
7,311.4
9,393.0
(a)
Total (a)
Net
Gross
Net
669.8
474.6
10,992.0
7,112.0
6,337.7
2,118.1
1,144.4
18,104.0
8,455.8
672.0 gross (378.5 net) gas wells and 9.0 gross (5.5 net) oil wells are dual completions.
Drilling Activity
The following table summarizes the number of wells drilled during the years indicated. As of December 31, 2004, we were in the process of drilling 284
gross (121.2 net) wells.
Year Ended December 31
2004
Gross
Development wells:
Completed asGas wells
Oil wells
Non-productive
Total
Exploratory wells:
Completed asGas wells
Oil wells
Non-productive
Total
Total (a)
(a)
2003
Net
Gross
2002
Net
Gross
Net
584
33
27
372.0
23.9
12.4
390
42
7
289.5
30.0
3.0
303
27
13
227.2
15.5
5.9
644
408.3
439
322.5
343
248.6
1
2
1.0
0.4
—
12
—
—
10.2
—
—
—
—
3
—
—
1.5
3
1.4
12
10.2
3
1.5
647
409.7
451
332.7
346
250.1
—
Included in totals are 212 gross (27.3 net) wells in 2004, 102 gross (17.66 net) wells in 2003 and 75 gross (11.2 net) wells in 2002, drilled on nonoperated
interests.
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Acreage
The following table summarizes developed and undeveloped leasehold acreage in which we own a working interest as of December 31, 2004. Acreage
related to royalty, overriding royalty and other similar interests is excluded from this summary.
Developed Acres (a)(b)
Gross
Texas
Oklahoma
Arkansas
New Mexico
Kansas
Louisiana
Colorado
Wyoming
Utah
Other
Total
Net
Undeveloped Acres
Gross
Net
811,785
546,238
577,937
450,044
211,253
114,659
107,900
72,442
66,939
362,354
575,617 152,209
381,312 16,946
306,590 30,507
284,802 33,395
167,245
—
61,215
160
83,875
—
55,506 53,963
42,546
—
9,608
—
117,173
8,158
22,299
27,825
—
160
—
51,246
—
—
3,321,551
1,968,316 287,180
226,861
(a)
Developed acres are acres spaced or assignable to productive wells.
(b)
Certain acreage in Oklahoma and Texas is subject to a 75% net profits interest conveyed to the Cross Timbers Royalty Trust, and in Oklahoma, Kansas
and Wyoming is subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust.
Oil and Gas Sales Prices and Production Costs
The following table shows the average sales prices per unit of production and the production expense and taxes, transportation and other expense per Mcfe
for quantities produced for the indicated period:
2004
2003
2002
Sales prices:
Gas (per Mcf)
Natural gas liquids (per Bbl)
Oil (per Bbl)
$ 5.04
$ 26.44
$ 38.38
$ 4.07
$ 19.99
$ 28.59
$ 3.49
$ 14.31
$ 24.24
Production expense per Mcfe
Production and property taxes per Mcfe
Transportation and other expense per Mcfe
$ 0.66
$ 0.30
$ 0.17
$ 0.58
$ 0.21
$ 0.16
$ 0.57
$ 0.15
$ 0.10
Delivery Commitments
Under a production payment sold in 1998, we have committed to deliver 16.0 Bcf (13.0 Bcf net to our interest) beginning approximately September 2006.
Delivery of the committed volumes is in East Texas. See Note 8 to Consolidated Financial Statements. The Company’s production and reserves are adequate to
meet this delivery commitment.
Competition and Markets
We compete with other oil and gas companies in all aspects of our business, including acquisition of producing properties and oil and gas leases,
marketing of oil and gas, and obtaining goods, services and labor. Some of our competitors have substantially larger financial and other resources. Factors that
affect our ability to acquire producing properties include available funds, available information about the property and our standards established for minimum
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projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for
natural gas delivery is presented by other pipelines and gathering systems. Competition is also presented by alternative fuel sources, including heating oil,
imported liquified natural gas and other fossil fuels. Because of the long-lived, high margin nature of our oil and gas reserves and management’s experience and
expertise in exploiting these reserves, management believes that it effectively competes in the market.
Our ability to market oil and gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the
proximity of our gas production to pipelines, the available capacity in such pipelines, the demand for oil and gas, and the effects of weather and state and federal
regulation. We cannot assure that we will always be able to market all of our production at favorable prices. We do not currently believe that the loss of any of
our oil or gas purchasers would have a material adverse effect on our operations.
Decreases in oil and gas prices have had and could have in the future an adverse effect on our acquisition and development programs, proved reserves,
revenues, profitability, cash flow and dividends. See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations,
“Significant Events, Transactions and Conditions - Product Prices.”
Federal and State Regulations
There are numerous federal and state laws and regulations governing the oil and gas industry that are often changed in response to the current political or
economic environment. Compliance with this regulatory burden is often difficult and costly and may carry substantial penalties for noncompliance. The
following are some specific regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.
Federal Energy Bill
After failing to pass legislation in 2003 and 2004, Congress is currently considering a new energy bill. The potential effect of this legislation is unknown,
but it may include certain tax incentives for oil and gas producers and changes in the federal regulatory framework.
Federal Regulation of Natural Gas
The interstate transportation and certain sales for resale of natural gas, including transportation rates charged and various other matters, is subject to federal
regulation by the Federal Energy Regulatory Commission. Federal wellhead price controls on all domestic gas were terminated on January 1, 1993, and none of
our gathering systems are currently subject to FERC regulation. We cannot predict the impact of future government regulation on any natural gas facilities.
Although FERC’s regulations should generally facilitate the transportation of gas produced from our properties and the direct access to end-user markets,
the future impact of these regulations on marketing our production or on our gas transportation business cannot be predicted. We, however, do not believe that
we will be affected differently than competing producers and marketers.
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of
these products is affected by market transportation costs. A significant part of our oil production is transported by pipeline. Under rules adopted by FERC
effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances.
These rules have had little effect on our oil transportation cost.
State Regulation
Oil and gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the
method of developing new fields, the spacing and operations of wells and waste prevention. The production rate may be regulated and the maximum daily
production allowable from oil and gas
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wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled.
We may become a party to agreements relating to the construction or operations of pipeline systems for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the state’s administrative
authority charged with regulating pipelines. The rates that can be charged for gas, the transportation of gas, and the construction and operation of such pipelines
would be subject to the regulations governing such matters. Certain states have recently adopted regulations with respect to gathering systems, and other states
are considering similar regulations. New regulations have not had a material effect on the operations of our gathering systems, but we cannot predict whether any
further rules will be adopted or, if adopted, the effect these rules may have on our gathering systems.
Federal, State or Native American Leases
Our operations on federal, state or Native American oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such
operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management,
Minerals Management Service and other agencies.
Environmental Regulations
Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment,
directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and
regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters of the United States, underground injection of waste
water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and
regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or
cessation of operations in affected areas. To date, we have not expended any material amounts to comply with such regulations, and management does not
currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.
We are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We
routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant
adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made, and will continue to make,
expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing
operations and not an extraordinary cost of compliance with government regulations.
Employees
We had 1,356 employees as of December 31, 2004. We consider our relations with our employees to be good.
Executive Officers of the Company
The executive officers of the Company are elected by and serve until their successors are elected by the Board of Directors.
Bob R. Simpson, 56, was a co-founder of the Company with Mr. Palko and has been Chairman and Chief Executive Officer since July 1, 1996. Prior
thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer or held similar positions with the Company since 1986. Mr. Simpson was Vice
President of Finance and Corporate Development (1979-1986) and Tax Manager (1976-1979) of Southland Royalty Company.
Steffen E. Palko, 54, was a co-founder of the Company with Mr. Simpson and has been Vice Chairman and President or held similar positions since 1986.
Mr. Palko was Vice President - Reservoir Engineering (1984-1986) and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.
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Louis G. Baldwin, 55, has been Executive Vice President and Chief Financial Officer or held similar positions with the Company since 1986. Mr.
Baldwin was Assistant Treasurer (1979-1986) and Financial Analyst (1976-1979) at Southland Royalty Company.
Keith A. Hutton, 46, has been Executive Vice President - Operations or held similar positions with the Company since 1987. From 1982 to 1987, Mr.
Hutton was a Reservoir Engineer with Sun Exploration & Production Company.
Vaughn O. Vennerberg II, 50, has been Executive Vice President - Administration or held similar positions with the Company since 1987. Prior to that
time, Mr. Vennerberg was employed by Cotton Petroleum Corporation and Texaco Inc. (1979-1986).
Bennie G. Kniffen, 54, has been Senior Vice President and Controller or held similar positions with the Company since 1986. From 1976 to 1986, Mr.
Kniffen held the position of Director of Auditing or similar positions with Southland Royalty Company.
Item 3.
LEGAL PROCEEDINGS
On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U.S. District
Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against
the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by
Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly
valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses),
civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring
practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States
District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision
was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional
prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending
that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion has been scheduled for March 2005. While we
are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any
potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.
In June 2001, we were served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. (formerly Quinque case). The action was filed in the District Court
of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors
of natural gas. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and
royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974.
The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the
federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and
heating content of natural gas delivered into their pipelines, resulting in underpayments to the plaintiffs. The plaintiffs assert a breach of contract claim, negligent
or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of
action. The amount of damages was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the suit and
another subsidiary of the Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs’ counsel
has filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only,
conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in
April 2005 to determine whether the amended class should be certified. While we are unable to predict the outcome of this case, we believe that the allegations of
this lawsuit are without merit and intend to vigorously
16
Table of Contents
defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.
On August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al.
The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. The plaintiffs seek to represent a class of
plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January
1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content that had previously been alleged in the Price case discussed
above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the
amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies to gas
measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified.
The amount of damages was not specified in the complaint. While we are unable to predict the outcome of this case, we believe that the allegations of this
lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no
provision has been accrued in our financial statements.
In September 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District
Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs allege that the defendants have deducted in their calculation of royalty
payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable
location. The plaintiffs seek to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La
Plata County, Colorado and that are leased to or operated by Huber or us, except to the extent that the lessors or their successors have expressly authorized
deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002,
and have assumed the responsibility for certain liabilities of Huber prior to the effective date, which may include liability for post-production deductions made by
Huber. As of December 31, 2004, based on an evaluation of available information, we accrued a $3.1 million estimated liability for this claim in our consolidated
financial statements. On February 17, 2005, we agreed to a tentative settlement of approximately $5.1 million, resulting in an additional loss of approximately $2
million to be recorded in first quarter 2005.
In December 2004, the U.S. Environmental Protection Agency issued a Compliance Agreement and Final Order to us, which cited certain violations
concerning the discharge of produced water and sanitary wastes into Alaska’s Cook Inlet from our two operated production platforms from January 2000 through
June 2004. We reported these discharges to the EPA as part of our offshore discharge permit monitoring. We have agreed to pay a monetary penalty of $139,000
and have accrued this amount in our financial statements.
We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management and legal
counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on our financial position or
liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.
Item 4.
SUBMISSION
OF MATTERS
TO A VOTE
OF SECURITY HOLDERS
A Special Meeting of the Shareholders of the Company was held on November 16, 2004, to vote on the proposed 2004 Stock Incentive Plan. All common
shares in this Item 4 have been retroactively restated for the effect of the four-for-three stock split to be effected on March 15, 2005. A total of 268,690,021 of the
Company’s shares were present at the meeting in person or by proxy, which represented 77% of our outstanding shares as of September 30, 2004, the record date
for the Special Meeting.
Shareholders approved the 2004 Stock Incentive Plan, based on the following vote tabulation:
For
212,600,831
17
Against
Withheld
55,755,692
333,498
Table of Contents
PART II
Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES
OF EQUITY
SECURITIES
Our common stock is listed on the New York Stock Exchange and trades under the symbol “XTO.” The following table sets forth quarterly high and low
sales prices and cash dividends declared for each quarter of 2004 and 2003 (as adjusted for the four-for-three stock split to be effected on March 15, 2005, the
five-for-four stock split effected in March 2004, and the four-for-three stock split effected in March 2003):
Cash
High
Low
2004
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$ 19.512
22.875
24.833
27.660
$ 15.348
18.315
19.050
22.350
$
0.0075
0.0075
0.0375
0.0375
2003
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$ 11.916
13.494
12.852
17.580
$ 10.211
10.920
11.148
12.558
$
0.0060
0.0060
0.0060(a)
0.0060
(a)
Dividend
In September 2003, we distributed as a dividend to our shareholders all of the Cross Timbers Royalty Trust units owned by the Company. This dividend
was recorded at a market value of $28.2 million, or approximately $0.09 per common share.
The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on
our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters the Board
of Directors deems relevant.
On February 15, 2005, the Board of Directors declared a quarterly dividend of $0.05 per common share payable on April 15, 2005 to stockholders of
record on March 31, 2004. As a result of the four-for-three stock split to be effected on March 15, 2005, this represents a 33% increase in our dividend rate. On
February 23, 2005, we had 1,054 stockholders of record.
The following summarizes purchases of our common stock during fourth quarter 2004:
Month
Total Number
of Shares
Average Price
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
Purchased
Paid per Share
or Programs (b)
October
November
December
—
696(a)
33,600
$
—
$ 27.26
$ 24.18
—
—
33,600
Total
34,296
$ 24.24
33,600
Maximum Number
of Shares that May
Yet Be Purchased
Under the Plans or
Programs (b)
19,966,400
(a)
During the quarter ended December 31, 2004, the Company purchased shares of common stock as treasury shares to pay income tax withholding
obligations in conjunction with vesting of performance shares under the 1998 Stock Incentive Plan. These share purchases were not part of a publicly
announced program to purchase common shares.
(b)
The Company has a repurchase program approved by the Board of Directors for the repurchase of up to 20,000,000 shares of the Company’s common
stock. The repurchase program was announced on August 18, 2004.
18
Table of Contents
Item 6.
SELECTED FINANCIAL DATA
The following table shows selected financial information for each of the years in the five-year period ended December 31, 2004. Significant producing
property acquisitions in each of the years presented, other than 2000, affect the comparability of year-to-year financial and operating data. See Items 1 and 2,
Business and Properties, “Acquisitions.” All weighted average shares and per share data have been adjusted for the four-for-three stock split to be effected on
March 15, 2005, the five-for-four stock split effected in March 2004, the four-for-three stock split effected in March 2003 and the three-for-two stock splits
effected in June 2001 and September 2000. This information should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations and the Consolidated Financial Statements at Item 15(a).
2004
2003
2002
2001
2000
$ 1,613,135
318,800
18,380
(2,714)
$ 1,040,370
135,058
12,982
1,145
$
681,147
115,324
11,622
2,070
$
710,348
116,939
12,832
(1,371)
$
456,814
128,194
16,123
(280)
$ 1,947,601
$ 1,189,555
$
810,163
$
838,748
$
600,851
Earnings available to common stock
$
507,882(a)
$
288,279(b)
$
186,059(c)
$
248,816(d)
$
115,235(e)
Per common share:
Basic
$
1.53
$
0.96(f)
$
0.67
$
0.91(g)
$
0.49
Diluted
$
1.51
$
0.95(f)
$
0.66
$
0.90(g)
$
0.46
(in thousands except production, per share and per unit data)
Consolidated Income Statement Data
Revenues:
Gas and natural gas liquids
Oil and condensate
Gas gathering, processing and marketing
Other
Total Revenues
Weighted average common shares outstanding
Cash dividends declared per common share
332,907
$
299,665
0.0900
$
0.0240(h)
277,834
$
0.0180
272,234
$
0.0165
237,179
$
0.0100
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities
Investing activities
Financing activities
$ 1,216,892
$ (2,518,261)
$ 1,304,074
$ 794,181
$ (1,135,234)
$ 333,094
$ 490,842
$ (736,817)
$ 254,119
$ 542,615
$ (610,923)
$
67,680
$ 377,421
$ (133,884)
$ (241,833)
Consolidated Balance Sheet Data
Property and equipment, net
Total assets
Long-term debt
Stockholders’ equity
$
$
$
$
$
$
$
$
3,312,067
3,611,134
1,252,000
1,465,642
$ 2,370,965
$ 2,648,193
$ 1,118,170
$ 907,786
$ 1,841,387
$ 2,132,327
$ 856,000
$ 821,050
$ 1,357,374
$ 1,591,904
$ 769,000
$ 497,367
668,436
6,463
12,943
784,877
513,925
5,068
13,033
622,532
416,927
4,385
13,637
525,062
343,871
4,430
12,941
448,098
Operating Data
Average daily production:
Gas (Mcf)
Oil (Bbls)
Mcfe
5,624,378
6,110,372
2,042,732
2,599,373
834,572
7,484
22,696
1,015,654
Average sales price:
Gas (per Mcf)
Natural gas liquids (per Bbl)
Oil (per Bbl)
$
$
$
5.04
26.44
38.38
$
$
$
4.07
19.99
28.59
$
$
$
3.49
14.31
24.24
$
$
$
4.51
15.41
23.49
$
$
$
3.38
19.61
27.07
Production expense (per Mcfe)
Taxes, transportation and other expense (per Mcfe)
$
$
0.66
0.47
$
$
0.58
0.37
$
$
0.57
0.25
$
$
0.57
0.33
$
$
0.53
0.35
Proved reserves:
Gas (Mcf)
Oil (Bbls)
Mcfe
Other Data
Ratio of earnings to fixed charges (i)
4,714,503
38,456
152,506
5,860,275
3,644,239
34,678
55,431
4,184,893
2,881,181
25,433
56,349
3,371,873
2,235,478
20,299
54,049
2,681,566
1,769,683
22,012
58,445
2,252,425
8.9
6.9
5.6
7.7
2.8
19
Table of Contents
(a)
Includes pre-tax effects of a derivative fair value loss of $11.9 million, stock-based incentive compensation of $89.5 million and special bonuses totaling
$11.7 million related to the ChevronTexaco and ExxonMobil acquisitions. Stock-based incentive compensation includes cash compensation of $22.3
million related to cash-equivalent performance shares.
(b)
Includes pre-tax effects of a derivative fair value loss of $10.2 million, a non-cash contingency gain of $1.7 million, non-cash incentive compensation of
$53.1 million, a $9.6 million loss on extinguishment of debt, a $16.2 million non-cash gain on the distribution of Cross Timbers Royalty Trust units, and a
$1.8 million after-tax gain on adoption of the new accounting standard for asset retirement obligation.
(c)
Includes pre-tax effects of a derivative fair value gain of $2.6 million, gain on settlement with Enron Corporation of $2.1 million, non-cash incentive
compensation of $27 million and an $8.5 million loss on extinguishment of debt.
(d)
Includes pre-tax effects of a derivative fair value gain of $54.4 million and non-cash incentive compensation of $9.6 million, and an after-tax charge of
$44.6 million for the cumulative effect of accounting change.
(e)
Includes pre-tax effects of a derivative fair value loss of $55.8 million, a gain of $43.2 million on significant asset sales, and non-cash incentive
compensation expense of $26.1 million.
(f)
Before cumulative effect of accounting change, earnings per share were $0.95 basic and $0.94 diluted.
(g)
Before cumulative effect of accounting change, earnings per share were $1.08 basic and $1.06 diluted.
(h)
Excludes the September 2003 distribution of all of the Cross Timbers Royalty Trust units owned by the Company to its stockholders as a dividend with a
market value of approximately $0.09 per common share.
(i)
For purposes of calculating this ratio, earnings are before income tax and fixed charges. Fixed charges include interest costs and the portion of rentals
considered to be representative of the interest factor.
20
Table of Contents
Item 7.
MANAGEMENT’S DISCUSSION
AND ANALYSIS
OF FINANCIAL CONDITION
AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with Item 6, Selected Financial Data, and the Consolidated Financial Statements at
Item 15(a). Unless otherwise indicated, throughout this discussion the term “Mcfe” refers to thousands of cubic feet of gas equivalent quantities produced for the
indicated period, with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
Overview
Our business is to produce and sell natural gas, natural gas liquids and crude oil from our predominantly southwestern and central U.S. properties, most of
which we operate. Because we consider our gathering, processing and marketing as ancillary functions to our production of natural gas, natural gas liquids and
crude oil, we have determined that our business comprises only one industry segment.
In 2004, we achieved the following record financial and operating results:
•
Average daily gas production was 835,000 Mcf, a 25% increase from 2003, average daily oil production was 22,696 Bbls, a 75% increase from
2003, and average daily natural gas liquids production was 7,484 Bbls, a 16% increase from 2003.
•
Year-end proved reserves were 5.86 Tcfe, a 40% increase from year-end 2003.
•
Net income was $507.9 million, a 76% increase from 2003, and earnings per basic common share was $1.53, a 59% increase from 2003.
•
Cash flow from operating activities was $1.22 billion, a 53% increase from 2003.
•
Stockholders’ equity was $2.6 billion, a 77% increase from year-end 2003.
•
The debt-to-capitalization ratio improved to 44% at year-end from 46% at year-end 2003.
We achieve production and proved reserve growth primarily through producing property acquisitions, followed by low-risk development generally funded
by cash flow from operating activities. Funding sources for our acquisitions include proceeds from sales of public and private equity and debt, bank borrowings,
cash flow from operating activities, or a combination of these sources. Maintaining or improving our debt-to-capitalization ratio is a primary consideration in
selecting our method of acquisition financing.
During 2004, we acquired $1.9 billion of producing properties with proved reserves of 716.5 Bcf of natural gas, 2.9 million Bbls of natural gas liquids and
98.2 million Bbls of oil. In January 2005, we announced an agreement to acquire Antero Resources Corporation, a prominent producer in the Barnett Shale of
North Texas, for cash and equity consideration of approximately $685 million. The agreement was amended in February to include Antero’s gas gathering assets
and related bank debt of $175 million.
Our goal for 2005 is to increase production by 21% to 23%. To achieve future production and reserve growth, we will continue to pursue acquisitions that
meet our criteria, and to complete development projects included in our inventory of between 3,100 and 3,850 potential development drilling locations. Our 2005
development budget is $850 million. While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during
2005. We cannot ensure that we will be able to find properties that meet our acquisition criteria and that we can purchase such properties on acceptable terms.
21
Table of Contents
Sales prices for our natural gas and oil production are influenced by supply and demand conditions over which we have little or no control, including
weather and regional and global economic conditions. To provide predictable production growth, we hedge a portion of our production at prices that ensure
stable cash flow margins to fund our operating commitments and development program. As of February 25, 2005 we have hedged approximately 25% of our
2005 projected gas production at an average NYMEX price of $5.90 per Mcf and about 45% of our crude oil production at an average NYMEX price of $38.37
per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.
The combined effect of higher product prices, a 25% increase in gas production and a 75% increase in oil production resulted in a 64% increase in total
revenues to $1.95 billion in 2004 from $1.19 billion in 2003. On an Mcfe produced basis, total revenues were $5.24 in 2004, a 26% increase from $4.15 in 2003.
We analyze, on an Mcfe produced basis, expenses that generally trend changes in production:
Increase
Production
Taxes, transportation and other
Depreciation, depletion and amortization
Accretion of discount in asset retirement obligation
General and administrative, excluding stock-based incentive compensation
Interest
2004
2003
(Decrease)
$ 0.66
0.47
1.09
0.02
0.20
0.25
$ 0.58
0.37
0.99
0.02
0.19
0.22
14%
27%
10%
—
5%
14%
$ 2.69
$ 2.37
14%
Production expense rose 14% primarily because of the 75% increase in oil production, which is more expensive to produce than natural gas. Taxes,
transportation and other expense generally is based on product revenues, and the 27% increase in this expense per Mcfe is primarily caused by increased product
prices. The 10% increase in depreciation, depletion and amortization resulted from higher acquisition and development costs. The 5% increase in general and
administrative expense is because of increased personnel and other costs related to Company growth.
Significant expenses that generally do not trend with production include:
Stock-based incentive compensation. This is a component of general and administrative expense and primarily relates to the vesting of performance
shares when the common stock price reaches specified target levels. Incentive compensation was $89.5 million in 2004, a 69% increase from the
comparable 2003 expense of $53.1 million. Included in 2004 incentive compensation is $22.3 million of cash compensation related to vesting of
cash-equivalent performance shares. Otherwise, stock-based incentive compensation was non-cash. Increased incentive compensation is because of
the 56% increase in the common stock price during 2004 and the resulting increased value of vested awards. After adjusting for the effect of the
May 2004 and April 2003 common stock offerings, stock-based incentive compensation was approximately 3% of the increase in market
capitalization during each of 2004 and 2003. Including stock-based incentive compensation, general and administrative expense increased $57.4
million, or 53%.
Derivative fair value (gain) loss. This is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge
accounting treatment and fluctuates based on changes in the fair value of underlying commodities. Derivative fair value losses of $11.9 million in
2004 and $10.2 million in 2003 were primarily related to the ineffective portion of hedge derivatives caused by the effect of increasing oil and gas
prices on hedges in areas without basis or location differential contracts.
Our primary sources of liquidity are cash flow from operating activities, borrowings under our revolving credit facility with commercial banks and public
and private offerings of equity and debt. In January 2004, Standard & Poors upgraded our corporate credit rating to investment grade and all liens on producing
properties and other collateral were
22
Table of Contents
irrevocably released as security for our revolving credit agreement with commercial banks. As a result, Moody’s upgraded our existing senior notes to Ba1 from
Ba2 and confirmed our Ba1 senior implied rating. In March 2004, Moody’s upgraded our issuer rating and senior implied rating to Baa3.
In February 2004, we fully repaid our revolving credit agreement and entered a new five-year revolving credit agreement with commercial banks that
matures in February 2009. The agreement currently provides for a maximum commitment amount of $1 billion, and an interest rate based on the London
Interbank Offered Rate plus 1%. On December 31, 2004, borrowings under the revolving credit agreement with commercial banks were $146 million at a
weighted average interest rate of 3.49%, with unused borrowing capacity of $854 million. In November 2004, we borrowed $300 million under a five-year bank
term loan due April 2010 with an initial interest rate of LIBOR plus 0.75%. Other terms and conditions are substantially the same as our existing revolving credit
agreement.
Our consolidated financial position and results of operations are significantly affected by our critical accounting policies and estimates. We utilize the
successful efforts method of oil and gas accounting that requires expensing of unsuccessful exploratory well costs, as well as exploratory geological and
geophysical costs. All acquisition, development and successful exploratory well costs are generally capitalized and expensed through depreciation, depletion and
amortization, which is computed on the unit-of-production method. If conditions indicate our properties may be impaired, we estimate future net cash flows from
the applicable properties and compare this estimate to our total net cost of the properties. If the property cost cannot be recovered from the estimated future net
cash flows, we must write down the property cost to the discounted present value of such future net cash flows. To date, our impairment of producing properties
has been limited to a $2 million provision recorded in 1998. While we do not expect significant impairment provisions in the near future, any prolonged
significant decline in commodity prices could require an impairment adjustment to our property cost. The amounts we record for depreciation, depletion and
amortization and impairment are dependent upon our estimates of proved oil and gas reserves. Our proved reserve estimates are subject to potentially significant
revisions based on subsequent drilling results and production data, changes in prices and costs, as well as other factors.
Significant Events, Transactions and Conditions
The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended
December 31, 2004, 2003 and 2002 and may impact future operations and financial condition.
Acquisitions. We acquired producing and undeveloped properties at a total cost of $2.0 billion in 2004, $629.5 million in 2003 and $358.1 million in 2002, which
were funded by a combination of proceeds from sales of common stock and senior notes, bank borrowings and cash flow from operating activities. The following
are the significant acquisitions:
23
Table of Contents
Closing Date
2004
2003
2002
Seller
January
Multiple parties
February -April
Amount
(in millions)
$
Acquisition Area
243
East Texas and northwestern Louisiana
Multiple parties
223
Barnett Shale of North Texas and Arkoma Basin
May
ExxonMobil Corporation
336
Permian Basin of West Texas and Powder River Basin of Wyoming
August
ChevronTexaco Corporation
930
Eastern Region, Permian Basin, Mid-Continent, Rocky Mountains and
South Texas
May
Williams of Tulsa, Oklahoma
381
June
Markwest Hydrocarbon, Inc.
51
October
Multiple parties
100
East Texas, Arkansas and San Juan Basin of New Mexico
May
Marathon Oil Company
101
East Texas and Louisiana
July
Marathon Oil Company
43
December
J.M. Huber Corporation
154
Raton Basin of Colorado, Hugoton field of southwestern Kansas and San
Juan Basin of New Mexico and Colorado
San Juan Basin of New Mexico and Colorado
San Juan Basin of New Mexico
San Juan Basin of Colorado
five-year warrants to purchase another 2 million shares of our common stock at $27.00 per share. The purchase agreement was amended in February 2005 to
include Antero’s gas gathering assets and related bank debt of $175 million. The transaction is expected to close April 1, 2005. The booked acquisition cost will
include customary non-cash adjustments, including a step-up for deferred taxes. The cash consideration for the acquisition will be initially provided through cash
flow from operations and existing bank credit facilities.
2004, 2003 and 2002 Development and Exploration Programs. Gas development focused on the East Texas area and the Arkoma and San Juan basins during
2004, 2003 and 2002. Oil development was concentrated in Alaska and in the Permian Basin during all three years. Development costs totaled $572.1 million in
2004, $445.9 million in 2003 and $352.1 million in 2002. Exploration activity in 2004 was primarily geological and geophysical analysis, including seismic
studies, of undeveloped properties. Exploration activity in 2003 and 2002 consisted primarily of drilling successful wells in East Texas. Exploratory costs were
$15 million in 2004, $16.1 million in 2003 and $4.2 million in 2002. Our development and exploration activities are generally funded by cash flow from
operations.
2005 Acquisition, Development and Exploration Program. We have budgeted $850 million for our 2005 development and exploration program, which we expect
to fund by cash flow from operations. While an acquisition budget has not been formalized, we plan to continue to actively review additional acquisition
opportunities during 2005. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding
through our bank credit facilities, public or private issuance of debt or equity, or asset sales. The cost of 2005 property acquisitions may alter the amount
currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2005 to focus on
opportunities offering the highest rates of return.
24
Table of Contents
As of December 31, 2004, we have an inventory of between 3,100 and 3,850 potential drilling locations. We plan to drill about 735 (560 net) development
wells and perform approximately 540 (400 net) workovers and recompletions in 2005. Drilling plans are dependent upon product prices and the availability of
drilling equipment.
Product Prices. In addition to supply and demand, oil and gas prices are affected by seasonal, political and other conditions we generally cannot control or
predict.
Gas. Natural gas prices are dependent upon North American supply and demand, which is affected by weather and economic conditions. Natural gas
competes with alternative energy sources as a fuel for heating and the generation of electricity. The winter of 2001-2002 was one of the warmest on record,
resulting in higher than average gas storage levels and lower gas prices in 2002. Prices climbed in fourth quarter 2002 as a result of low levels of drilling activity,
increased industrial demand, colder weather and international instability. Colder than normal weather, record low gas storage levels and continued increasing
demand caused gas prices to remain relatively high during the first five months of 2003. With diminished demand related to higher prices, natural gas prices were
lower during the summer months, then rose with cooler weather in the fall and early winter. Forecasts for continued production declines, increasing natural gas
demand and larger than projected storage withdrawals supported higher prices in the first six months of 2004. Mild summer weather and increased gas storage
inventories led to declining gas prices in August and early September. Natural gas prices rose again in mid-September because of reduced gas production as a
result of hurricanes in the Gulf of Mexico. Gas prices remained relatively high for the remainder of 2004 because of sporadic colder weather and lower gas
supplies. With moderate temperatures and favorable supply, prices were lower in January 2005, but rose in February as a result of colder weather in the U.S.
Northeast and Europe. Prices will continue to be affected by weather, the recovery of the domestic economy, increases in the level of North American production
and import levels of liquified natural gas. In any case, management expects natural gas prices to remain volatile. As described under “Hedging Activities” below,
we use commodity price hedging instruments to reduce our exposure to gas price fluctuations. The following are comparative average gas prices for the last three
years:
2004
2003
2002
$ 6.14
$ 5.04
$ 5.56
$ 5.39
$ 4.07
$ 4.86
$ 3.22
$ 3.49
$ 2.98
(per Mcf)
Average NYMEX price
Average realized sales price
Average realized sales price excluding hedging
At February 25, 2005, the average NYMEX gas price for the following 12 months was $7.23 per MMBtu. As computed on an energy equivalent basis, our
proved reserves were 80% natural gas at December 31, 2004. After considering hedges in place as of February 25, 2005, we estimate that a $0.10 per Mcf
increase or decrease in the average gas sales price would result in approximately a $25 million change in 2005 annual operating cash flow before income taxes.
Oil. Crude oil prices are generally determined by global supply and demand. Oil prices declined in 2002 because of lagging demand caused by a global
recession. Rising uncertainties in the Middle East led to higher prices late in 2002. During 2003, unusually low storage levels, the war in Iraq and production
discipline by OPEC maintained oil prices at relatively high levels. Oil prices continued to increase in early 2004 because of increasing demand and low crude
stocks. Despite increased production by OPEC members, oil prices exceeded $55 per Bbl in October because of continued instability in the Middle East and
Nigeria and hurricanes in the Gulf of Mexico. With mild winter weather and an ample supply of oil stocks, prices declined in late 2004 but rebounded in January
and February 2005 following global supply outages, colder weather in the U.S. Northeast and Europe and continued disruptions of Iraqi exports. As described
under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to oil price fluctuations. The following are comparative
average oil prices for the last three years:
2004
2003
2002
(per Bbl)
Average NYMEX price
Average realized sales price
Average realized sales price excluding hedging
$ 41.38 $ 31.08 $ 26.10
$ 38.38 $ 28.59 $ 24.24
$ 40.24 $ 29.40 $ 24.52
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At February 25, 2005, the average NYMEX oil price for the following 12 months was $50.62 per Bbl. After considering hedges in place as of February 25,
2005, we estimate that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $6 million change in 2005 annual
operating cash flow before income taxes.
Hedging Activities. We enter futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts, to hedge our exposure to
product price volatility. Our policy is to routinely hedge a portion of our production. While there is a risk we may not be able to realize the full benefit of rising
prices, management plans to continue its hedging strategy because of the benefits of more predictable production growth and cash flows.
In 2004, all hedging activities decreased gas revenue by $156.1 million and decreased oil revenue by $15.5 million, while in 2003, all hedging activities
decreased gas revenue by $193 million and decreased oil revenue by $3.9 million, and in 2002, hedging activities increased gas revenue by $95.4 million and
decreased oil revenue by $1.3 million.
The following summarizes our January 2005 through December 2005 NYMEX hedging positions at February 25, 2005, excluding basis adjustments which
are separately hedged. Our average daily production was 915,905 Mcf of gas and 33,494 Bbls of oil in fourth quarter 2004. Prices to be realized for hedged
production will be less than these NYMEX prices because of location, quality and other adjustments. See Note 8 to the Consolidated Financial Statements.
Futures Contracts and Swap Agreements For January through December 2005 Production
Natural Gas
Crude Oil
Mcf per Day
Average
NYMEX Price
per Mcf
250,000
$
Bbl per Day
5.90
10,000
5,000
Average
NYMEX Price
per Bbl
$
$
35.91
43.28
Derivative Fair Value Gain/Loss. We record in our income statements realized and unrealized derivative fair value gains and losses related to derivatives that do
not qualify for hedge accounting, as well as the ineffective portion of hedge derivatives. We recorded an $11.9 million loss is 2004, a $10.2 million loss in 2003
and a $2.6 million gain in 2002 related to changes in fair value of these non-hedge derivatives. The 2004 loss includes a $12.5 million loss on the ineffective
portion of hedge derivatives, or approximately 8% of total hedge derivative losses, while the 2003 loss includes a $7.3 million loss on the ineffective portion of
hedge derivatives, or approximately 4% of total hedge derivative losses. Netted in the 2002 derivative fair value gain is a $2.9 million loss on the ineffective
portion of hedge derivatives, or approximately 2% of total hedge derivative losses. These ineffective hedge derivative losses are primarily because of increasing
oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.
Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other
comprehensive income (loss). At December 31, 2004, we have an unrealized pre-tax loss of $45.1 million in accumulated other comprehensive income (loss)
related to the fair value of derivatives designated as cash flow hedges of gas and crude oil price risk. This fair value loss is expected to be reclassified into
earnings through December 2005. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.
Stock-based Incentive Compensation. Incentive compensation generally results from vesting of performance share awards as our common stock price increases.
Incentive compensation totaled $89.5 million in 2004, $53.1 million in 2003 and $27 million in 2002, which relates to increases in our stock price of 56% in
2004, 53% in 2003 and 41% in 2002. Included in 2004 incentive compensation is $22.3 million cash compensation related to vesting of cash-equivalent
performance shares. Otherwise, stock-based compensation was non-cash. After adjusting for the effects of the May 2004 and April 2003 common stock
offerings, stock-based incentive compensation was approximately 3% of the increase in market capitalization during each of 2004, 2003 and 2002. As of
December 31, 2004, outstanding performance shares comprise 397,500 shares that vest when the common stock price reaches $28.13, 2,533 shares that vest
when the common stock price reaches $28.50, and 397,500 shares that vest when the common stock price reaches $31.88. Based on
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management’s estimated probable vesting period, $2.8 million of related stock incentive compensation was accrued at December 31, 2004. All performance
shares vested in February 2005 when these target stock prices were attained, resulting in the remaining related non-cash compensation of $21.1 million to be
recorded in first quarter 2005.
In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 (Revised 2004), which
requires companies to record compensation expense for all stock awards at fair value effective July 1, 2005. Accordingly, we will begin recording compensation
related to stock options in third quarter 2005. See “Accounting Pronouncements” below.
Cross Timbers Royalty Trust Distribution. In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each
share of our common stock outstanding on September 2, 2003. This dividend, totaling 1,360,000 units, was distributed on September 18, 2003, after which we no
longer own any Cross Timbers Royalty Trust units. We recorded this dividend at $28.2 million, or approximately $0.09 per common share, based on the fair
market value of the units on the distribution date. After considering the cost of the units, we recorded a gain on distribution of $16.2 million.
Extinguishment of Debt. We purchased and canceled $9.7 million of our 9¼% senior subordinated notes in April 2002, and redeemed the remaining $115.3
million of the 9¼% notes in June 2002. In November 2002, we purchased and canceled $11.8 million of our 8¾% senior subordinated notes and redeemed the
remaining $163.2 million of the 8¾% notes in May 2003. As a result of these transactions, we recorded a total pre-tax loss on extinguishment of debt of $9.6
million in 2003 and $8.5 million in 2002, which includes the effects of redemption premium paid and expensing related deferred debt costs.
Enron Corporation Bankruptcy and Settlement. In December 2001, after Enron Corporation filed for bankruptcy, we had recorded a $21.4 million receivable
from Enron and a $43.3 million Btu swap contract payable to Enron. In December 2002, we paid Enron Corporation $6 million in settlement of all claims,
resulting in recognition of $14.1 million in gas revenue and a $2.1 million gain.
Cumulative Effect of Accounting Change for Asset Retirement Obligation. On January 1, 2003, we adopted SFAS No. 143 by recording a long-term liability for
asset retirement obligation of $75.3 million, an increase in property cost of $60.7 million, a reduction of accumulated depreciation, depletion and amortization of
$17.3 million and a cumulative effect of accounting change gain, net of tax, of $1.8 million.
Impairment Provision. We evaluate possible impairment of producing properties when conditions warrant. This evaluation is based on an assessment of
recoverability of net property costs from estimated future net cash flows from those properties. Estimated future net cash flows are based on management’s best
estimate of projected oil and gas reserves and prices. We have not recorded impairment of producing properties since a $2 million provision was recorded in
1998. If oil and gas prices significantly decline, we may be required to record impairment provisions for producing properties in the future, which could be
material.
Investment Grade Ratings. In January 2004, Standard & Poors upgraded our corporate credit rating to investment grade and all liens on producing properties and
other collateral were irrevocably released as security for our revolving credit agreement with commercial banks. As a result, Moody’s upgraded our existing
senior notes to Ba1 from Ba2 and confirmed our Ba1 senior implied rating. In March 2004, Moody’s upgraded our issuer rating and senior implied rating to
Baa3.
Senior Note Offering. In April 2002, we sold $350 million of 7½% senior notes due April 2012, and in April 2003, we sold $400 million of 6¼% senior notes
due April 2013. In January 2004, we sold $500 million of 4.9% senior notes due February 2014. In September 2004, we sold $350 million of 5% senior notes due
in January 2015. Proceeds from the senior notes were used to fund property acquisitions, redeem senior subordinated notes and reduce bank debt.
Common Stock Transactions. In April 2003, we completed a public offering of 23 million shares of common stock at $11.25 per share, with net proceeds of
approximately $248 million. The proceeds and net proceeds from the concurrent sale of senior notes were used to fund our producing property acquisition from
Williams, to redeem our 8¾% senior subordinated notes and to reduce bank debt. In May 2004, we completed a public offering of 31.7 million shares of common
stock at $18.92 per share. Net proceeds of $580 million were used to reduce bank borrowings that funded our producing property acquisitions from ExxonMobil
Corporation and our deposit on the ChevronTexaco acquisition.
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Shelf Registration Statement. In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer
securities which could include debt securities, preferred stock, common stock, or warrants to purchase debt or stock. The total face amount of securities that can
be offered is $2.5 billion, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general
corporate purposes, including reduction of bank debt.
Results of Operations
2004 Compared to 2003
For the year 2004, net income was $507.9 million compared with net income of $288.3 million for 2003. Earnings for 2004 include the net after-tax effects
of stock-based incentive compensation of $55.5 million, special bonuses totaling $11.7 million related to acquisitions announced in second quarter 2004, and a
$7.4 million derivative fair value loss. Earnings for 2003 include the net after-tax effects of non-cash incentive compensation of $34.5 million, loss on
extinguishment of debt of $6.2 million, a $6.6 million derivative fair value loss, a non-cash contingency gain of $1.1 million, a non-cash gain of $10.5 million
resulting from the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders and a $1.8 million gain on the cumulative effect of
the accounting change for adoption of SFAS No. 143 for asset retirement obligation.
Revenues for 2004 were $1.95 billion, or 64% higher than 2003 revenues of $1.19 billion. Gas and natural gas liquids revenue increased $572.8 million, or
55%, because of a 25% increase in gas production and a 24% increase in gas prices from an average of $4.07 per Mcf in 2003 to $5.04 in 2004, as well as a 32%
increase in natural gas liquids prices from an average price of $19.99 per Bbl in 2003 to $26.44 in 2004 and a 16% increase in natural gas liquids production (see
“Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2004 acquisition and development
program.
Oil revenue increased $183.7 million, or 136%, primarily because of a 75% increase in production, primarily due to acquisitions, and a 34% increase in oil
prices from an average of $28.59 per Bbl in 2003 to $38.38 in 2004 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above). Gas
gathering, processing and marketing revenues increased $5.4 million primarily because of higher natural gas liquids prices and margins.
Expenses for 2004 totaled $1.03 billion as compared with total 2003 expenses of $687.9 million. Most expenses increased in 2004 because of increased
production from acquisitions and development and related Company growth. Production expense increased $81 million, or 49%, primarily because of increased
production and maintenance. The production expense per Mcfe increase from $0.58 in 2003 to $0.66 in 2004 is primarily attributable to the 75% increase in oil
production, which is more expensive to produce than natural gas. Taxes, transportation and other expense, which is generally based on product revenue,
increased 66%, or $69.4 million, primarily because of significantly higher oil and gas prices and increased production. Taxes, transportation and other per Mcfe
increased 27% from $0.37 in 2003 to $0.47 in 2004 primarily due to higher product prices. Exploration expense increased $8.7 million primarily because of 2004
seismic studies conducted in the Barnett Shale and East Texas.
Depreciation, depletion and amortization (DD&A) increased $122.7 million, or 43%, primarily because of increased production and higher acquisition
costs. On an Mcfe basis, DD&A increased from $0.99 in 2003 to $1.09 in 2004 because of higher acquisition and development costs.
General and administrative expense increased $57.4 million, or 53%, primarily because of an increase of $36.4 million in stock-based incentive
compensation from $53.1 million to $89.5 million, of which $67.2 million is non-cash. General and administrative expense for the year also includes a total of
$11.7 million in special bonuses related to the ChevronTexaco and ExxonMobil acquisitions announced in second quarter 2004 and other increased expenses
from Company growth. Excluding stock-based incentive compensation, general and administrative expense per Mcfe increased 5% from $0.19 in 2003 to $0.20
in 2004.
The derivative fair value loss for 2004 was $11.9 million compared to the 2003 derivative fair value loss of $10.2 million. This loss is primarily related to
the ineffective portion of hedge derivatives as well as the effect of higher gas prices on the fair value of Btu swap contracts. See Note 7 to Consolidated Financial
Statements.
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Interest expense increased $29.9 million, or 47%, primarily because of a 46% increase in the weighted average borrowings to partially fund property
acquisitions. Interest expense per Mcfe increased 14% from $0.22 in 2003 to $0.25 in 2004.
2003 Compared to 2002
For the year 2003, net income was $288.3 million compared with net income of $186.1 million for 2002. Earnings for 2003 include the net after-tax effects
of non-cash incentive compensation of $34.5 million, loss on extinguishment of debt of $6.2 million, a $6.6 million derivative fair value loss, a non-cash
contingency gain of $1.1 million, a non-cash gain of $10.5 million resulting from the distribution of Cross Timbers Royalty Trust units as a dividend to common
stockholders and a $1.8 million gain on the cumulative effect of the accounting change for adoption of SFAS No. 143 for asset retirement obligation. Earnings
for 2002 include a $17.5 million after-tax charge for non-cash incentive compensation, a $5.5 million after-tax charge for extinguishment of debt, a $1.3 million
after-tax gain on a settlement with Enron Corporation and a $1.7 million after-tax derivative fair value gain.
Revenues for 2003 were $1.19 billion, or 47% higher than 2002 revenues of $810.2 million. Gas and natural gas liquids revenue increased $359.2 million,
or 53%, because of a 30% increase in gas production and a 17% increase in gas prices from an average of $3.49 per Mcf in 2002 to $4.07 in 2003, as well as a
40% increase in natural gas liquids prices from an average price of $14.31 per Bbl in 2002 to $19.99 in 2003 and a 28% increase in natural gas liquids production
(see “Significant Events, Transactions and Conditions – Product Prices – Gas” above). Increased production was attributable to the 2003 acquisition and
development program.
Oil revenue increased $19.7 million, or 17%, primarily because of an 18% increase in oil prices from an average of $24.24 per Bbl in 2002 to $28.59 in
2003 (see “Significant Events, Transactions and Conditions – Product Prices – Oil” above). A 1% decrease in production was the result of natural decline,
partially offset by development. Gas gathering, processing and marketing revenues increased $1.4 million primarily because of higher natural gas liquids prices
and margins. Other revenues of $2.1 million in 2002 represent the gain on a settlement with Enron Corporation.
Expenses for 2003 totaled $687.9 million as compared with total 2002 expenses of $461.3 million. Most expenses increased in 2003 because of increased
production from acquisitions and development and related Company growth. Production expense increased $35.7 million, or 28%, because of higher production
related to acquisitions and development. Production expense per Mcfe increased slightly from $0.57 in 2002 to $0.58 in 2003 because of increased fuel costs.
Taxes, transportation and other increased 83%, or $47.4 million, primarily because of significantly higher oil and gas prices, increased production, higher
transportation fuel prices and higher property taxes related to drilling and acquisitions. Taxes, transportation and other per Mcfe increased 48% from $0.25 in
2002 to $0.37 in 2003 primarily due to higher product prices.
DD&A increased $79.9 million, or 39%, primarily because of increased production and higher acquisition costs. On an Mcfe basis, DD&A increased from
$0.90 in 2002 to $0.99 in 2003 because of higher acquisition and development costs.
General and administrative expense increased $45.6 million, or 73%, because of an increase of $26.1 million in stock-based incentive compensation and
increased expenses from Company growth. Excluding this non-cash incentive compensation, general and administrative expense per Mcfe increased 27% from
$0.15 in 2002 to $0.19 in 2003.
The derivative fair value loss for 2003 was $10.2 million compared to 2002 derivative fair value gain of $2.6 million. The 2003 loss is primarily related to
the effect of higher gas prices on the fair value of Btu swap contracts and the ineffective portion of hedge derivatives. The 2002 gain is primarily the result of
declining gas prices on derivatives that do not qualify for hedge accounting. See Note 7 to Consolidated Financial Statements.
Interest expense increased $10.2 million, or 19%, primarily because of a 24% increase in the weighted average borrowings to partially fund property
acquisitions, offset by a 6% decrease in the weighted average interest rate. Interest expense per Mcfe decreased 8% from $0.24 in 2002 to $0.22 in 2003 because
higher production offset increased borrowings.
During 2003, we recognized a $9.6 million loss on extinguishment of debt related to the redemption of our 8¾% senior subordinated notes, compared with
the recognition in 2002 of an $8.5 million loss on extinguishment of debt
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primarily related to the redemption of our 9¼% senior subordinated notes. See Note 3 to Consolidated Financial Statements. During 2003, we also recognized a
$16.2 million gain on the distribution of Cross Timbers Royalty Trust units as a dividend to common stockholders.
Liquidity and Capital Resources
Our primary sources of liquidity are cash flow from operating activities, borrowings against the revolving credit facility, occasional producing property
sales (including sales of royalty trust units) and private or public offerings of equity and debt. Other than for operations, our cash requirements are generally for
the acquisition, exploration and development of oil and gas properties, and debt and dividend payments. Exploration and development expenditures and dividend
payments have generally been funded by cash flow from operations. We believe that our sources of liquidity are adequate to fund our cash requirements in 2005.
Cash provided by operating activities was $1.22 billion in 2004, compared with cash provided by operating activities of $794.2 million in 2003 and $490.8
million in 2002. Increased cash provided by operating activities from 2003 to 2004 and from 2002 to 2003 was primarily because of increased prices and
production from acquisitions and development activity. Cash provided by operating activities was decreased by changes in operating assets and liabilities of
$58.2 million in 2004 and $22.9 million in 2002 and was increased by changes in operating assets and liabilities of $3.7 million in 2003. Changes in operating
assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash provided by operating activities was also reduced by exploration
expense of $10.5 million in 2004, $1.8 million in 2003 and $2.2 million in 2002. Cash provided by operating activities is largely dependent upon the prices
received for oil and gas production. As of February 2005, we have hedged approximately 25% of our projected 2005 gas production and about 45% of our
projected 2005 crude oil production. See “Significant Events, Transactions and Conditions - Product Prices” above.
We do not have any investments in unconsolidated entities or persons that could materially affect the liquidity or the availability of capital resources.
Financial Condition
Total assets increased 69% from $3.6 billion at December 31, 2003 to $6.1 billion at December 31, 2004, primarily because of Company growth related to
acquisitions and development. As of December 31, 2004 total capitalization was $4.6 billion, of which 44% was long-term debt. Capitalization at December 31,
2003 was $2.7 billion, of which 46% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 2003 to 2004 is primarily because of our
earnings for the year.
Working Capital
We generally maintain low cash and cash equivalent balances because we use available funds to reduce bank debt. Short-term liquidity needs are satisfied
by bank commitments under the loan agreement (see “Financing” below). Because of this, and since our principal source of operating cash flows (i.e., proved
reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. Working capital decreased
from a negative position of $59.4 million at December 31, 2003 to negative working capital of $64 million at December 31, 2004. Excluding the effects of
current derivative and deferred tax assets and liabilities, working capital decreased $19.2 million. This decrease is because of increased accounts payable and
accrued liabilities primarily related to increased production and drilling liabilities, partially offset by increased accounts receivable related to increased revenues.
Any cash settlement of hedge derivatives should generally be offset by increased or decreased cash flows from our sales of related production. Therefore, we
believe that most of the changes in derivative fair value assets and liabilities are offset by changes in value of our oil and gas reserves. This offsetting change in
value of oil and gas reserves, however, is not recorded in the financial statements.
None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.
When the monthly cash settlement amount under our hedge derivatives is calculated, if market prices are higher than the fixed contract prices, we are required to
pay the contract counterparties. While this payment will ultimately be funded by higher prices received from sale of our production, production receipts lag
payments to the counterparties by as much as 55 days. Any interim cash needs are funded by borrowings under our revolving credit agreement.
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Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and
end-users in various industries. We currently have greater concentrations of credit with several A- or better rated integrated energy companies. Financial and
commodity-based futures and swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified
among major investment grade financial institutions, and we have master netting agreements with counterparties that provide for offsetting payables against
receivables from separate derivative contracts. Letters of credit or other appropriate forms of security are obtained as considered necessary to limit risk of loss.
Financing
In February 2004, we entered a five-year revolving credit agreement with commercial banks that matures in February 2009. The agreement currently
provides for a maximum commitment amount of $1 billion, and an interest rate based on the London Interbank Offered Rate (“LIBOR”) plus 1%. The agreement
requires us to maintain a debt-to-total capitalization ratio of not more than 60%. On December 31, 2004, borrowings under the revolving credit agreement with
commercial banks were $146 million at a weighted average interest rate of 3.49%, and with unused borrowing capacity of $854 million.
In November 2004, we entered a new $300 million five-year term loan due April 2010 with an initial interest rate of LIBOR plus 0.75%. Other terms and
conditions are substantially the same as our existing revolving credit agreement. As of December 31, 2004, borrowings under the term loan were $300 million.
In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include
debt securities, preferred stock, common stock or warrants to purchase debt or stock. The total face amount of securities that can be offered is $2.5 billion, at
prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including
reduction of bank debt.
Capital Expenditures
In 2004, exploration and development cash expenditures totaled $610 million compared with $461.6 million in 2003. We have budgeted $850 million for
the 2005 development and exploration program. As we have done historically, we expect to fund the 2005 development program with cash flow from operations.
Since there are no material long-term commitments associated with this budget, we have the flexibility to adjust our actual development expenditures in response
to changes in product prices, industry conditions and the effects of our acquisition and development programs.
While an acquisition budget has not been formalized, we plan to actively review additional acquisition opportunities during 2005. If acquisition,
development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, issuance
of public or private debt or equity, or asset sales. There are no restrictions under our revolving credit agreement that would affect our ability to use our remaining
borrowing capacity for acquisitions of producing properties.
To date, we have not spent significant amounts to comply with environmental or safety regulations, and we do not expect to do so during 2005. However,
new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.0045 per common share each quarter of 2002, $0.006 per common share each quarter of 2003,
$0.0075 per common share for first and second quarter 2004 and $0.0375 per common share for the remainder of 2004. In February 2005, the Board increased
the dividend rate 33% by declaring
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a first quarter 2005 dividend of $0.05 per common share after the four-for-three stock split is effected on March 15, 2005. In August 2003, the Board also
declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of our common stock outstanding on September 2, 2003. The market value at
the date of distribution was approximately $0.09 per common share. Our ability to pay dividends is dependent upon our financial condition, earnings and cash
flow from operations, the level of our capital expenditures, our future business prospects and other matters our Board of Directors deems relevant.
Income Taxes
We have estimated that all our net operating loss carryforwards will be fully utilized as of December 31, 2004. Although our alternative minimum tax
credit carryforwards of $37.8 million have no expiration date, we expect to utilize these carryforwards in 2005.
Contractual Obligations and Commitments
The following summarizes our significant obligations and commitments to make future contractual payments as of December 31, 2004. We have not
guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in
unconsolidated debt or losses.
Payments Due by Year
Total
2005
2006
2007
2008
2009
After 2009
—
18,605
—
18,804
—
—
$ 146,000
15,964
—
18,030
—
—
$ 1,900,000
39,666
—
36,368
—
—
$ 37,409
$ 179,994
$ 1,976,034
(in thousands)
Long-term debt
Operating leases
Drilling contracts
Transportation contracts
Purchase obligations
Derivative contract liabilities at December 31, 2004 fair value
Total
$ 2,046,000
151,123
99,085
137,341
10,300
86,713
$
—
30,200
99,085
21,935
10,300
75,534
$ 2,530,562
$ 237,054
$
—
23,882
—
22,463
—
11,179
$ 57,524
$
—
22,806
—
19,741
—
—
$ 42,547
$
Long-Term Debt. At December 31, 2004, borrowings were $146 million under our senior bank revolving credit facility due in February 2009, as reflected in the
table above. Borrowings of $300 million under our term bank facility are due in April 2010, and our senior notes, totaling $1.6 billion at December 31, 2004, are
due in 2012 through 2015. For further information regarding long-term debt, see Note 3 to Consolidated Financial Statements.
Transportation Contracts. We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum
daily gas volumes or pay for any deficiencies at a specified reservation fee rate. As calculated on a monthly basis, our failure to deliver these minimum volumes
to the pipeline requires us to pay the pipeline for any deficiency. Our production committed to these pipelines is expected to exceed the minimum daily volumes
provided in the contracts. We have generally delivered at least minimum volumes under these firm transportation contracts, therefore avoiding payment for
deficiencies.
Purchase Obligations. We have agreed to acquire an airplane for $17.1 million, either through purchase or lease, and have made an initial payment of $6.8
million in 2004. We currently expect to take delivery of the airplane in the first half of 2005. This obligation is reflected as a purchase in the table above, net of
the amount paid in 2004.
Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to oil and natural gas price fluctuations. As of December 31, 2004,
market prices generally exceeded the fixed prices specified by these contracts, resulting in a derivative fair value current liability of $75.5 million and long-term
liability of $11.2 million. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract
counterparties. While such payments generally will be funded by higher prices received from the sale of our production, production receipts may be received as
much as 55 days after payment to counterparties and can result in draws on our revolving credit facility. See Note 8 to Consolidated Financial Statements.
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Post-Retirement Plans
We have a retiree medical plan that provides retired employees and directors with health care benefits similar to those provided employees. Employees and
directors are eligible to receive benefits when their combined age and years of qualified service total 60, with a minimum age of 45 and a minimum of five years
of service. Otherwise, retirement benefits are only provided through our defined contribution 401(k) plan. Post-retirement medical benefits are not prefunded but
are paid when incurred. Our periodic benefit cost recorded for 2004 was $632,000 and is expected to be approximately $1 million in 2005. Future benefit costs
will be affected by fluctuations in interest rates and health care cost trends. We do not currently anticipate that retiree medical plan costs will be significant in
relation to the Company’s future financial position, results of operations or cash flows.
Related Party Transactions
A firm, partially owned by one of our directors, has performed property acquisition advisory services for the Company. We paid this firm total fees of $8.8
million in 2004 and $2.4 million in 2002, and there were no amounts payable at December 31, 2004 or 2003. No fees were paid to this firm in 2003. This same
director-related company represented the seller of properties for acquisitions totaling approximately $186 million that we closed in January 2004. In February
2005, this firm was acquired by another company with which we expect to continue to have a relationship.
A portion of the producing properties obtained in the ChevronTexaco acquisition were considered nonstrategic and marked for disposition at the time of
purchase. In August 2004, we exchanged $37.8 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett Shale of
North Texas, and $25.4 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of
Bob R. Simpson, Chairman and Chief Executive Officer of the Company. In connection with this exchange, we granted these companies an option to purchase
other properties included in the ChevronTexaco acquisition. On March 1, 2005, these companies purchased the properties for an adjusted purchase price of $11.5
million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.
Critical Accounting Policies and Estimates
Our financial position and results of operations are significantly affected by accounting policies and estimates related to our oil and gas properties, proved
reserves, asset retirement obligation and commodity prices and risk management, as summarized below.
Oil and Gas Property Accounting
Oil and gas exploration and production companies may elect to account for their property costs using either the “successful efforts” or “full cost”
accounting method. Under the successful efforts method, unsuccessful exploratory well costs, as well as all exploratory geological and geophysical costs, are
expensed. Under the full cost method, all exploration costs are capitalized, regardless of success. Selection of the oil and gas accounting method can have a
significant impact on a company’s financial results. We use the successful efforts method of accounting and generally pursue acquisitions and development of
proved reserves as opposed to exploration activities.
In accordance with Statement of Financial Accounting Standards No. 144, we evaluate possible impairment of producing properties when conditions
indicate that the properties may be impaired. Such conditions include a significant decline in product prices which we believe to be other than temporary or a
significant downward revision in estimated proved reserves for a field or area. Our estimates of cash flows are based on the latest available proved reserve and
production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices and industry
forecasts and analysis. An impairment provision must be recorded to adjust the net book value of the property to its estimated fair value if the net book value
exceeds the estimated future net cash flows from the property. The estimated fair value of the property is generally calculated as the discounted present value of
future net cash flows.
The impairment assessment process is primarily dependent upon the estimate of proved reserves. Any overstatement of estimated proved reserve quantities
would result in an overstatement of estimated future net cash flows, which could result in an understated assessment of impairment. The subjectivity and risks
associated with estimating proved reserves are discussed under “Oil and Gas Reserves” below. Prediction of product prices is subjective since
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prices are largely dependent upon supply and demand resulting from global and national conditions generally beyond our control. However, management’s
assessment of product prices for purposes of impairment is consistent with that used in its business plans and investment decisions. While there is judgment
involved in management’s estimate of future product prices, the potential impact on impairment is not currently significant since current and projected product
prices are substantially higher than our net acquisition and development costs per Mcfe. Because of this, our historical impairment of producing properties has
been limited to a $2 million provision in 1998, and we do not currently expect significant future impairment unless product prices were to decline and remain at
levels substantially below current levels. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is
impracticable to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.
Oil and Gas Reserves
Our proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the
quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different
engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an
estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be
estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.
Proved reserves, as defined by the Financial Accounting Standards Board and adopted by the Securities and Exchange Commission, are limited to
reservoir areas that indicate economic producibility through actual production or conclusive formation tests, and generally cannot extend beyond the immediately
adjoining undrilled portion. Although improved technology often can identify possible or probable reserves other than by drilling, these reserves cannot be
estimated and disclosed.
Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas
reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing of when
DD&A expense is recognized. Downward revisions of proved reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate
of DD&A expense recognition. As shown in Note 15 to the Consolidated Financial Statements, net upward revisions occurred to proved reserves on an Mcfe
basis in 2002 and 2003, resulting in a decrease of DD&A expense of approximately 4%, or $8 million, in 2002 and 1%, or $2 million, in 2003. Net downward
revisions of proved reserves on an Mcfe basis occurred in 2004, resulting in an increase in DD&A expense of approximately 2%, or $7 million. Based on proved
reserves at December 31, 2004, we estimate that a 1% change in proved reserves would increase or decrease 2005 DD&A expense by approximately $4 million.
During 2004, development and exploration activities resulted in extensions, additions, discoveries and net revisions of proved reserves that were 195% of
our 2004 production. Over the last five years, our proved reserve extensions, additions, discoveries and net revisions averaged 220% of our production for this
period. Our proved reserve extensions, additions and discoveries in 2004 included an increase of 637.6 Bcfe in proved undeveloped reserves, or approximately
80% of our total extensions, additions and discoveries, which are expected to be developed within three years. Over the past four years, approximately 80% of
our proved reserves extensions, additions and discoveries were proved undeveloped reserves which were generally reclassified to proved developed reserves
within three years. Development of our proved undeveloped reserves is not subject to significant uncertainties such as regulatory approvals, and we believe that
we have adequate resources to develop these reserves, dependent on commodity prices not declining significantly. We believe that reserve additions, comparable
to these historical reserve additions, are attainable in the near term future, subject to product prices and development costs remaining at levels to ensure economic
viability.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 15 to Consolidated Financial
Statements, are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such
assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net
cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the
standardized measure does not represent management’s estimated current market value of proved reserves.
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Asset Retirement Obligation
Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. Our asset retirement obligation primarily represents
the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties (including removal of our offshore platforms in
Alaska) at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present
value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception,
with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs,
the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset
retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed
annual inflation of these costs and/or the assumed productive lives of our wells. During 2004, we increased our estimated asset retirement obligation by $6
million, or approximately 6% of the asset retirement obligation at December 31, 2003, based on a review of current plugging and abandonment costs. Revisions
to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and
amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to
ultimately retire our wells may vary significantly from prior estimates.
Commodity Prices and Risk Management
Commodity prices significantly affect our operating results, financial condition, cash flows and ability to borrow funds. Current market oil and gas prices
are affected by supply and demand as well as seasonal, political and other conditions which we generally cannot control. Oil and gas prices and markets are
expected to continue their historical volatility. See “Significant Events, Transactions and Conditions – Product Prices” above.
We attempt to reduce our price risk on a portion of our production by entering into financial instruments such as futures contracts, collars and basis swap
agreements, as well as fixed price physical delivery contracts. While these instruments secure a certain price and, therefore, a certain cash flow, there is the risk
that we may not be able to realize the full benefit of rising prices. These contracts also expose us to credit risk of nonperformance by the contract counterparties,
all of which are major investment grade financial institutions. We attempt to limit our credit risk by obtaining letters of credit or other appropriate forms of
security. We also have sold call options as part of our hedging program. Call options, however, do not provide a hedge against declining prices, and there is the
risk that the call sales proceeds will be less than the benefit a higher sales price would have provided.
While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under
generally accepted accounting principles, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon
settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the
market value of our proved reserves, which are not reflected in the financial statements. Derivatives that provide effective cash flow hedges are designated as
hedges, and, to the extent the hedge is determined to be effective, we defer related unrealized fair value gains and losses in accumulated other comprehensive
income until the hedged transaction occurs. See “Derivatives” under Note 1 to Consolidated Financial Statements regarding our accounting policy related to
derivatives.
See also “Commodity Price Risk” under Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for the effect of price changes on derivative
fair value gains and losses.
Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board issued SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion
No. 29, which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged,
and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected
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future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion 29
previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. We
must implement SFAS 153 for any nonmonetary asset exchanges occurring on or after January 1, 2006. This change in accounting is currently not expected to
have a significant effect on our reported financial position or earnings.
In December 2004, the FASB issued Staff Position FAS 109-1 that concluded that the special tax deduction allowed under the American Jobs Creation Act
of 2004 should be accounted for as a “special deduction” instead of a tax rate reduction as provided by SFAS 109. Accordingly, any tax relief the Company
receives under the new tax law will be recorded as a reduction of current tax when realized, rather than an immediate reduction to its accrued deferred income tax
liability.
Also in December 2004, the FASB issued SFAS No. 123 (Revised 2004), Share-Based Payment, which requires that compensation related to all
stock-based awards, including stock options, be recognized in the financial statements. This pronouncement replaces SFAS No. 123, Accounting for Stock-Based
Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and will be effective beginning July 1, 2005. We have
previously recorded stock compensation pursuant to the intrinsic value method under APB No. 25, whereby no compensation was recognized for most stock
option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and, therefore, SFAS No. 123R will have a
significant impact on our financial statements. For the pro forma effect of recording compensation for all stock awards at fair value, utilizing the Black-Scholes
method, see Stock-Based Compensation in Note 1 to Consolidated Financial Statements. We are currently considering alternative valuation methods to determine
stock award fair value for grants after June 30, 2005. We plan to use the modified prospective application method of adopting SFAS No. 123R, whereby the
estimated fair value of unvested stock awards granted prior to July 1, 2005 will be recognized as compensation expense in periods subsequent to June 30, 2005,
based on the estimated service period. The fair value of awards granted prior to July 1, 2005 will be the same value as determined under the Black–Scholes
method for our pro forma disclosure. As of February 22, 2005, all stock options outstanding at that date vested when the common stock price closed above the
target price level of $31.88, resulting in no compensation expense to be recognized after June 30, 2005 related to these awards.
In February 2005, the staff of the Securities and Exchange Commission sent a letter to oil and gas registrants regarding situations that require additional
financial statement disclosures, pending final resolution of accounting treatment. The following are items related to registrants using the successful efforts
method of accounting:
•
Companies may enter concurrent commodity buy/sale arrangements, or transactions in contemplation of other transactions, often to assure that the
commodity is available at a specific location. Pending resolution of accounting questions with the Emerging Issues Task Force, the Commission
staff has requested additional disclosures for any such material arrangements, including separate disclosure on the face of the income statement of
any related proceeds and costs reported on a gross basis. These disclosures are not applicable to us since we have not entered any significant
transactions of this nature.
•
Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, specifies that
drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain
criteria are met. Rather than specifying this one-year requirement, a proposed FASB Staff Position has been issued that provides guidance for
evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved. Pending approval of the FASB Staff
Position, the Commission staff has requested additional disclosures be included in registrants’ financial statements regarding their accounting policy
for capitalization of exploratory drilling costs, as well as disclosure of capitalized exploratory drilling cost amounts included in the financial
statements. As disclosed in Note 1 to Consolidated Financial Statements, we generally pursue development of proved reserves as opposed to
exploration activities, and our drill well costs are generally transferred to producing properties within one month of the well completion date.
Disclosure of changes in capitalized exploratory well costs is included in Note 15 to Consolidated Financial Statements.
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Production Imbalances
We have gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on jointly
owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well, or by cash payment by the overproduced party to
the underproduced party. We use the entitlement method of accounting for natural gas sales. Accordingly, revenue is deferred for gas deliveries in excess of our
net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at
the time of production. The consolidated balance sheets include the following amounts related to production imbalances:
December 31
2004
Amount
2003
Mcf
Amount
Mcf
(in thousands)
Accounts receivable - current underproduction
Accounts payable - current overproduction
$
Net current gas underproduction balancing receivable
$
Other assets - noncurrent underproduction
Other long-term liabilities - noncurrent overproduction
$
Net long-term gas overproduction balancing payable
30,780
8,116 $ 23,949
7,135
(24,087) (6,388)
(19,366) (5,900)
6,693
1,728
$
1,985
Net long-term overproduction balancing payable
1,235
17,723
4,868 $ 19,385
6,148
(33,262) (9,063)
(29,776) (9,353)
(15,539) (4,195)
Other assets - noncurrent carbon dioxide underproduction
4,583
$ (13,554)
(10,391) (3,205)
12,480
1,977
$
12,354
(8,414)
Forward-Looking Statements
Certain information included in this annual report and other materials filed or to be filed by us with the Securities and Exchange Commission, as well as
information included in oral statements or other written statements made or to be made by us, contain projections and forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to our
operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures, capital budget, cash
flow, drilling activity, drilling locations, acquisition and development activities and funding thereof, production and reserve growth, pricing differentials, reserve
potential, operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof,
liquidity, debt repayment, unused borrowing capacity, estimated stock award vesting periods, completion of pipelines and processing facilities, regulatory matters
and competition. Such forward-looking statements are based on management’s current plans, expectations, assumptions, projections and estimates and are
identified by words such as “expects,” “intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,” “estimates,” “goal,” “should,” “could,” “assume,” and
similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and
assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in,
or implied in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are discussed below.
Oil and Gas Price Fluctuations. Our results of operations depend upon the prices we receive for our oil and gas. Historically, the markets for oil and gas have
been volatile and are likely to remain volatile in the future. We routinely hedge a portion of our production to reduce the effects of price volatility (see “Hedging
Arrangements” below). Otherwise, the prices we receive depend upon factors beyond our control, including political instability in oil-producing regions, weather
conditions, ability of OPEC to agree upon and maintain oil prices and production levels, consumer demand, worldwide economic conditions and the price and
availability of alternative fuels. Moreover, government regulations, such as regulation of gas transportation and price controls, can affect product prices in the
long term. These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of oil and gas. To the extent we
have not hedged our production, any decline in oil and gas prices adversely affects our financial
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condition. If the oil and gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, make
planned capital expenditures or reach production growth targets.
Debt Level. We have substantial debt and may incur more. If we are unsuccessful in increasing production from existing reserves or developing new reserves, we
may lack the funds to pay principal and interest on our debt obligations. Our indebtedness also affects our ability to finance future operations and capital needs
and may preclude pursuit of other business opportunities.
Capital Requirements. We make, and will continue to make, substantial capital expenditures for the acquisition, development, production, exploration and
abandonment of our oil and gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, bank borrowings and public
or private offerings of equity and debt. Lower oil and gas prices, however, may reduce cash flow available to pay down bank borrowings or other debt.
Competitive Industry. The oil and gas industry is highly competitive. We compete with major oil companies, independent oil and gas businesses, and individual
producers and operators. In addition, there is competition from alternative energy sources, such as heating oil, imported liquified natural gas and other fossil
fuels. Some of our competitors have financial, technological and other resources substantially greater than ours. These companies may be able to pay more for
development prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. We also compete with these companies for technical, managerial and other professional personnel. Our
ability to develop and exploit our oil and gas properties and to acquire additional properties in the future will depend upon our ability to hire and retain qualified
personnel, conduct operations, implement advanced technologies, evaluate and select suitable properties, and consummate transactions in this highly competitive
environment.
Reserve Replacement. Our success depends upon finding, acquiring and developing oil and gas reserves that are economically recoverable. Unless we are able to
successfully explore for, develop or acquire proved reserves, our proved reserves will decline through depletion and our financial assets and annual revenues will
decline unless prices substantially increase. We cannot assure the success of our exploration, development and acquisition activities.
Hedging Arrangements. To reduce our exposure to fluctuations in the prices of oil and gas, we currently and may in the future enter into hedging arrangements
for a portion of our oil and gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is
less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the
underlying price in the hedging agreements and actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive
from increases in prices for oil and gas.
Reserve Estimates. Estimating our proved reserves involves many uncertainties, including factors beyond our control. Petroleum engineers consider many factors
and make assumptions in estimating oil and gas reserves and future net cash flows. Lower oil and gas prices generally cause lower estimates of proved reserves.
Ultimately, actual production, revenues and expenditures relating to our reserves will vary from any estimates, and these variations may be material.
Acquiring Producing Properties. We constantly evaluate opportunities to acquire oil and gas properties and frequently engage in bidding and negotiation for
these acquisitions. If successful in this process, we may alter or increase our capitalization through the issuance of additional debt or equity securities, the sale of
production payments or other measures. Any change in capitalization affects our risk profile. Acquisitions may also alter the nature of our business. This could
occur when the character of acquired properties is substantially different from our existing properties in terms of operating or geologic characteristics.
Drilling Activities. Our drilling activities subject us to many risks, including the risk that we will not find commercially productive reservoirs. Drilling for oil and
gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems,
weather conditions, governmental requirements and shortages or delays in the delivery of equipment and services can delay our drilling operations or result in
their cancellation. Shortages of equipment, including pipe, can lead to a delay or suspension of drilling and can significantly increase the cost of drilling. The cost
of drilling, completing and operating wells is often uncertain, and we cannot assure that new wells will be productive or that we will recover all or any portion of
our investment.
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Marketability of Production. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, gas gathering
systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver some of
our oil and gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future or access may be limited for
extended periods due to maintenance or other curtailment.
Growth through Acquisitions. Our business strategy has emphasized growth through strategic acquisitions, but we may not be able to continue to identify
properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. There is intense competition for
acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy
of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our
ability to pursue our growth strategy may be hindered if we are not able to obtain financing or regulatory approvals. Our ability to grow through acquisitions and
manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively
manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current
operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from
period to period, based on whether or not significant acquisitions are completed in particular periods.
Governmental Regulations. Extensive federal, state and local regulation of the oil and gas industry significantly affects our operations. In particular, our oil and
natural gas exploration, development and production, and our storage and transportation of liquid hydrocarbons, are subject to stringent environmental
regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other
related facilities. These regulations may become more demanding in the future. Matters subject to regulation include discharge permits for drilling operations,
drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, reports concerning operations, and taxation.
Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, reclamation costs,
remediation and clean-up costs, and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or
termination of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that
substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to
conduct our business or cause us to limit or curtail some of our operations.
We currently own, lease or expect to acquire, and have in the past owned or leased, numerous properties that have been used for the exploration and production
of oil and natural gas for many years. Although we have used operating and disposal practices that were standard in the industry at the time, petroleum
hydrocarbons or wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes
were taken for disposal. In addition, petroleum hydrocarbons or wastes may have been disposed or released by prior operators of properties that we are acquiring
as well as by current third party operators of properties in which we have an ownership interest. Properties impacted by any such disposal or releases could be
subject to costly and stringent investigatory or remedial requirements under environmental laws, some of which impose strict joint and several liability without
regard to fault or the legality of the original conduct. These laws include the federal Comprehensive Environmental Response, Compensation, and Liability Act,
also known as “CERCLA” or the “Superfund” law, the federal Resource Conservation and Recovery Act and analogous state laws. Under these laws and any
implementing regulations, we could be required to remediate contaminated properties and take actions to compensate for damages to natural resources. In
addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the
release of petroleum hydrocarbons or wastes into the environment. We currently do not expect any remedial obligations imposed under environmental laws to
have a significant effect on our operations.
Our operations in the coastal waters of Cook Inlet of Alaska are subject to the federal Oil Pollution Act, which imposes a variety of requirements related to the
prevention of oil spills and liability for damages resulting from such spills in United States waters. The Oil Pollution Act imposes strict joint and several liability
on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities
require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused
by gross negligence or willful misconduct of the party, if the spill
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resulted from violation of a federal safety, construction or operation regulation, or if the party failed to report the spill or cooperate fully in any resulting cleanup.
The Oil Pollution Act also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill. We believe our operations are in substantial compliance with Oil Pollution Act
requirements.
The Department of Transportation, through the Office of Pipeline Safety and Research and Special Programs Administration, has implemented a series of rules
requiring operators of natural gas and hazardous liquid pipelines to develop integrity management plans for pipelines that, in the event of a failure, could impact
certain high consequence areas. These rules also require operators to conduct baseline integrity assessments of all applicable pipeline segments located in the
high consequence areas. We are currently in the process of identifying all of our pipeline segments that may be subject to these rules and are developing integrity
management plans for all covered pipeline segments. We do not expect to incur significant costs in achieving compliance with these rules.
Operating Hazards and Uninsured Risks. Our operations are subject to inherent hazards and risks inherent in drilling for, producing and transporting oil and
natural gas, such as fire, natural disasters, explosions, blowouts, formations with abnormal pressures, failure of oilfield drilling and service tools, uncontrollable
flows of underground gas, oil and formation water, pipeline ruptures or cement failures and environmental hazards such as gas leaks and oil spills. Any of these
events could cause a loss of hydrocarbons, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension
of operations, personal injury claims, loss of life, damage to our properties, or damage to the property of others. In addition, our liability for environmental
hazards may include conditions created by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire
them. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance
coverage for all environmental damages that could occur is available at a reasonable cost. We believe that our insurance is adequate and customary for companies
of similar size and operation, but losses could occur for uninsured risks or in amounts exceeding existing coverage. The occurrence of an event that is not fully
covered by insurance could adversely affect our financial condition and results of operations.
Item 7A.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
We only enter derivative financial instruments in conjunction with our hedging activities. These instruments principally include commodity futures,
collars, swaps and option agreements and interest rate swap agreements. These financial and commodity-based derivative contracts are used to limit the risks of
fluctuations in interest rates and natural gas and crude oil prices. Gains and losses on these derivatives are generally offset by losses and gains on the respective
hedged exposures.
Our Board of Directors has adopted a policy governing the use of derivative instruments, which requires that all derivatives used by us relate to an
underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. The
policy also requires review and approval by the Chairman, the Executive Vice President - Administration and the Senior Vice President - Marketing of all risk
management programs using derivatives and all derivative transactions. These programs are also reviewed at least quarterly by our internal risk management
committee and annually by the Board of Directors.
Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term
changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and
product prices. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
Interest Rate Risk
We are exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2004, our variable rate debt had a
carrying value of $446 million, which approximated its fair value, and our fixed rate debt had a carrying value of $1.60 billion and an approximate fair value of
$1.69 billion. We attempt to balance the benefit of lower cost variable rate debt that has inherent increased risk with more expensive fixed rate debt that has less
market risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate senior and subordinated debt, as well as the occasional
use of interest rate swaps.
40
Table of Contents
The following table shows the carrying amount and fair value of long-term debt and the hypothetical change in fair value that would result from a
100-basis point change in interest rates. Unless otherwise noted, the hypothetical change in fair value could be a gain or a loss depending on whether interest
rates increase or decrease.
Carrying
Amount
Fair
Value (a)
Hypothetical
Change in
Fair Value
$ (2,133,818)
$ (1,275,285)
$ 115,205
$ 51,085
(in thousands)
December 31, 2004 Long-term debt
December 31, 2003 Long-term debt
(a)
$
$
(2,042,732)
(1,252,000)
Fair value is based upon current market quotes and is the estimated amount required to purchase our long-term debt on the open market. This estimated
value does not include any redemption premium.
Commodity Price Risk
We hedge a portion of our price risks associated with our crude oil and natural gas sales. As of December 31, 2004, we had outstanding gas futures
contracts, swap agreements and gas basis swap agreements. These contracts and agreements had a net fair value loss of approximately $30.8 million at December
31, 2004 and a net fair value loss of $84.7 million at December 31, 2003. Of the December 31, 2004 fair value, a $34.8 million loss has been determined based
on the exchange-trade value of NYMEX contracts, and a $4 million gain has been determined based on the broker bid and ask quotes for basis contracts. These
fair values approximate amounts confirmed by the counterparties. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of
approximately $47.9 million in the fair value of gas futures contracts and swap agreements at December 31, 2004. As of December 31, 2004, outstanding oil
futures contracts and differential swaps had a net fair value loss of $22.1 million. The aggregate effect of a hypothetical 10% change in oil prices would result in
a change of approximately $20.6 million in the fair value of these oil futures and differential swaps at December 31, 2004. None of our derivative contracts have
margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. See Note 8 to Consolidated Financial
Statements.
Because most of our futures contracts and swap agreements have been designated as hedge derivatives, changes in their fair value generally are reported as
a component of accumulated other comprehensive income (loss) until the related sale of production occurs. At that time, the realized hedge derivative gain or
loss is transferred to product revenues in the consolidated income statement.
We had a physical delivery contract to sell 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX
futures price for intermediate crude oil. Because this gas sales contract was priced based on crude oil, which is not clearly and closely associated with natural gas
prices, it was accounted for as a non-hedge derivative financial instrument. This contract (referred to as the Enron Btu swap contract) was terminated in
December 2001 in conjunction with the bankruptcy filing of Enron Corporation. In November 2001, we entered derivative contracts to effectively defer until
2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. The net fair
value loss on these contracts at December 31, 2004 was $19.1 million. The effect of a hypothetical 10% change in gas prices would result in a change of
approximately $5.6 million in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of approximately $3.7 million.
Since the contracts are not hedge derivatives, changes in their fair value are recognized in our consolidated income statement as a derivative fair value gain or
loss.
41
Table of Contents
Item 8.
FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
The following financial statements and supplementary information are included under Item 15(a):
Page
Consolidated Balance Sheets
45
Consolidated Income Statements
46
Consolidated Statements of Cash Flows
47
Consolidated Statements of Stockholders’ Equity
48
Notes to Consolidated Financial Statements
49
Selected Quarterly Financial Data (Note 14 to Consolidated Financial Statements)
75
Information about Oil and Gas Producing Activities (Note 15 to Consolidated Financial Statements)
76
Management’s Report on Internal Control over Financial Reporting
80
Reports of Independent Registered Public Accounting Firm
81
Item 9.
CHANGES
IN AND DISAGREEMENTS
WITH ACCOUNTANTS
ON ACCOUNTING
AND FINANCIAL DISCLOSURE
There have been no changes in accountants or any disagreements with accountants on any matter of accounting principles or practices or financial
statement disclosures during the two years ended December 31, 2004.
Item 9A.
CONTROLS
AND PROCEDURES
a) Evaluation of Disclosure Controls and Procedures
We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15
as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our
disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in our periodic
filings with the Securities and Exchange Commission. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute
assurance that all control issues and instances of fraud, if any, within our Company have been detected.
b) Management’s Report on Internal Control over Financial Reporting
Our management’s report on internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K and is incorporated by
reference herein.
c) Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are
reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B.
OTHER INFORMATION
None.
42
Table of Contents
PART III
Except for the portion of Item 10 relating to Executive Officers of the Registrant which is included in Part I of this Report or is included below, the
information called for by Items 10 through 14 is incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement to be filed with the
Securities and Exchange Commission no later than April 29, 2005.
Item 10.
DIRECTORS
AND EXECUTIVE OFFICERS
OF THE REGISTRANT
We have a Code of Business Conduct and Ethics that applies to all directors, officers and employees, including the chief executive officer and senior
financial officers. We also have a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. You can find our Code of Business Conduct and
Ethics and our Code of Ethics for the Chief Executive Officer and Senior Financial Officers on our web site at http://www.xtoenergy.com. You can also obtain a
free copy of these materials by contacting us at 810 Houston Street, Fort Worth, Texas 76102, Attn: Corporate Secretary. Any amendments to or waivers from
these codes that apply to our executive officers will be posted on the Company’s web site or by other appropriate means in accordance with the rules of the
Securities and Exchange Commission.
Item 11.
EXECUTIVE COMPENSATION
Item 12.
SECURITY OWNERSHIP
Item 13.
CERTAIN RELATIONSHIPS
Item 14.
PRINCIPAL ACCOUNTANT FEES
OF
CERTAIN BENEFICIAL OWNERS
AND
AND
RELATED TRANSACTIONS
AND
SERVICES
43
MANAGEMENT
Table of Contents
PART IV
Item 15.
(a)
EXHIBITS
AND
FINANCIAL STATEMENT SCHEDULES
The following documents are filed as a part of this report:
Page
1.
2.
(b)
Financial Statements:
Consolidated Balance Sheets at December 31, 2004 and 2003
Consolidated Income Statements for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002
Management’s Report on Internal Control over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Financial Statement Schedules:
Schedule II - Consolidated Valuation and Qualifying Accounts
All other financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial
statements or the notes to consolidated financial statements.
Exhibits
See Index to Exhibits at page 85 for a description of the exhibits filed as a part of this report. Documents filed prior to June 1, 2001, were filed with the
Securities and Exchange Commission under our prior name, Cross Timbers Oil Company.
44
45
46
47
48
49
80
81
83
Table of Contents
XTO ENERGY INC.
Consolidated Balance Sheets
December 31
2004
2003
(in thousands, except shares)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable, net
Derivative fair value
Current income tax receivable
Deferred income tax benefit
Other
$
Total Current Assets
6,871,245
61,170
106,031
4,253,221
12,627
70,494
7,038,446
(1,414,068)
4,336,342
(1,024,275)
5,624,378
3,312,067
—
49,029
646
37,258
49,029
37,904
$ 6,110,372
$ 3,611,134
$
$
Net Property and Equipment
Other Assets:
Other
Total Other Assets
Total Current Liabilities
Long-term Debt
Other Long-term Liabilities:
Deferred income taxes payable
Asset retirement obligation
Other
Total Other Long-term Liabilities
Commitments and Contingencies (Note 6)
Stockholders’ Equity:
Common stock ($.01 par value, 500,000,000 shares authorized, 348,428,489 and 312,335,137 shares issued)
Additional paid-in capital
Treasury stock, at cost (1,250,266 and -0- shares)
Retained earnings
Accumulated other comprehensive income (loss)
Total Stockholders’ Equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
See accompanying notes to consolidated financial statements.
6,995
193,666
11,351
4,503
32,455
12,193
261,163
Total Property and Equipment
Accumulated depreciation, depletion and amortization
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities
Payable to royalty trusts
Other
$
436,965
Property and Equipment, at cost – successful efforts method:
Producing properties
Undeveloped properties
Other
TOTAL ASSETS
9,700
333,134
14,713
9,089
22,613
47,716
415,350
9,823
75,534
259
218,710
4,848
96,653
346
500,966
320,557
2,042,732
1,252,000
11,179
756,369
159,948
39,805
18,044
426,730
93,379
34,782
967,301
572,935
3,484
1,410,135
(24,917)
1,239,553
(28,882)
3,123
753,120
—
762,640
(53,241)
2,599,373
1,465,642
$ 6,110,372
$ 3,611,134
45
Table of Contents
XTO ENERGY INC.
Consolidated Income Statements
2004
2003
2002
$ 1,613,135
318,800
18,380
(2,714)
$ 1,040,370
135,058
12,982
1,145
$ 681,147
115,324
11,622
2,070
1,947,601
1,189,555
810,163
245,892
174,007
10,513
406,749
7,592
6,586
165,092
11,889
164,864
104,654
1,811
284,006
5,330
9,350
107,675
10,201
129,182
57,225
2,186
204,109
—
9,114
62,114
(2,599)
Total Expenses
1,028,320
687,891
461,331
OPERATING INCOME
919,281
501,664
348,832
OTHER INCOME (EXPENSE)
Gain on distribution of royalty trust units
Loss on extinguishment of debt
Interest expense, net
—
—
(93,661)
16,216
(9,601)
(63,769)
—
(8,528)
(53,555)
(93,661)
(57,154)
(62,083)
INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE
INCOME TAX EXPENSE
825,620
317,738
444,510
158,009
286,749
100,690
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE
Cumulative effect of accounting change, net of tax
507,882
—
286,501
1,778
186,059
—
$ 186,059
(in thousands, except per share data)
REVENUES
Gas and natural gas liquids
Oil and condensate
Gas gathering, processing and marketing
Other
Total Revenues
EXPENSES
Production
Taxes, transportation and other
Exploration
Gas gathering and processing
General and administrative
Derivative fair value (gain) loss
Total Other Expense
NET INCOME
EARNINGS PER COMMON SHARE
Basic:
Net income before cumulative effect of accounting change
Net income
Diluted:
Net income
507,882
$
288,279
$
1.53
—
$
0.95
0.01
$
0.67
—
$
1.53
$
0.96
$
0.67
$
1.51
—
$
0.94
0.01
$
0.66
—
$
1.51
$
0.95
$
0.66
332,907
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
46
$
299,665
277,834
Table of Contents
XTO ENERGY INC.
Consolidated Statements of Cash Flows
2004
2003
2002
(in thousands)
OPERATING ACTIVITIES
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Non-cash incentive compensation
Deferred income tax
Gain on distribution of royalty trust units
Non-cash derivative fair value loss
Loss on extinguishment of debt
Non-cash settlement gain with Enron Corporation, and related revenue
Other non-cash items
Changes in operating assets and liabilities (a)
$
$
406,749
7,592
67,184
272,672
—
6,652
—
—
—
6,366
(58,205)
Cash Provided by Operating Activities
INVESTING ACTIVITIES
Proceeds from sale of property and equipment
Property acquisitions
Development and capitalized exploration costs
Other property and asset additions
Cash Used by Investing Activities
FINANCING ACTIVITIES
Proceeds from long-term debt
Payments on long-term debt
Net proceeds from common stock offering
Dividends
Senior note offering and debt costs
Proceeds from exercise of stock options and warrants
Payments upon exercise of stock options
Subordinated note redemption costs
Purchases of treasury stock and other
$
Cash and Cash Equivalents, December 31
(a) Changes in Operating Assets and Liabilities
Accounts receivable
Other current assets
Other operating assets
Enron Btu swap contract
Current liabilities
186,059
1,216,892
794,181
490,842
25,265
(1,905,109)
(599,458)
(38,959)
—
(653,742)
(459,762)
(21,730)
149
(358,087)
(370,558)
(8,321)
(2,518,261)
(1,135,234)
(736,817)
3,883,423
(3,093,000)
580,272
(19,824)
(13,869)
7,973
(13,030)
—
(27,871)
1,835,000
(1,701,170)
247,972
(6,640)
(7,797)
16,248
(18,183)
(7,139)
(25,197)
1,156,000
(893,830)
—
(4,984)
(8,381)
23,745
(1,440)
(3,794)
(13,197)
333,094
9,700
254,119
(7,959)
14,954
8,144
6,810
$
6,995
$
14,954
$
(131,817)
(39,791)
4,153
—
109,250
$
(49,628)
(5,523)
1,103
—
57,784
$
(19,088)
2,758
4,293
(43,272)
32,433
$
(58,205)
$
3,736
$
(22,876)
47
$
204,109
—
26,990
100,368
—
6,890
—
8,528
(16,142)
(3,084)
(22,876)
2,705
6,995
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
Cash and Cash Equivalents, January 1
288,279
284,006
5,330
53,123
157,715
(16,216)
10,771
(1,778)
9,601
—
(386)
3,736
1,304,074
Cash Provided by Financing Activities
507,882
Table of Contents
XTO ENERGY INC.
Consolidated Statements of Stockholders’ Equity
Additional
Paid-in
Common
Stock
Retained
Treasury
Stock
Capital
Earnings
Accumulated
Other
Comprehensive
Income
(Loss)
Total
(in thousands, except per share amounts)
$ 2,933
Balances, December 31, 2001
Net income
Change in hedge derivative fair value, net of applicable income
tax of $51,543
Hedge derivative contract settlements reclassified into earnings
from accumulated other comprehensive income, net of
applicable income tax of $19,647
$
483,481
$
(64,714)
$
328,712
$
186,059
70,638
—
$
821,050
—
—
—
—
—
—
—
(95,723)
(95,723)
—
—
—
—
(36,488)
(36,488)
Comprehensive income
186,059
53,848
Issuance/vesting of performance shares
Stock option and warrant exercises, including income tax
benefits
Treasury stock purchases
Common stock dividends ($0.018 per share)
Net income
tax of $65,850
22
25,596
(10,276)
—
—
15,342
61
—
—
24,071
—
—
(35)
(1,536)
—
—
—
(5,015)
—
—
—
24,097
(1,536)
(5,015)
3,016
533,148
(76,561)
509,756
(61,573)
288,279
—
907,786
—
—
—
—
—
—
—
(122,293)
(122,293)
—
—
—
—
130,625
130,625
288,279
296,611
Issuance/vesting and forfeiture of performance shares
Stock option exercises, including income tax benefits
Common stock offering
Fair value of royalty trust unit distribution
Cancellation of treasury stock
45
44
—
230
—
—
(212)
51,080
22,919
—
247,742
—
—
(101,769)
3,123
Net income
tax of $51,063
(23,124)
—
(2,296)
—
—
—
101,981
753,120
—
—
—
—
(28,151)
(7,244)
—
—
762,640
507,882
—
—
—
—
—
—
—
(53,241)
—
28,001
22,963
(2,296)
247,972
(28,151)
(7,244)
—
1,465,642
—
—
—
—
—
—
—
(85,023)
(85,023)
—
—
—
—
109,382
109,382
507,882
532,241
Issuance/vesting of performance shares
Stock option exercises, including income tax benefits
25
19
—
317
—
$ 3,484
64,358
12,702
—
579,955
—
$
1,410,135
(24,105)
—
(812)
—
—
$
(24,917)
48
—
—
—
—
(30,969)
$
1,239,553
—
—
—
—
—
$
(28,882)
40,278
12,721
(812)
580,272
(30,969)
$ 2,599,373
Table of Contents
XTO ENERGY INC.
1. Organization and Summary of Significant Accounting Policies
XTO Energy Inc., a Delaware corporation, was organized under the name Cross Timbers Oil Company in October 1990 to ultimately acquire the business
and properties of predecessor entities that were created from 1986 through 1989. Cross Timbers Oil Company completed its initial public offering of common
stock in May 1993 and changed its name to XTO Energy Inc. in June 2001.
The accompanying consolidated financial statements include the financial statements of XTO Energy Inc. and all of its wholly owned subsidiaries. All
significant intercompany balances and transactions have been eliminated in the consolidation. In preparing the accompanying financial statements, management
has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ
from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.
All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the four-for-three stock split to be
effected on March 15, 2005, the five-for-four stock split effected March 17, 2004 and the four-for-three stock split effected on March 18, 2003.
We are an independent oil and gas company with production and exploration concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico,
Colorado, Wyoming, Alaska, Utah and Louisiana. We also gather, process and market gas, transport and market oil and conduct other activities directly related to
our oil and gas producing activities.
Property and Equipment
We follow the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory
wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and
development of proved reserves as opposed to exploration activities. A significant portion of the property costs reflected in the accompanying consolidated
balance sheets are from acquisitions of producing properties from other oil and gas companies. Producing properties balances include costs of $139.4 million at
December 31, 2004 and $80.6 million at December 31, 2003 related to wells in process of drilling. Drill well costs are transferred to producing properties
generally within one month of the well completion date. See Note 15 for information regarding exploratory well costs. Inventory held for future use on our
producing properties totaled $34.7 million at December 31, 2004 and $6.5 million at December 31, 2003, and is included in other current assets on the
consolidated balance sheet.
Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas
reserves. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives which range from 3 to 40 years.
Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.
If conditions indicate that long-term assets may be impaired, the carrying value of property is compared to management’s future estimated pre-tax cash
flow from properties generally aggregated on a field-level basis. If impairment is necessary, the asset carrying value is written down to fair value. Cash flow
pricing estimates are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Impairment
of individually significant undeveloped properties is assessed on a property-by-property basis, and impairment of other undeveloped properties is assessed and
amortized on an aggregate basis.
49
Table of Contents
Asset Retirement Obligation
Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143
provides that, if the fair value for asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil
and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the retirement obligation is
recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the balance sheet. Periodic
accretion of discount of the estimated liability is recorded as an expense in the income statement. Prior to adoption of SFAS No. 143, we accrued for any
estimated asset retirement obligation, net of estimated salvage value, as part of our calculation of depletion, depreciation and amortization. This method resulted
in recognition of the obligation over the life of the property on a unit-of-production basis, with the estimated obligation netted in property cost as part of the
accumulated depreciation, depletion and amortization balance. See Note 5.
Royalty Trusts
We created Cross Timbers Royalty Trust in February 1991 and Hugoton Royalty Trust in December 1998 by conveying defined net profits interests in
certain of our properties. Units of both trusts are traded on the New York Stock Exchange. We make monthly net profits payments to each trust based on
revenues and costs from the related underlying properties. We own 54.3% of Hugoton Royalty Trust, which is the portion we retained following our sale of units
in 1999 and 2000. The cost of our interest in Hugoton Royalty Trust is included in producing properties. We owned 22.7% of Cross Timbers Royalty Trust as a
result of units we purchased on the open market from 1996 through 1998. In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross
Timbers Royalty Trust for each share of our common stock outstanding on September 2, 2003. Our Cross Timbers Royalty Trust units were distributed to our
common stockholders on September 18, 2003, after which we no longer own any Cross Timbers Royalty Trust units. We recorded this dividend at $28.2 million,
the fair market value of the units on the date of distribution, resulting in a gain on distribution of $16.2 million. Amounts due the trusts, net of amounts retained
by our ownership of trust units, are deducted from our revenues, taxes, production expenses and development costs.
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.
Income Taxes
We record deferred income tax assets and liabilities to recognize timing differences between recognition of income for financial statement and income tax
reporting purposes. Deferred income tax assets are calculated using enacted tax rates applicable to taxable income in the years when we anticipate these timing
differences will reverse. The effect of changes in tax rates is recognized in the period of enactment. See New Accounting Pronouncements below.
Other Assets
Other assets primarily include deferred debt costs that are amortized to interest expense over the term of the related debt (Note 3) and the long-term portion
of gas balancing receivable (see Revenue Recognition and Gas Balancing below). We do not have any goodwill or significant intangible assets that are subject to
potential impairment assessment. Other assets are presented net of accumulated amortization of $13.3 million at December 31, 2004 and $19. 8 million at
December 31, 2003.
Derivatives
We use derivatives to hedge against changes in cash flows related to product price and interest rate risks, as opposed to their use for trading purposes.
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet at fair value. We
generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the
50
Table of Contents
underlying market price at the determination date. The fair value of call options and collars are generally determined under the Black-Scholes option-pricing
model. Most values are confirmed by counterparties to the derivative.
Realized and unrealized gains and losses on derivatives that are not designated as hedges, as well as on the ineffective portion of hedge derivatives, are
recorded as a derivative fair value gain or loss in the income statement. Unrealized gains and losses on effective cash flow hedge derivatives, as well as any
deferred gain or loss realized upon early termination of effective hedge derivatives, are recorded as a component of accumulated other comprehensive income
(loss). When the hedged transaction occurs, the realized gain or loss, as well as any deferred gain or loss, on the hedge derivative is transferred from accumulated
other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivatives are recognized in oil and gas revenues, and realized
gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Settlements of derivatives are included in cash flows from
operating activities.
To summarize, we record our derivatives at fair value in our consolidated balance sheets. Gains and losses resulting from changes in fair value and upon
settlement are recorded as follows:
Derivative Type
Fair Value
Gains/
Losses
Non-hedge derivatives
and
Hedge derivatives –
ineffective portion
Unrealized
and
Realized
in the Consolidated Income Statements
Unrealized
Accumulated other comprehensive income (loss)
in Stockholders’ Equity in the Consolidated Balance Sheets
Realized
Hedged item as classified in the Consolidated Income Statements
(e.g., gas revenue, oil revenue or interest expense)
Hedge derivatives –
effective portion
Financial Statement Classification
To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in
offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent
relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change
in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer
highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses on the effective portion of the derivative are
reclassified to earnings as oil or gas revenue or interest expense when the underlying transaction occurs. If it is determined that the designated hedge transaction
is not likely to occur, any unrealized gains or losses are recognized immediately in the income statement as a derivative fair value gain or loss.
In conjunction with our hedging activities, we occasionally sell natural gas call options. Because sold options do not provide protection against declining
prices, they do not qualify for hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectively provided by
selling the call options, is recognized as a derivative fair value loss, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged
production occurs, as prescribed by hedge accounting.
Physical delivery contracts that are not expected to be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives.
However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a
non-hedge derivative (Note 8).
Revenue Recognition and Gas Balancing
Oil, gas and natural gas liquids revenues are recognized when the products are sold and delivery to the purchaser has occurred. At times we may sell more
or less than our entitled share of gas production. When this happens, we use
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the entitlement method of accounting for gas sales, based on our net revenue interest in production. Accordingly, revenue is deferred for gas deliveries in excess
of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in
effect at the time of production. The consolidated balance sheets include the following amounts related to production imbalances:
December 31
2004
Amount
2003
Mcf
Amount
Mcf
(in thousands)
Accounts receivable - current underproduction
Accounts payable - current overproduction
$
Net current gas underproduction balancing receivable
$
Other assets - noncurrent underproduction
Other long-term liabilities - noncurrent overproduction
$
Net long-term gas overproduction balancing payable
30,780
8,116 $ 23,949
7,135
(24,087) (6,388)
(19,366) (5,900)
6,693
1,728
$
1,985
Net long-term overproduction balancing payable
1,235
17,723
4,868 $ 19,385
6,148
(33,262) (9,063)
(29,776) (9,353)
(15,539) (4,195)
Other assets - noncurrent carbon dioxide underproduction
4,583
$ (13,554)
(10,391) (3,205)
12,480
1,977
$
12,354
(8,414)
Gas Gathering, Processing and Marketing Revenues
We market our gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users. Gas gathering and marketing
revenues are recognized in the month of delivery based on customer nominations. Gas processing and marketing revenues are recorded net of cost of gas sold of
$98.3 million for 2004, $66.3 million for 2003 and $55.6 million for 2002. These amounts are net of intercompany eliminations.
Other Revenues
Other revenues result from and are related to our ongoing major operations. These revenues include various gains and losses, including from lawsuits and
other disputes, as well as from other than significant sales of property and equipment.
Loss Contingencies
We account for loss contingencies in accordance with SFAS No. 5, Accounting for Contingencies. Accordingly, when management determines that it is
probable that an asset has been impaired or a liability has been incurred, we accrue our best estimate of the loss if it can be reasonably estimated. Our legal costs
related to litigation are expensed as incurred. See Note 6.
Interest
Interest expense includes amortization of deferred debt costs and is presented net of interest income of $402,000 in 2004, $553,000 in 2003 and $836,000
in 2002, and net of capitalized interest of $2.6 million in 2004, $2.2 million in 2003 and $4.3 million in 2002. Interest is capitalized as producing property cost
based on the weighted average interest rate and the cost of wells in process of drilling. Included in accounts payable and accrued liabilities is accrued interest of
$26.6 million at December 31, 2004 and $11.5 million at December 31, 2003.
Stock-Based Compensation
In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation is recorded for stock
options or other stock-based awards that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on
the grant date. Compensation related to performance share grants with time vesting conditions is based on the fair value of the award at the grant date and
recognized over the vesting period. Compensation related to performance shares with price target vesting is
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recognized over the estimated vesting period if management believes it is able to reasonably estimate a vesting date or, if earlier, when the price target is reached.
See New Accounting Pronouncements below and Note 12.
As required to be disclosed pursuant to SFAS No. 148, Accounting for Stock-Based Compensation–Transition and Disclosure, the following is the pro
forma effect of recording stock-based compensation at the estimated fair value of awards on the grant date, as prescribed by SFAS No. 123, Accounting for
Stock-Based Compensation:
2004
2003
2002
Net income as reported
Add stock-based compensation expense included in the income statement, net of related tax effects
Deduct stock-based employee compensation expense determined under fair value method for all awards, net of related
tax effects
$ 507,882
56,368
$ 288,279
34,530
$ 186,059
17,543
Pro forma net income
$ 487,391
$ 289,311
$ 183,840
Earnings per common share:
Basic - as reported
$
1.53
$
0.96
$
0.67
Basic - pro forma
$
1.46
$
0.96
$
0.66
Diluted - as reported
$
1.51
$
0.95
$
0.66
Diluted - pro forma
$
1.45
$
0.95
$
0.65
(76,859)
(33,498)
(19,762)
Earnings per Common Share
In accordance with SFAS No. 128, Earnings Per Share, we report basic earnings per common share, which excludes the effect of potentially dilutive
securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. See Note 10.
Segment Reporting
In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, we evaluated how the Company is organized
and managed, and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. We consider
our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. All of our assets are located in the United States, and all
revenues are attributable to United States customers.
Our production is sold to various purchasers, based on their credit rating and location of our production. For the year ended December 31, 2004, sales to
each of two purchasers were approximately 20% and 13% of total revenues. For the year ended December 31, 2003, sales to each of three purchasers were
approximately 25%, 15% and 12% of total revenues. For the year ended December 31, 2002, sales to each of two purchasers were approximately 10% of total
revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these
significant purchasers. We currently have greater concentrations of credit with several A- or better rated integrated energy companies.
New Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board issued SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion
No. 29, which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged,
and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows.
Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion 29 previously exempted all
exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. We must implement SFAS
153 for any
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nonmonetary asset exchanges occurring on or after January 1, 2006. This change in accounting is currently not expected to have a significant effect on our
reported financial position or earnings.
In December 2004, the FASB issued Staff Position FAS 109-1 that concluded that the special tax deduction allowed under the American Jobs Creation Act
of 2004 should be accounted for as a “special deduction” instead of a tax rate reduction as provided by SFAS 109. Accordingly, any tax relief the Company
receives under the new tax law will be recorded as a reduction of current tax when realized, rather than an immediate reduction to its accrued deferred income tax
liability.
Also in December 2004, the FASB issued SFAS No. 123 (Revised 2004), Share-Based Payment, which requires that compensation related to all
stock-based awards, including stock options, be recognized in the financial statements. This pronouncement replaces SFAS No. 123, Accounting for Stock-Based
Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and will be effective beginning July 1, 2005. We have
previously recorded stock compensation pursuant to the intrinsic value method under APB No. 25, whereby no compensation was recognized for most stock
option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and, therefore, SFAS No. 123R will have a
significant impact on our financial statements. For the pro forma effect of recording compensation for all stock awards at fair value, utilizing the Black-Scholes
method, see Stock-Based Compensation above. We are currently considering alternative valuation methods to determine stock award fair value for grants after
June 30, 2005. We plan to use the modified prospective application method of adopting SFAS No. 123R, whereby the estimated fair value of unvested stock
awards granted prior to July 1, 2005 will be recognized as compensation expense in periods subsequent to June 30, 2005, based on the estimated service period.
The fair value of awards granted prior to July 1, 2005 will be the same value as determined under the Black–Scholes method for our pro forma disclosure under
Stock-Based Compensation above. As of February 22, 2005, all stock options outstanding at that date vested when the common stock price closed above the
target price level of $31.88, resulting in no compensation expense to be recognized after June 30, 2005 related to these awards.
2. Related Party Transactions
A firm, partially owned by one of our directors, has performed property acquisition advisory services for the Company. We paid this firm total fees of $8.8
million in 2004 and $2.4 million in 2002, and there were no amounts payable at December 31, 2004 or 2003. No fees were paid to this firm in 2003. This same
director-related company represented the seller of properties for acquisitions totaling approximately $186 million that we closed in January 2004. In February
2005, this firm was acquired by another company with which we expect to continue to have a relationship.
A portion of the producing properties obtained in the ChevronTexaco acquisition (Note 13) were considered nonstrategic and marked for disposition at the
time of purchase. In August 2004, we exchanged $37.8 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett
Shale of North Texas, and $25.4 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a
brother of Bob R. Simpson, Chairman and Chief Executive Officer of the Company. In connection with this exchange, we granted these companies an option to
purchase other properties included in the ChevronTexaco acquisition. On March 1, 2005, these companies purchased the properties for an adjusted purchase price
of $11.5 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.
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3. Debt
Our long-term debt consists of the following:
December 31
2004
2003
(in thousands)
Bank debt:
Revolving credit agreement due February 2009, 3.49% at December 31, 2004
Term loan due April 2010, 3.17% at December 31, 2004
Senior notes:
7½%, due April 15, 2012
6¼%, due April 15, 2013
4.9%, due February 1, 2014, net of discount
5%, due January 31, 2015, net of discount
Total long-term debt
$
146,000
300,000
$
502,000
—
350,000
400,000
497,012
349,720
350,000
400,000
—
—
$ 2,042,732
$ 1,252,000
Other than borrowings under our revolving credit agreement, no debt matures within five years. Before the February 2009 maturity, we may renegotiate
the revolving credit agreement to increase the borrowing commitment and extend the maturity.
Bank Debt
In February 2004, we fully repaid our revolving facility and entered a new five-year revolving credit agreement with commercial banks that matures in
February 2009. The agreement currently provides for a maximum commitment amount of $1 billion, and an interest rate based on London Interbank Offered
Rates (“LIBOR”) plus 1%. The loan agreement provides the option of borrowing at floating interest rates based on the prime rate, certificate of deposit rates, or
LIBOR. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing
commitments, which was 0.20% at February 2005. The agreement requires us to maintain a ratio of debt-to-total capitalization of not more than 60%.
Borrowings under the loan agreement may be prepaid at any time without penalty. The weighted average interest rate on bank debt was 2.6% during 2004 and
2003 and 3.2% during 2002.
In November 2004, we entered a $300 million five-year term loan due April 2010 with an initial interest rate of LIBOR plus 0.75%. Other terms and
conditions are substantially the same as our revolving credit agreement.
Senior Notes
In April 2002, we sold $350 million of 7½% senior notes due in April 2012, with interest payable each April 15 and October 15. Net proceeds of $341.6
million were used to finance property transactions (Note 13), to redeem our 9¼% senior subordinated notes and to reduce bank debt.
In April 2003, we sold $400 million of 6¼% senior notes due in April 2013, with interest payable each April 15 and October 15. Net proceeds of $393.4
million, combined with proceeds from the concurrent sale of common stock (Note 9), were used to finance our producing property acquisition from units of
Williams of Tulsa, Oklahoma (Note 13), to redeem our 8¾% senior subordinated notes and to reduce bank debt.
In January 2004, we sold $500 million of 4.9% senior notes that were issued at 99.34% of par to yield 4.98% to maturity. The notes mature on February 1,
2014 and interest is payable each February 1 and August 1. Net proceeds of $490 million were used to fund our January 2004 property acquisitions of $243
million (Note 13) and to reduce bank debt.
In September 2004, we sold $350 million of 5% notes that were issued at 99.918% of par to yield 5.011% to maturity pursuant to Rule 144A under the
Securities Act of 1933, which allows unregistered transactions with qualified institutional buyers. Through March 14, 2005, noteholders can exchange these
notes with notes that were registered with
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the Securities and Exchange Commission in February 2005. The notes are due in January 2015 and interest is payable each January 31 and July 31. Net proceeds
of $347 million were used to reduce bank debt associated with our 2004 acquisitions.
The senior notes require no sinking fund. We may redeem all or a part of the senior notes at any time at a price of 100% of their principal balance plus
accrued interest and a make-whole premium payment. The make-whole premium is calculated as any excess over the principal balance of the present value of
remaining principal and interest payments at the U.S. Treasury rate for a comparable maturity plus no more than 0.15%.
Subordinated Debt
In April 1997, we sold $125 million of 9¼% senior subordinated notes due April 2007, and in October 1997, we sold $175 million of 8¾% senior
subordinated notes due November 2009. Under the terms of an agreement with a bank counterparty, we purchased and canceled $9.7 million of 9¼% senior
subordinated notes in April 2002, and we purchased and canceled $11.8 million of 8¾% senior subordinated notes in November 2002. In June 2002, we
redeemed the remaining $115.3 million 9¼% notes at a redemption price of 104.625%, or $120.6 million, plus accrued interest of $1.8 million. In May 2003, we
redeemed the remaining $163.2 million of our 8¾% senior subordinated notes at a redemption price of 104.375%, or $170.3 million, plus accrued interest of
approximately $700,000. As a result of these transactions, we recorded a loss on extinguishment of debt of $8.5 million in 2002 and $9.6 million in 2003.
4. Income Tax
The following reconciles our income tax expense to the amount calculated at the statutory federal income tax rate:
2004
2003
2002
Income tax expense at the federal statutory rate (35%)
State and local income taxes and other
$ 288,967
28,771
$ 155,579
2,430
$ 100,362
328
Income tax expense
$ 317,738
$ 158,009
$ 100,690
2004
2003
2002
(in thousands)
Components of income tax expense are as follows:
(in thousands)
Current income tax
Deferred income tax
Net operating loss carryforwards (added) used
$ 45,066
184,927
87,745
$
294
148,304
9,411
Income tax expense
$ 317,738
$ 158,009
$
322
121,396
(21,028)
$ 100,690
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and
liabilities. Our net deferred tax assets and liabilities are recorded as a current asset of $22.6 million and a long-term liability of $756.4 million at December 31,
2004 and as a current asset of $32.5 million and a long-term liability of $426.7 million at December 31, 2003. Significant components of net deferred tax assets
and liabilities are:
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December 31
2004
2003
(in thousands)
Deferred tax assets:
Net operating loss carryforwards
Alternative minimum tax credit carryforwards
Derivative fair value loss
Other
$
Total deferred tax assets
Deferred tax liabilities:
Property and equipment
Derivative fair value gain
Other
Total deferred tax liabilities
Net deferred tax liabilities
—
37,762
31,217
11,427
$
84,001
429
40,144
6,304
80,406
130,878
801,610
5,297
7,255
509,877
4,199
11,077
814,162
525,153
$ (733,756)
$ (394,275)
We have estimated that all our net operating loss carryforwards will be fully utilized as of December 31, 2004. While our alternative minimum tax credit
carryforwards do not have an expiration date, we expect to fully utilize them in 2005.
5. Asset Retirement Obligation
Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, recording a cumulative effect of accounting change
gain, net of tax, of $1.8 million. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and
remediate our producing properties (including removal of our offshore platforms in Alaska) at the end of their productive lives, in accordance with applicable
state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a
summary of the asset retirement obligation activity for the years ended December 31, 2004 and 2003:
2004
2003
Asset retirement obligation, January 1
Revisions in the estimated cash flows
Liability incurred upon acquiring and drilling wells
Liability settled upon plugging and abandoning wells
Accretion of discount expense
$ 93,379
5,978
53,886
(887)
7,592
$ 75,256
—
13,879
(1,086)
5,330
Asset retirement obligation, December 31
$ 159,948
$ 93,379
(in thousands)
Based on the same assumptions used in the calculation of our asset retirement obligation at January 1, 2003, we estimate that this obligation would have
been $62.2 million at January 1, 2002 if we had adopted SFAS No. 143 as of that date. The estimated pro forma effect of earlier adoption on 2002 net income
and earnings per share is not material.
6. Commitments and Contingencies
Leases
We lease compressors, offices, vehicles, aircraft and certain other equipment in our primary locations under noncancelable operating leases. Commitments
related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2004, minimum future lease payments for
all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows:
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(in thousands)
2005
2006
2007
2008
2009
Remaining
$ 30,200
23,882
22,806
18,605
15,964
39,666
Total
$151,123
Amounts incurred under operating leases (including renewable monthly leases) were $34.6 million in 2004, $31.7 million in 2003 and $26.6 million in
2002.
In March 1996, we sold our Tyrone gas processing plant and related gathering system for $28 million and entered an agreement to lease the facility from
the buyers for an initial term of eight years at annual rentals of $4 million with fixed renewal options for an additional 13 years at a total cost of $7.8 million.
This transaction was recorded as a sale and operating leaseback, with no gain or loss on the sale. In March 2004, we extended the lease until March 2006.
In November 1996, we sold a gathering system in Major County, Oklahoma for $8 million and entered an agreement to lease the facility from the buyers
for an initial term of eight years, with fixed renewal options for an additional ten years. This transaction was recorded as a sale and operating leaseback, with a
deferred gain of $3.4 million on the sale. The deferred gain is amortized over the lease term based on pro rata rentals and is recorded in other long-term liabilities
in the accompanying consolidated balance sheets. The deferred gain balance at December 31, 2004 was $600,000. In November 2004, we extended the lease
until November 2006.
Under each of the above sale and leaseback transactions, we do not have the right or option to purchase, nor does the lessor have the obligation to sell, the
facility at any time. However, if the lessor decides to sell the facility at the end of the initial term or any renewal period, the lessor must first offer to sell it to us
at its fair market value. Additionally, we have the right of first refusal of any third party offers to buy the facility after the initial term.
Transportation Contracts
We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum daily gas volumes or
pay for any deficiencies at a specified reservation fee rate. As calculated on a monthly basis, our failure to deliver these minimum volumes to the pipeline
requires us to pay the pipeline for any deficiency. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the
contracts. We have generally delivered at least minimum volumes under our firm transportation contracts, therefore avoiding payment for deficiencies. As of
December 31, 2004, maximum commitments under our transportation contracts were as follows:
(in thousands)
2005
2006
2007
2008
2009
Remaining
$ 21,935
22,463
19,741
18,804
18,030
36,368
$137,341
Guarantees
Under the terms of some of our operating leases for compressors, airplanes and vehicles, we have various residual value guarantees and other payment
provisions upon our election to return the equipment under certain specified conditions. As of December 31, 2004, we estimate the total contingent payable under
these guarantees does not exceed $5 million. Guarantees related to leases entered during 2004 and 2003 were not material.
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Employment Agreements
Two executive officers have year-to-year employment agreements with us. The agreements are automatically renewed each year-end unless terminated by
either party upon thirty days notice prior to each December 31. Under these agreements, the officers receive a minimum annual salary of $625,000 and $450,000,
respectively, and are entitled to participate in any incentive compensation programs administered by the Board of Directors. The agreements also provide that, in
the event the officer terminates his employment for good reason, as defined in the agreement, we terminate the employee without cause or a change in control of
the Company occurs, the officer is entitled to a lump-sum payment of three times the officer’s most recent annual compensation, including any special bonuses or
other compensation required to be designated as a bonus under the rules and regulations of the Securities and Exchange Commission. In addition, the officer is
entitled to receive a payment sufficient to make the officer whole for any excise tax on excess parachute payments imposed by the Internal Revenue Code.
Commodity Commitments
We have entered into futures contracts, collars and swap agreements that effectively fix gas and oil prices. See Note 8.
Drilling Contracts
As of December 31, 2004, we have contracts to use 32 drilling rigs in 2005 with total commitments of $99.1 million. Early termination of these contracts
at December 31, 2004 would have required us to pay maximum penalties of $34.7 million.
Litigation
On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U.S. District
Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against
the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by
Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly
valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses),
civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring
practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States
District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision
was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional
prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending
that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion has been scheduled for March 2005. While we
are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any
potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.
In June 2001, we were served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. (formerly Quinque case). The action was filed in the District Court
of Stevens County, Kansas, against us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors
of natural gas. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and
royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974.
The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the
federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and
heating content of natural gas delivered into their pipelines, resulting in underpayments to the plaintiffs. The plaintiffs assert a breach of contract claim, negligent
or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of
action. The amount of damages
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was not specified in the complaint. In February 2002, we, along with one of our subsidiaries, were dismissed from the suit and another subsidiary of the
Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs’ counsel has filed an amended
class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only, conspiracy, unjust
enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in April 2005 to
determine whether the amended class should be certified. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit
are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision
has been accrued in our financial statements.
On August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al.
The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. The plaintiffs seek to represent a class of
plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January
1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content that had previously been alleged in the Price case discussed
above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the
amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies to gas
measured in Kansas, Colorado and Wyoming. The court has set an evidentiary hearing in April 2005 to determine whether the amended class should be certified.
The amount of damages was not specified in the complaint. While we are unable to predict the outcome of this case, we believe that the allegations of this
lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no
provision has been accrued in our financial statements.
In September 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District
Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs allege that the defendants have deducted in their calculation of royalty
payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable
location. The plaintiffs seek to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La
Plata County, Colorado and that are leased to or operated by Huber or us, except to the extent that the lessors or their successors have expressly authorized
deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002,
and have assumed the responsibility for certain liabilities of Huber prior to the effective date, which may include liability for post-production deductions made by
Huber. We have filed our response and intend to file a response for Huber. As of December 31, 2004, based on an evaluation of available information, we
accrued a $3.1 million estimated liability for this claim in our consolidated financial statements. On February 17, 2005, we agreed to a tentative settlement of
approximately $5.1 million, resulting in an additional loss of approximately $2 million to be recorded in first quarter 2005.
In December 2004, the U.S. Environmental Protection Agency issued a Compliance Agreement and Final Order to us, which cited certain violations
concerning the discharge of produced water and sanitary wastes into Alaska’s Cook Inlet from our two operated production platforms from January 2000 through
June 2004. We reported these discharges to the EPA as part of our offshore discharge permit monitoring. We have agreed to pay a monetary penalty of $139,000
and have accrued this amount in our financial statements.
We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management and legal
counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on our financial position or
liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.
Other
To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future.
However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
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To secure tubular goods required to support our drilling program, we have entered a contract with a tubular goods supplier who commits to deliver, at
market prices, our next quarter’s tubular products ordered by us at least 30 days prior to the beginning of the quarter. There is no minimum order requirement,
and our order is subject to modification by the supplier. The contract is cancellable by either party with at least 60 days notice prior to the beginning of the next
calendar quarter.
Through December 2004, we have acquired more than 80,000 net acres in the Barnett Shale of North Texas (Note 13). Approximately 60,000 net acres
with an estimated value of $69 million are generally subject to lease expiration if initial wells are not drilled within one year. Because we have ample resources
to meet the drilling requirements, we currently do not anticipate significant impairment of these leases.
In October 2004, we agreed to acquire an airplane for $17.1 million, either through purchase or lease, and made an initial payment of $6.8 million. We
expect to take delivery of the airplane in the first half of 2005.
7. Financial Instruments
We use financial and commodity-based derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or
issue derivative financial instruments for speculative or trading purposes. We also may enter gas physical delivery contracts to effectively provide gas price
hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these
contracts are not recorded in the financial statements.
All derivatives are recorded on the balance sheet at estimated fair value. Fair value is generally determined based on the difference between the fixed
contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the fair value of effective
cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to earnings when the hedged
transaction occurs. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of the hedge derivatives, are
recorded in derivative fair value (gain) loss in the income statement. This ineffective portion is calculated as the difference between the change in fair value of
the derivative and the estimated change in cash flows from the item hedged. Btu swap contracts do not qualify for hedge accounting.
Btu Swap Contracts
In 1995, we entered a contract to sell gas based on crude oil pricing, also referred to as the Enron Btu swap contract. This contract was terminated as a
result of the Enron bankruptcy in December 2001. Because the contract pricing was not clearly and closely associated with natural gas prices, it was considered a
non-hedge derivative financial instrument, with changes in fair value recorded as a derivative (gain) loss in the income statement.
Prior to termination of the Enron Btu swap contract, we entered Btu swap contracts with another counterparty to effectively defer until August 2005
through July 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. Changes
in fair value of these contracts are recorded as a derivative (gain) loss in the income statement. In March 2002, we terminated some of these contracts with
maturities of May through December 2002 and received $6.6 million from the counterparty. Because these Btu swap contracts are non-hedge derivatives, most of
the $6.6 million gain related to their termination had previously been recorded in 2001 derivative fair value gain.
Commodity Price Hedging Instruments
We periodically enter into futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on crude oil and natural gas
sales. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when actual commodity
prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged a portion of our exposure to variability
in future cash flows from crude oil and natural gas sales through December 2005. See Note 8.
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Derivative Fair Value (Gain) Loss
The components of derivative fair value (gain) loss, as reflected in the consolidated income statements are:
2004
2003
2002
Change in fair value of Btu swap contracts
Change in fair value of other derivatives that do not qualify for hedge accounting
Ineffective portion of derivatives qualifying for hedge accounting
$ 1,086
(1,685)
12,488
$ 5,115
(2,187)
7,273
$ 1,046
(6,505)
2,860
$ 11,889
$ 10,201
$ (2,599)
(in thousands)
Fair Value of Financial Instruments
Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying
values at December 31, 2004 and 2003. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:
Asset (Liability)
December 31, 2004
December 31, 2003
Carrying
Carrying
Amount
Fair Value
Amount
Fair Value
(in thousands)
Derivative Assets:
Fixed-price natural gas futures and swaps
Fixed-price crude futures and differential
Derivative Liabilities:
Fixed-price natural gas futures and swaps
Fixed-price crude futures and differential
Btu swap contracts
$
10,962
3,751
$
(41,754)
(25,879)
(19,080)
Net derivative asset (liability)
$
(72,000)
Long-term debt
$
(2,042,732)
10,962
3,751
$
(41,754)
(25,879)
(19,080)
$
11,997
—
$
(96,702)
—
(17,995)
(72,000)
$
(102,700)
$ (2,133,818)
$
(1,252,000)
11,997
—
(96,702)
—
(17,995)
$
(102,700)
$ (1,275,285)
The fair value of futures, swap and differential agreements is estimated based on the exchange-trade value of NYMEX, basis and differential contracts and
market commodity prices for the applicable future periods. The fair value of bank borrowings approximates their carrying value because of short-term interest
rate maturities. The fair value of senior notes is based on current market quotes.
Changes in fair value of derivative assets and liabilities are the result of changes in oil and gas prices. Futures and swaps are generally designated as
hedges of commodity price risks, and accordingly, changes in their values are predominantly recorded in accumulated other comprehensive income (loss) until
the hedged transaction occurs.
Concentrations of Credit Risk
Although our cash equivalents, accounts receivable and derivative assets are exposed to the risk of credit loss, we do not believe such risk to be significant.
Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of our receivables are from a diverse group of
companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. We currently have greater
concentrations of credit with several A- or better rated integrated energy companies. Financial and commodity-based swap contracts expose us to the credit risk
of nonperformance by the counterparty to the contracts. This exposure
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is diversified among major investment grade financial institutions, and we have master netting agreements with counterparties that provide for offsetting payables
against receivables from separate derivative contracts. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. Our
allowance for collectibility of all accounts receivable was $3.9 million at December 31, 2004 and $6.3 million at December 31, 2003. Our bad debt provision was
$232,000 in 2004, $1.3 million in 2003 and $980,000 in 2002. We also recorded a $2.2 million reduction in the allowance for collectibility in 2004.
8. Commodity Sales Commitments
Our policy is to routinely hedge a portion of our production at commodity prices management deems attractive. This policy assures cash flow needed for
funding our development program and provides more predictable economic returns for our acquisitions. While there is a risk we may not be able to realize the
benefit of rising prices, management plans to continue this strategy because of these benefits.
In addition to selling gas under fixed price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our
exposure to price fluctuations on natural gas and crude oil sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this
excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty.
We have hedged a portion of our exposure to variability in future cash flows from natural gas and crude oil sales through December 2005.
Natural Gas
We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be
realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 7 regarding accounting for
commodity hedges.
Production Related to
Base Production
Production Period
Mcf
per Day
Average
NYMEX
Price
per Mcf
2005 January to December
200,000
$
63
5.79
2004 Acquisitions
Mcf
per Day
50,000
Average
NYMEX
Price
per Mcf
$
6.34
Total
Mcf
per Day
250,000
Average
NYMEX
Price
per Mcf
$
5.90
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The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality
and other factors. We have entered basis swap agreements that effectively fix the basis adjustment for the following delivery locations and periods:
Delivery Location
Houston
Ship
Arkoma
Production Period
San Juan
Channel
Rockies
Basin
Total
2005
(a)
January
Mcf per day
Basis per Mcf (a)
10,000
(0.06)
$
210,000
(0.21)
$
30,000
(0.77)
$
70,000
(0.67)
320,000
$
February to March
Mcf per day
Basis per Mcf (a)
10,000
(0.06)
$
210,000
(0.21)
$
10,000
(0.71)
$
70,000
(0.67)
300,000
$
April to June
Mcf per day
Basis per Mcf (a)
—
—
270,000
(0.14)
$
5,000
(0.75)
$
30,000
(0.68)
305,000
$
July to August
Mcf per day
Basis per Mcf (a)
—
—
270,000
(0.12)
$
5,000
(0.75)
$
30,000
(0.68)
305,000
$
September
Mcf per day
Basis per Mcf (a)
—
—
250,000
(0.12)
$
5,000
(0.75)
$
30,000
(0.68)
285,000
$
October
Mcf per day
Basis per Mcf (a)
—
—
270,000
(0.14)
$
5,000
(0.75)
$
30,000
(0.68)
305,000
$
November to December
Mcf per day
Basis per Mcf (a)
—
—
220,000
(0.17)
$
10,000
(0.76)
$
40,000
(0.68)
270,000
$
Reductions to NYMEX gas prices for delivery location.
Net losses on futures and basis swap hedge contracts decreased gas revenue by $156.1 million in 2004 and $193 million in 2003. Net gains on futures and
basis swap hedge contracts increased gas revenue by $57.4 million in 2002. Including the effect of fixed price physical delivery contracts, all hedging activities
increased gas revenue by $95.4 million in 2002. There were no fixed price physical delivery contracts in 2003 or 2004. As of December 31, 2004, an unrealized
pre-tax derivative fair value loss of $28.1 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss).
This fair value loss is expected to be reclassified into earnings in 2005. The actual reclassification to earnings will be based on mark-to-market prices at the
contract settlement date.
The settlement of futures contracts and basis swap agreements related to January 2005 gas production reduced gas revenue by approximately $1.1 million,
or $0.04 per Mcf.
Crude Oil
In connection with our 2004 acquisitions from ExxonMobil Corporation and ChevronTexaco Corporation (Note 13), we entered oil futures contracts to
sell, through December 2005, 10,000 Bbls per day at an average West Texas Intermediate NYMEX price of $35.91 per Bbl and 5,000 Bbls per day at an average
West Texas Intermediate NYMEX price of $43.28 per Bbl. For 5,000 Bbls per day of production hedged at $35.91 per Bbl, we entered a crude sweet and sour
differential swap of $3.05 per Bbl, to effectively fix the price for crude sour production at $32.86 per Bbl. Prices to be realized for hedged oil production are
expected to be less than the NYMEX price because of location, quality and other adjustments.
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In 2004, net losses on futures and differential swap hedge contracts decreased oil revenue by $15.5 million. Net losses on oil futures hedge contracts
decreased oil revenue by $3.9 million in 2003. During 2002, net losses on oil futures hedge contracts decreased oil revenue by $1.3 million, while changes in fair
value of sour oil basis swap contracts resulted in a derivative fair value gain of $300,000. As of December 31, 2004, an unrealized pre-tax derivative fair value
loss of $17 million related to cash flow hedges of oil price risk was recorded in accumulated other comprehensive income (loss). This entire fair value loss is
expected to be reclassified into earnings in 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.
The settlement of futures contracts and crude sweet and sour differential swaps related to January 2005 production reduced oil revenue by approximately
$3.1 million, or $2.84 per Bbl.
Physical Delivery Contracts
From August 1995 through July 1998 we received an additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, we agreed to
sell 34,344 Mcf per day at the index price in 2001 and 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX
futures price for intermediate crude oil. See Note 7 regarding accounting for this contract, also referred to as the Enron Btu swap contract, which was terminated
as a result of the Enron bankruptcy, and regarding a related derivative commitment with another counterparty.
In addition to the Enron Btu swap contract, Enron Corporation was a purchaser of natural gas under other physical delivery contracts and was counterparty
to some of our hedge derivative contracts at the time of its bankruptcy in December 2001. In settlement of all obligations, we paid Enron $6 million in December
2002. As a result of this settlement, in 2002 we recognized $14.1 million in previously unrecognized gas revenue related to physical delivery contracts and a gain
of $2.1 million.
In 1998, we sold a production payment, payable from future production from certain properties acquired in an acquisition, to EEX Corporation for $30
million. Under the terms of the production payment conveyance and related delivery agreement, we committed to deliver to EEX a total of approximately 34.3
Bcf (27.8 Bcf net to our interest) of gas during the 10-year period beginning January 1, 2002, with scheduled deliveries by year, subject to certain variables. EEX
will reimburse us for all royalty and production and property tax payments related to such deliveries. EEX will also pay us an operating fee of $0.257 per Mcf for
deliveries, which fee will be escalated annually at a rate of 5.5%. In 2001 and 2002, we repurchased 18.3 Bcf (14.8 Bcf net) of gas under the production payment
for $20.7 million. We expect to begin delivery of the remaining 16.0 Bcf (13.0 Bcf net) of gas in 2006.
9. Equity
Stock Splits
We effected a four-for-three stock split on March 18, 2003 and a five-for-four stock split on March 17, 2004, and will effect a four-for-three stock split on
March 15, 2005. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits.
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Common Stock
The following reflects our common stock activity:
Shares Issued
2004
(in thousands)
2003
Shares in Treasury
2002
2004
2003
2002
Balance, January 1
Issuance/vesting and forfeiture of performance shares
Stock option and warrant exercises
Cancellation of treasury shares
312,335 301,633 293,308
2,448
4,444
2,224
1,937
4,456
6,101
—
—
—
31,708 23,000
—
—
(21,198)
—
—
19,462
1,216
1,585
—
—
34
151
—
—
— (21,198)
18,258
1,045
4
155
—
—
Balance, December 31
348,428 312,335
1,250
19,462
301,633
—
In May 2004, we completed a public offering of 31.7 million shares of common stock at $18.92 per share. After underwriting discount and other offering
costs of $19.7 million, net proceeds of $580.3 million were used to reduce bank borrowings that funded our producing property acquisitions from ExxonMobil
Corporation and our deposit on the ChevronTexaco acquisition (Note 13).
In April 2003, we completed a public offering of 23 million shares of common stock at $11.25 per share. After underwriting discount and other offering
costs of $10.8 million, net proceeds from the offering of $248 million and net proceeds from the concurrent sale of senior notes (Note 3) were used to fund our
producing property acquisition from units of Williams of Tulsa, Oklahoma (Note 13), to redeem our 8¾% senior subordinated notes and to reduce bank debt.
In January 2005, we announced our agreement to purchase Antero Resources Corporation, which will partially be funded by issuance of 13.3 million
shares of common stock (Note 13).
Treasury Stock
In February 2004, the Board of Directors authorized the cancellation of treasury shares as of December 31, 2003. This retirement of treasury shares is
reflected in the December 31, 2003 consolidated balance sheet, resulting in a reduction of treasury stock and additional paid-in-capital of $102 million, and a
reduction in shares in treasury and shares issued of 21.2 million shares.
In August 2004, our Board of Directors authorized the repurchase of up to 20 million shares of our common stock which may be purchased from time to
time in open market or negotiated transactions. This authorization effectively replaced the share repurchase authorization remaining from May 2000. As of
December 31, 2004, we have repurchased 33,600 shares at a cost of $812,000.
Stockholder Rights Plan
In August 1998, the Board of Directors adopted a stockholder rights plan that is designed to assure that all stockholders receive fair and equal treatment in
the event of any proposed takeover of the Company. Under this plan, one preferred share purchase right is attached to each outstanding share of common stock.
Each right entitles stockholders to buy one one-thousandth of a share of newly created Series A Junior Participating Preferred Stock at an exercise price of $80,
subject to adjustment in the event a person acquires or makes a tender or exchange offer for 15% or more of the outstanding common stock. In such event, each
right entitles the holder (other than the person acquiring 15% or more of the outstanding common stock) to purchase shares of common stock with a market value
of twice the right’s exercise price. At any time prior to such event, the Board of Directors may redeem the rights at one cent per right. The rights can be
transferred only with common stock and expire in August 2008.
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Shelf Registration Statement
In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include
debt securities, preferred stock, common stock, or warrants to purchase debt or stock. The total face amount of securities that can be offered is $2.5 billion, at
prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including
reduction of bank debt.
Common Stock Warrants
As partial consideration for producing properties acquired in December 1997, we issued warrants to purchase 4.8 million shares of common stock at a
price of $3.02 per share for a period of five years. These warrants, valued at $5.7 million when issued and recorded as additional paid-in capital, were exercised
in August 2002, resulting in an increase to common stock and additional paid-in capital of $14.3 million.
Our purchase of Antero Resources Corporation will be partially funded by issuance of five-year warrants to purchase 2 million shares of common stock at
$27.00 per share (Note 13).
Common Stock Dividends
The Board of Directors declared quarterly dividends of $0.0045 per common share for each quarter in 2002, $0.006 per common share for each quarter in
2003, $0.0075 per common share for first and second quarter 2004 and $0.0375 per common share for third and fourth quarter 2004. In February 2005, the Board
of Directors declared a first quarter 2005 dividend of $0.05 per common share after the four-for-three stock split is effected on March 15, 2005.
In August 2003, our Board of Directors declared a dividend of 0.0044 units of Cross Timbers Royalty Trust for each share of common stock outstanding
on September 2, 2003. This dividend, totaling 1,360,000 trust units, was distributed on September 18, 2003, and was recorded at the fair value of the units on that
date of $28.2 million.
The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on
our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters the Board
of Directors deems relevant.
See Note 12.
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10. Earnings Per Share
The following reconciles earnings (numerator) and shares (denominator) used in the computation of basic and diluted earnings per share:
Earnings
Earnings
Shares
per Share
332,907
$ 1.53
2004
Basic
$
Effect of dilutive securities:
Stock options
507,882
—
2,774
Diluted
$
507,882
335,681
$ 1.51
Basic
$
288,279
299,665
$ 0.96
2003
Stock options
—
4,087
Diluted
$
288,279
303,752
$ 0.95
Basic
$
186,059
277,834
$ 0.67
2002
Stock options
Warrants
—
—
Diluted
$
186,059
1,378
1,874
281,086
$ 0.66
11. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash transactions:
•
Distribution of 1,360,000 Cross Timbers Royalty Trust units as a dividend to common stockholders in 2003 (Note 9)
•
Exchange of nonstrategic working and royalty interests for nonproducing acres in August 2004 (Note 2)
•
The following performance share activity (Note 12):
•
Grants of 2.6 million shares in 2004, 4.4 million shares in 2003 and 2.4 million shares in 2002
•
Vesting of 3.2 million shares in 2004, 3.5 million in 2003 and 2.8 million shares in 2002
•
Forfeiture of 20,000 shares in 2003
Interest payments in 2004 totaled $77 million (including $2.6 million of capitalized interest), $60.9 million in 2003 (including $2.2 million of capitalized
interest) and $52.1 million in 2002 (including $4.3 million of capitalized interest). Net income tax payments were $49.7 million during 2004, $5.3 million during
2003 and $405,000 during 2002.
Because we do not recognize compensation related to stock options granted, the tax benefit realized upon exercise of stock options is recorded as an
increase in additional paid-in capital. This tax benefit has increased our net operating loss carryforwards (Note 4) and is reflected in our consolidated statements
of cash flows when these carryforwards were utilized, primarily in 2004. This tax benefit from exercise of stock options was $17.9 million in 2004, $22.7 million
in 2003 and $1.8 million in 2002.
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12. Employee Benefit Plans
401(k) Plan
We sponsor a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. We match employee contributions of up to 10%
of wages, subject to annual dollar maximums established by the federal government. Employee contributions vest immediately while our matching contributions
vest 100% upon completion of three years of service. All employees over 21 years of age may participate. Company contributions under the plan were $6.8
million in 2004, $5.2 million in 2003 and $4.5 million in 2002.
Post-Retirement Health Plan
Effective January 1, 2001, we adopted a medical plan for employees who retire at age 55 or over, as well as directors age 55 or over, with a minimum of
five years service. During 2003, our retiree medical plan was amended to provide benefits to employees and directors when their combined age and qualified
years of service total 60, with a minimum age of 45 and a minimum of five years of service. Benefits under the plan are the same as for active employees, and
continue until the retired employee or director or the employee’s or director’s dependents are eligible for Medicare or another similar federal health insurance
program. Post-retirement medical benefits are not prefunded but are paid when incurred. The status of our post-retirement health plan for 2004, 2003 and 2002 is
as follows:
December 31
2004
2003
2002
$ 3,122
456
201
—
256
(100)
$ 3,096
729
275
2,380
(3,273)
(85)
$ 1,078
477
185
490
904
(38)
$ 3,935
$ 3,122
$ 3,096
$ (3,935)
(2,704)
2,332
$ (3,122)
(3,391)
2,738
$ (3,096)
698
424
$ (4,307)
$ (3,775)
$ (1,974)
$
456
201
406
(431)
$
729
275
66
731
$
477
185
66
159
$
632
$ 1,801
$
887
(in thousands)
Change in benefit obligation:
Benefit obligation at January 1
Service cost
Interest cost
Plan amendments
Actuarial (gain) loss
Benefit payments
Benefit obligation at December 31
Amounts recognized in the consolidated balance sheet:
Funded status
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost
Accrued benefit liability, as recognized in the consolidated balance sheet at December 31
Components of net periodic benefit cost:
Service cost
Interest cost
Amortization of prior service cost
Recognized net actuarial (gain) loss
Net periodic benefit cost
Unrecognized net actuarial gain and prior service costs are amortized to expense over the lesser of the estimated average remaining service life of plan
participants or seven years. Including such amortization, the 2005 accrued benefit cost is expected to be approximately $1 million.
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The following are assumptions used by us to determine our benefit obligation as of December 31 of each of the years presented:
2004
Weighted average discount rate
Health care cost trend rate assumed for the following year
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
Year that the rate reaches the ultimate trend rate
2003
2002
6% 6.5% 6.5%
9%
9%
9%
6%
6%
6%
2010 2009 2008
Assumed health care cost trends have a significant effect on the amounts reported for health care plans. A one percentage point change in assumed health
care cost trend rates would have the following estimated effects as of December 31, 2004:
One Percentage Point
Increase
Decrease
$
$
$
$
(in thousands)
Effect on total service and interest cost
Effect on the post-retirement benefit obligation
105
513
89
450
The following are projected benefit payments, which reflect expected future service, for the next ten years:
(in thousands)
2005
2006
2007
2008
2009
2010 - 2014
$ 155
181
191
231
267
2,326
Total
$3,351
Stock Incentive Plans
In November 2004, stockholders approved the 2004 Stock Incentive Plan under which 24 million shares of common stock are available for grants of stock
awards. Prior to approval of the 2004 Plan, grants of stock awards were made pursuant to the 1998 Stock Incentive Plan. No further grants will be made under the
1998 Plan. Stock award grants are subject to the provision that awards outstanding at any given time under all incentive plans may not exceed six percent of
common stock outstanding at the time such grants are made. The maximum term of stock awards is ten years under the 1998 Plan and seven years under the 2004
plan. Stock options granted under the 2004 Plan generally vest and become exercisable ratably over a three-year period, with provision for accelerated vesting
when the common stock price reaches specified levels as determined by the Compensation Committee of the Board of Directors. There were 19.3 million options
outstanding under both plans at December 31, 2004, including 4.1 million that were exercisable at that date. The remaining 15.2 million options vested when the
common stock price reached specified levels in February 2005.
Nonemployee directors are each eligible to receive discretionary stock awards under the 2004 Plan covering up to 20,000 shares annually, as approved by
the Corporate Governance and Nominating Committee and the Board of Directors. In November 2004, nonemployee directors were granted a total of 88,000
stock options which were outstanding at December 31, 2004 and vested when the common stock price reached specified levels in February 2005. Under the 1998
Plan, nonemployee directors previously received automatic annual grants of unrestricted common shares that totaled 18,000 shares in each of 2004, 2003 and
2002. In February 2005, nonemployee directors received a total of 18,000 unrestricted shares under the 2004 Plan.
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Performance Shares
Performance shares granted under the 2004 and 1998 Plans are subject to restrictions determined by the Compensation Committee of the Board of
Directors and are subject to forfeiture if performance criteria are not met. Otherwise, holders of performance shares generally have all the voting, dividend and
other rights of other common stockholders. To date, the performance criteria for all awards has been the achievement of specified increases in the common stock
price above the market price at the grant date. The following summarizes performance share activity for each year:
December 31
2004
2003
2002
Shares granted to key employees
Shares vested when common stock price reached specified levels
Shares forfeited
Weighted average fair value of shares when granted
2,576
3,240
—
$ 20.94
4,431
3,470
20
$ 14.71
2,353
2,754
—
$ 9.73
Treasury stock purchases related to vested shares
Non-cash performance share compensation
$ 24,105
$ 67,184
$ 22,741
$ 50,826
$ 10,276
$ 26,990
At December 31, 2004, deferred compensation of $18.4 million was recorded, based on the year-end common stock price, as an offset to additional
paid-in-capital for 797,533 performance shares outstanding. These performance shares vest when the common stock reaches the following prices:
Shares
Outstanding at
December 31, 2004
Vesting
397,500
2,533
397,500
$28.13
$28.50
$31.88
Price
797,533
Management assesses whether the vesting period of stock-based awards can be reasonably estimated. When management is able to reasonably estimate a
probable vesting period, compensation is recognized ratably over the estimated vesting period or at actual vesting, if earlier. Performance shares outstanding at
December 31, 2004 were granted to key employees other than executive officers in September and November 2004. As of December 31, 2004, management
estimated a reasonably probable vesting period of one year for performance share awards that vest at $28.13 and $28.50, resulting in related compensation of
$2.8 million recorded in 2004. As of February 2005, all performance shares outstanding at December 31, 2004 vested, resulting in remaining compensation of
$21.1 million to be recorded in first quarter 2005.
During second quarter 2004, the Company began granting cash-equivalent, or phantom, performance shares to executive officers in lieu of performance
shares. Vested cash-equivalent performance shares are payable solely in cash in an amount equal to the fair market value of the underlying common stock upon
vesting. During 2004, 967,000 cash-equivalent performance shares were issued to executive officers. All cash-equivalent performance shares vested in 2004
resulting in compensation expense of $22.3 million. As of December 31, 2004, there are no cash-equivalent performance shares outstanding.
In September 2004, the Compensation Committee of the Board of Directors announced that it intended to restructure the Company’s equity incentive
program to discontinue the use of performance shares for executive officers and to provide that all future grants to the officers would be in the form of options or
other stock appreciation shares. As a result, in October 2004, the Compensation Committee of the Board of Directors amended the change in control performance
share grant agreements to delete the provisions regarding the grant of performance shares for every $0.75 increment in the price of the common stock and to
provide that, immediately prior to a change in control, executive officers will receive a lump-sum cash payment equal to the value of 1,667,000 shares of
common stock on the date of the change in control. A provision, providing that certain officers will also receive a total grant of 517,000 performance shares
immediately prior to a change in control without regard to the price of our common stock, has been revised to
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provide that such payment will be in cash and not in shares of common stock. All amounts to be granted under these agreements will be adjusted for any future
stock splits or other extraordinary transactions. If the executive officers are subject to the 20% parachute excise tax, the Company will pay the executive officer
an additional amount to “gross up” the payment so that the executive officer will receive the full amount due under the terms of the amended change in control
grant agreement after payment of the excise tax.
Option Activity and Balances
The following summarizes option activity and balances from 2002 through 2004:
Weighted
Average
Exercise
Stock
Options
Price
2002
Beginning of year
Grants
Exercises
Forfeitures
$
8.07
10.24
6.52
7.90
15,413,893
1,104,677
(1,591,438)
(73,063)
End of year
8.40
14,854,069
Exercisable at end of year
8.33
14,339,138
8.40
15.06
8.46
13.88
14,854,069
3,530,208
(10,430,123)
(55,000)
11.15
7,899,154
9.22
5,310,993
2003
Beginning of year
Grants
Exercises
Forfeitures
$
End of year
2004
Beginning of year
Grants
Exercises
Forfeitures
$ 11.15
24.86
13.17
15.14
7,899,154
16,229,845
(4,794,177)
(15,000)
End of year
22.16
19,319,822
11.99
4,092,488
The following summarizes information about outstanding options at December 31, 2004:
Options Outstanding
Range of
Exercise Prices
$ 5.23 - $ 7.85
$ 7.86 - $10.46
$10.47 - $13.08
$13.09 - $15.70
$15.71 - $20.93
$20.94 - $26.16
Weighted
Average
Remaining
Weighted
Average
Exercise
Number
Term
Price
1,948,925
1,099,233
19,329
55,667
20,000
16,176,668
6.1 years
7.0 years
8.5 years
8.9 years
9.4 years
7.2 years
$
$
$
$
$
$
7.15
9.43
11.67
15.14
19.22
24.88
1,948,925
1,099,233
19,329
55,667
20,000
949,334
$
$
$
$
$
$
19,319,822
7.1 years
$ 22.16
4,092,488
$ 11.99
72
Options Exercisable
Weighted
Average
Exercise
Number
Price
7.15
9.43
11.67
15.14
19.22
24.58
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Estimated Fair Value of Grants
Using the Black-Scholes option-pricing model and the following assumptions, the weighted average fair value of option grants was estimated to be $5.34
in 2004, $5.47 in 2003 and $4.36 in 2002. Black-Scholes and alternative option-pricing models do not consider the effects of forfeitability and nontransferability
on the valuation of employee stock options.
2004
Risk-free interest rates
Dividend yield
Weighted average expected lives
Volatility
2003
3.5%
0.6%
3 years
26%
3.1%
0.2%
4 years
42%
2002
3.1%
0.2%
4 years
50%
Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair Value
The following are pro forma earnings available to common stock and earnings per common share for 2004, 2003 and 2002, as if stock-based compensation
had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation:
2004
2003
2002
$ 507,882
$ 487,391
$ 288,279
$ 289,311
$ 186,059
$ 183,840
$
$
$
$
$
$
$
$
$
$
$
$
Earnings available to common stock:
As reported
Pro forma
Basic
As reported
Pro forma
Diluted As reported
Pro forma
1.53
1.46
1.51
1.45
0.96
0.96
0.95
0.95
0.67
0.66
0.66
0.65
13. Acquisitions
In January 2004, we acquired producing properties located primarily in East Texas and northwestern Louisiana in three separate transactions totaling $243
million after adjustments of $6 million for net revenues, preferential right elections and other items from the effective date of the transaction. The acquisitions
were funded with a portion of the proceeds from the sale of 4.9% senior notes in January 2004 (Note 3) and are subject to typical post-closing adjustments.
From February through April 2004, we purchased $223.1 million of properties located primarily in the Barnett Shale of North Texas and in the Arkoma
Basin. These acquisitions are subject to typical post-closing adjustments. Funding was provided by bank debt and cash flow from operations.
In two separate transactions during April 2004, we acquired predominantly oil-producing properties in the Permian Basin of West Texas and in the Powder
River Basin of Wyoming from ExxonMobil Corporation for a total adjusted purchase price of $336 million, including a contingent payable of up to $5 million
dependent on earnings from one property in the following year. The acquisitions were funded with bank borrowings that were repaid with proceeds from the sale
of common stock in May 2004 (Note 9) and are subject to typical post-closing adjustments.
In May 2004, we entered an agreement with ChevronTexaco Corporation to acquire properties for a stated purchase price of $1.1 billion. The acquisition
closed on August 16, 2004. After adjustments for net revenues from the January 1, 2004 effective date, preferential purchase right elections exercised in
November and December 2004, and other typical closing adjustments, the adjusted purchase price was approximately $930 million. Post-closing adjustments for
final net revenues, volume balancing and income tax effects will be made within twelve months. The acquisition was funded through existing bank credit
facilities and the sale of common stock in May 2004. These properties expand our operations in the Permian Basin and our Eastern and Mid-Continent regions,
and add new coal bed methane properties in the Rocky Mountains and a new operating region in South Texas.
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Two acquisitions in 2004 were purchases of corporations that primarily owned producing and nonproducing properties. After purchase accounting
adjustments, including a $72.3 million step-up adjustment for deferred income taxes, the cost of all producing properties acquired in 2004 was $1.9 billion.
In May 2003, we acquired from Williams of Tulsa, Oklahoma natural gas and coal bed methane producing properties in the Raton Basin of Colorado, the
Hugoton Field of southwestern Kansas and the San Juan Basin of New Mexico and Colorado. The adjusted purchase price was $381 million, which was financed
with proceeds from our sale of senior notes (Note 3) and common stock (Note 9).
In June 2003, we acquired coal bed methane and natural gas producing properties in the San Juan Basin of New Mexico and Colorado from Markwest
Hydrocarbon, Inc. for an adjusted purchase price of $51 million, which was funded through bank borrowings. The acquisition is subject to typical post-closing
adjustments.
In October 2003, we announced the completion of property transactions which increased our positions in East Texas, Arkansas and the San Juan Basin of
New Mexico for a total cost of $100 million. The purchases were funded with existing credit facilities and are subject to typical post-closing adjustments.
Acquisitions were recorded using the purchase method of accounting. The following presents our unaudited pro forma results of operations for 2003 and
2002, as if the ChevronTexaco, ExxonMobil and Williams acquisitions were made at the beginning of each period. These pro forma results are not necessarily
indicative of future results.
Pro Forma (Unaudited)
2004
2003
Revenues
$ 2,186,961
$ 1,645,307
$
574,233
$
381,985
Net income
$
574,233
$
383,763
Basic
$
1.68
$
1.19
$
1.66
$
1.17
Diluted
Weighted average shares outstanding
342,211
322,990
five-year warrants to purchase another 2 million shares of our common stock at $27 per share. The purchase agreement was amended in February 2005 to include
Antero’s gas gathering assets and related bank debt of $175 million. The transaction is expected to close April 1, 2005. The booked acquisition cost will include
customary non-cash adjustments, including a step-up adjustment for deferred income taxes. The cash consideration for the acquisition will initially be provided
through cash flow from operations and existing bank credit facilities.
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14. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2004 and 2003:
Quarter
1st
2nd
3rd
4th
Revenues
Gross profit (a)
Net income
Earnings per common share (b)
Basic
Diluted
Average shares outstanding
$ 394,764
$ 215,777
$ 94,136
$ 444,749
$ 254,986
$ 99,089
$ 507,430
$ 284,446
$ 140,782
$ 600,658
$ 329,164
$ 173,875
$
$
$
$
$
$
$
$
Revenues
Gross profit (a)
Income before cumulative effect of accounting change
$ 253,484
$ 125,532
$ 64,452
1,778
$ 282,159
$ 140,274
$ 57,335
—
$ 322,058
$ 172,789
$ 102,806
—
$ 331,854
$ 170,744
$ 61,908
—
Net income
$ 66,230
$ 57,335
$ 102,806
$ 61,908
$
0.22
0.01
$
0.19
—
$
0.34
—
$
0.20
—
$
0.23
$
0.19
$
0.34
$
0.20
$
0.22
0.01
$
0.19
—
$
0.33
—
$
0.20
—
$
0.23
$
0.19
$
0.33
$
0.20
2004
0.30
0.30
312,727
0.30
0.30
326,087
0.41
0.40
345,281
0.50
0.50
347,118
2003
Earnings per common share (b)
Basic:
Net income
Diluted:
Net income
Average shares outstanding
282,263
300,275
306,320
309,431
(a)
Operating income before general and administrative expense.
(b)
Because quarterly earnings per share is based on the weighted average shares outstanding during the quarter, the sum of quarterly earnings per share may
not equal earnings per share for the year.
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15. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)
All of our operations are directly related to oil and gas producing activities located in the United States.
Costs Incurred Related to Oil and Gas Producing Activities
The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes:
2004
2003
2002
(in thousands)
Acquisitions:
Producing properties
Undeveloped properties
Development (b) (c)
Exploration:
Successful exploratory drilling costs
Geological and geophysical studies
Dry hole expense
Rental expense and other
Asset retirement obligation accrual recorded upon acquiring and drilling wells
Total Costs Incurred
$ 1,948,995(a)
49,973
572,073
$
623,775
5,678
445,914
4,516
8,098
—
2,415
59,864(d)
$ 2,645,934
$ 354,110
3,977
352,115
14,327
639
26
1,146
13,879(e)
$ 1,105,384
(a)
Includes a deferred income tax step-up adjustment of $72.3 million.
(b)
Includes capitalized interest of $2.6 million in 2004, $2.2 million in 2003 and $4.3 million in 2002.
(c)
Amounts have been restated from previously reported amounts to separately disclose successful exploratory drilling costs.
(d)
Includes revisions of $6 million in 2004.
(e)
Excludes $75.3 million recorded upon adoption of SFAS No. 143 on January 1, 2003.
1,968
792
242
1,152
—
$ 714,356
Exploratory Well Costs
The following summarizes changes in capitalized costs for exploratory wells in process of drilling:
2004
2003
2002
(in thousands)
Exploratory wells in process of drilling, January 1
Exploratory drilling costs incurred
Successful wells transferred to producing properties
Unsuccessful well costs charged to expense
$ 3,390
4,516
(5,965)
—
$
1,709
14,353
(12,646)
(26)
Exploratory wells in process of drilling, December 31
$ 1,941
$
3,390
$
816
2,210
(1,075)
(242)
$ 1,709
There were no completed exploratory wells awaiting determination of proved reserves at December 31, 2004, 2003 or 2002.
Proved Reserves
Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to
the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new
information obtained from
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development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production
payments.
Standardized Measure
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial
Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and
production expenditures to produce year-end estimated proved reserves. Year-end prices are not adjusted for the effect of hedge derivatives. Discounted future
net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows,
less the tax basis of related assets and applicable tax credits.
As of December 31, 2003, estimated well abandonment costs, net of salvage, are deducted from the standardized measure using year-end costs. Such
abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values of the projected abandonment date and discounted using a
risk-adjusted rate at the time the well is drilled or acquired (Note 5).
In our prior reports, the estimated future net cash flows from proved reserves and related present value amounts were reported before reduction for
operated overhead expense. Operated overhead is a component of production expense in the consolidated income statement, and is an allocation from general and
administrative expense of the costs estimated to support the production function. As part of its periodic review of our filings, the staff of the Securities and
Exchange Commission concluded that production expense components for proved reserve disclosures should be consistent with components of production
expense recorded in the financial statements. Accordingly, we have restated estimated future net cash flows and the related present value amounts for all years
presented, resulting in a reduction to these amounts of approximately 2% at December 31, 2003 and 3% at December 31, 2002.
The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and gas reserves. Probable and
possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized
measure are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.
Gas (Mcf)
Natural Gas
Oil
Natural Gas
Equivalents
Liquids (Bbls)
(Bbls)
(Mcfe)
(in thousands)
Proved Reserves
December 31, 2001
Revisions
Extensions, additions and discoveries
Production
Purchases in place
Sales in place
2,235,478
76,400
426,541
(187,583)
330,387
(42)
20,299
2,433
2,395
(1,850)
2,156
—
54,049
5,465
1,144
(4,757)
449
(1)
2,681,566
123,788
447,775
(227,225)
346,017
(48)
December 31, 2002
Revisions
Production
Purchases in place
Sales in place
2,881,181
(11,644)
559,773
(243,979)
465,732
(6,824)
25,433
5,487
1,610
(2,359)
4,508
(1)
56,349
1,792
424
(4,724)
2,204
(614)
3,371,873
32,030
571,977
(286,477)
506,004
(10,514)
December 31, 2003
Revisions
Production
Purchases in place
3,644,239
(96,139)
755,385
(305,453)
716,471
34,678
(146)
3,730
(2,739)
2,933
55,431
3,001
4,176
(8,307)
98,205
4,184,893
(79,009)
802,821
(371,729)
1,323,299
December 31, 2004
4,714,503
38,456
77
152,506
5,860,275
Table of Contents
Gas
Natural Gas
Oil
Natural Gas
Equivalents
(Mcf)
Liquids (Bbls)
(Bbls)
(Mcfe)
(in thousands)
Proved Developed Reserves
December 31, 2001
1,452,222
14,774
41,231
1,788,252
December 31, 2002
2,042,661
19,367
47,178
2,441,931
December 31, 2003
2,651,259
28,187
47,882
3,107,673
December 31, 2004
3,252,711
30,019
134,382
4,239,117
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
December 31
2004
2003
2002
$ 34,027,144
$ 23,213,223
$ 14,734,787
(in thousands)
Future cash inflows
Future costs:
Production
Development
(8,841,912)
(1,580,173)
(5,636,953)
(875,665)
(3,881,188)
(687,723)
Future net cash flows before income tax
Future income tax
23,605,059
(7,366,185)
16,700,605
(5,142,301)
10,165,876
(3,017,334)
Future net cash flows
10% annual discount
16,238,874
(7,836,431)
11,558,304
(5,568,619)
7,148,542
(3,392,100)
Standardized measure (a)
(a)
$ 8,402,443
$ 5,989,685
$ 3,756,442
Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $12.2 billion for 2004, $8.6 billion for
2003 and $5.3 billion for 2002.
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Changes in Standardized Measure of Discounted Future Net Cash Flows (a)
2004
2003
2002
$ 5,989,685
$ 3,756,442
$ 1,473,777
(in thousands)
Standardized measure, January 1
Revisions:
Prices and costs
Quantity estimates
Accretion of discount
Future development costs
Income tax
Production rates and other
Net revisions
Production
Development costs
Purchases in place (b)
Sales in place (c)
Net change
Standardized measure, December 31
(20,491)
436,812
516,752
(796,658)
(978,455)
(2,007)
1,514,335
207,955
327,181
(493,856)
(973,113)
2,372
2,551,358
209,061
132,097
(344,531)
(1,159,368)
821
(844,047)
1,383,710
(1,512,036)
484,341
2,900,790
—
584,874
1,092,285
(905,910)
434,554
1,043,242
(15,802)
1,389,438
619,556
(610,064)
326,219
557,561
(45)
2,412,758
2,233,243
2,282,665
$ 8,402,443(d)
$ 5,989,685(e)
$ 3,756,442
(a)
The standardized measure has been reduced by estimated operated overhead expense, resulting in a restatement from previously reported amounts of the
standardized measure at December 31, 2003 and 2002, and of the changes in the standardized measure for 2003 and 2002.
(b)
Generally based on the year-end present value (at year-end prices and costs) plus the cash flow received from such properties during the year, rather than
the estimated present value at the date of acquisition.
(c)
Generally based on beginning of the year present value (at beginning of year prices and costs) less the cash flow received from such properties during the
year, rather than the estimated present value at the date of sale.
(d)
The December 31, 2004 standardized measure includes a reduction of $14.6 million ($22.9 million before income tax) for estimated property abandonment
costs. The consolidated balance sheet at December 31, 2004 includes a long-term liability of $159.9 million for the same asset retirement obligation, which
was calculated using different cost and present value assumptions as required by SFAS No. 143.
(e)
The December 31, 2003 standardized measure includes a reduction of $7 million ($10.8 million before income tax) for estimated property
abandonment costs. The consolidated balance sheet at December 31, 2003 includes a long-term liability of $93.4 million for the same asset
retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143.
Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions
are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development
activity.
Year-end average realized gas prices used in the estimation of proved reserves and calculation of the standardized measure were $5.69 for 2004, $5.71 for
2003, $4.41 for 2002 and $2.36 for 2001. Year-end average realized natural gas liquids prices were $28.24 for 2004, $23.17 for 2003, $17.86 for 2002 and $8.70
for 2001. Year-end average realized oil prices were $41.03 for 2004, $30.55 for 2003, $29.69 for 2002 and $17.39 for 2001. Proved oil and gas reserves at
December 31, 2004 include 192,719,000 Mcf of gas and 1,647,000 Bbls of oil and discounted present value before income tax of $403.4 million related to our
ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2004.
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934, as amended). Our management assessed the effectiveness of our internal control over financial reporting as of December 31,
2004. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission
(“COSO”) in Internal Control-Integrated Framework. Our management has concluded that, based on these criteria, we have maintained in all material respects,
effective internal control over financial reporting as of December 31, 2004. Our independent registered public accounting firm, KPMG LLP, has issued an audit
report on our assessment of our internal control over financial reporting, which is included herein.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our
internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met. Further, the design of a control system must reflect that there are resource constraints, and the benefits
of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute
assurance that all control issues and instances of fraud, if any, within our Company have been detected.
March 7, 2005
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
XTO Energy Inc.:
We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2004 and 2003, and the related
consolidated income statements, statements of cash flows and statements of stockholders’ equity for each of the years in the three-year period ended December
31, 2004. In connection with our audits of the consolidated financial statements, we also have audited the related financial statement schedules. These
consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of XTO Energy Inc. and its
subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended
December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January
1, 2003, in connection with its adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of XTO Energy
Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 7, 2005 expressed an unqualified opinion on
management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 7, 2005
81
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
XTO Energy Inc.:
We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting, that XTO Energy Inc. maintained
effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). XTO Energy Inc.’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion
on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, management’s assessment that XTO Energy Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). Also, in our opinion, XTO Energy Inc. maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of
XTO Energy Inc. and its subsidiaries as of December 31, 2004 and 2003, and the related consolidated income statements, statements of cash flows and
statements of stockholders’ equity for each of the years in the three-year period ended December 31, 2004, and our report dated March 7, 2005 expressed an
unqualified opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 7, 2005
82
Table of Contents
XTO ENERGY INC.
Consolidated Valuation and Qualifying Accounts
SCHEDULE II
Balance at
Beginning of
Period
Balance at
End of
Additions(a)
Deductions(b)
Other
Period
(in thousands)
Year Ended December 31, 2004
Allowance for doubtful accounts - Joint interest and other receivables
$
6,328
$
232
$
(535)
$ (2,161)(c)
$ 3,864
$
5,537
$ 1,319
$
(528)
$
—
$ 6,328
$
4,098
$
$
(65)
$
524(d)
$ 5,537
(a)
Additions relate to provisions for doubtful accounts.
(b)
Deductions relate to the write-off of accounts receivable deemed uncollectible.
(c)
Reduction based on collection experience.
(d)
Adjustment related to reclassified account balances.
83
980
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized, on the 7th day of March 2005.
XTO ENERGY INC.
By
/s/
BOB R. SIMPSON
Bob R. Simpson, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in
the capacities indicated on the 7th day of March 2005.
PRINCIPAL EXECUTIVE OFFICERS
(AND DIRECTORS)
/s/
DIRECTORS
BOB R. SIMPSON
/s/ WILLIAM H. ADAMS III
Bob R. Simpson, Chairman of the Board
and Chief Executive Officer
/s/
William H. Adams III
STEFFEN E. PALKO
/s/
Steffen E. Palko, Vice Chairman of the Board
and President
PHILLIP R. KEVIL
Phillip R. Kevil
/s/
JACK P. RANDALL
Jack P. Randall
/s/
SCOTT G. SHERMAN
Scott G. Sherman
/s/
HERBERT D. SIMONS
Herbert D. Simons
PRINCIPAL FINANCIAL OFFICER
/s/
PRINCIPAL ACCOUNTING OFFICER
LOUIS G. BALDWIN
/s/
Louis G. Baldwin, Executive Vice President
and Chief Financial Officer
84
BENNIE G. KNIFFEN
Bennie G. Kniffen, Senior Vice President
and Controller
Table of Contents
INDEX TO EXHIBITS
Documents filed prior to June 1, 2001 were filed with the Securities and Exchange Commission under our prior name, Cross Timbers Oil Company.
Exhibit
No.
Description
2.1+
Asset Sale Agreement between Chevron U.S.A. Inc. as Seller and XTO Energy Inc. as Buyer, dated May 14, 2004 (incorporated by
reference to Exhibit 2.1 to Form 8-K filed August 19, 2004)
2.2+
Agreement and Plan of Merger by and among Antero Resources Corporation, XTO Energy Inc. and XTO Barnett Inc., dated January 9,
2005
2.3+
Amendment to Agreement and Plan of Merger by and among Antero Resources Corporation, XTO Energy Inc. and XTO Barnett Inc.,
dated February 3, 2005
3.1
Restated Certificate of Incorporation of the Company, as restated on June 21, 2004 (incorporated by reference to Exhibit 3.1 to Form
10-Q for the quarter ended June 30, 2004)
3.2
Amended Bylaws of the Company (incorporated by reference to Form 10-K for the year ended December 31, 2003)
4.1
Form of Indenture for Senior Debt Securities dated as of April 23, 2002 between the Company and the Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.3.1 to Form 8-K filed April 17, 2002)
4.2
First Supplemental Indenture dated as of April 23, 2002, between the Company and the Bank of New York, as Trustee for the 7½%
Senior Notes due April 15, 2012 (incorporated by reference to Exhibit 4.2 to Form 10-K for the year ended December 31, 2002)
4.3
Preferred Stock Purchase Rights Agreement between the Company and ChaseMellon Shareholder Services, LLC (incorporated by
reference to Exhibit 4.1 to Form 8-A/A filed September 8, 1998)
4.4
Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, dated August 25, 1998
(incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2000)
4.5
Registration Rights Agreement among the Company and partners of Cross Timbers Oil Company, L.P. (incorporated by reference to
Exhibit 10.9 to Registration Statement on Form S-1, File No. 33-59820)
4.6
Indenture dated as of April 23, 2003, between the Company and the Bank of New York, as Trustee for the 6¼% Senior Notes due April
15, 2013 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2003)
4.7
Registration Rights Agreement dated April 23, 2003, between the Company and certain Initial Purchasers named therein (incorporated
by reference to Exhibit 4.2 to Form 10-Q for the quarter ended March 31, 2003)
4.8
Indenture for Senior Debt Securities dated as of January 22, 2004, between the Company and the Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.3.1 to Form 8-K filed January 16, 2004)
85
Page
Table of Contents
Exhibit
No.
Description
4.9
First Supplemental Indenture dated as of January 22, 2004, between the Company and the Bank of New York for the 4.9% Senior Notes
due February 1, 2014 (incorporated by reference to Exhibit 4.3.2 to Form 8-K filed January 16, 2004)
4.10
Indenture dated as of September 23, 2004, between the Company and the Bank of New York, as Trustee for the 5% Senior Notes due
2015 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 20, 2004)
10.1 *
Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated May 17, 2000 (incorporated by
reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2000)
10.2 *
Amendment to Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated August 20, 2002
10.3 *
Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated May 17, 2000 (incorporated by
reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2000)
10.4 *
Amendment to Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated August 20, 2002
10.5 *
1998 Stock Incentive Plan, as amended March 17, 2004 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended
March 31, 2004)
10.6 *
2004 Stock Incentive Plan (incorporated by reference to Appendix A to the Proxy Statement dated October 15, 2004 for the Special
Meeting of Stockholders held November 16, 2004)
10.7 *
Form of Nonqualified Stock Option Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit
10.2 to Form 8-K filed November 22, 2004)
10.8 *
Form of Stock Award Agreement for Employees under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 to Form
8-K filed November 22, 2004)
10.9 *
Form of Nonqualified Stock Option Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by
reference to Exhibit 10.4 to Form 8-K filed November 22, 2004)
10.10*
Form of Stock Award Agreement for Non-Employee Directors under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit
10.5 to Form 8-K filed November 22, 2004)
10.11*
Form of Stock Grant Agreement for Non-Employee Directors under Section 11 of the 2004 Stock Incentive Plan (incorporated by
reference to Exhibit 10.1 to Form 8-K filed February 22, 2005)
10.12*
Amended Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.14 to Form 10-K
for the year ended December 31, 1999)
86
Page
Table of Contents
Exhibit
No.
Description
10.13*
Amendment to Amended Employee Severance Protection Plan, as amended August 20, 2002 (incorporated by reference to Exhibit 10.5
to Form 10-Q for the quarter ended September 30, 2002)
10.14*
Amended and Restated Management Group Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by
reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 1999)
10.15*
Amendment to Amended and Restated Management Group Employee Severance Protection Plan, as amended August 20, 2002
10.16*
Outside Directors Severance Plan, dated August 20, 2002 (incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarter ended
September 30, 2002)
10.17*
Form of Agreement for Grant of Performance Shares (relating to change in control) between the Company and each of Bob R. Simpson
and Steffen E. Palko dated February 20, 2001 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September
30, 2001)
10.18*
Form of Agreement for Grant of Performance Shares (relating to change in control) between the Company and each of Louis G. Baldwin,
Keith A. Hutton and Vaughn O. Vennerberg II dated February 20, 2001 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the
quarter ended September 30, 2001)
10.19*
Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Bob R. Simpson
dated May 24, 2001 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2001)
10.20*
Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Steffen E. Palko
10.21*
Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Louis G. Baldwin
10.22*
Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Keith A. Hutton
10.23*
Amendment to Agreement for Grant of Performance Shares (relating to change in control) between the Company and Vaughn O.
Vennerberg II dated May 24, 2001 (incorporated by reference to Exhibit 10.7 to Form 10-Q for the quarter ended September 30, 2001)
10.24*
Form of Amended and Restated Agreement for Grant (relating to change in control) between the Company and Bob R. Simpson, Steffen
E. Palko, Louis G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated October 15, 2004 (incorporated by reference to Exhibit
10.1 to Form 8-K filed October 21, 2004)
10.25*
Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated April 23, 2004 (incorporated by
reference to Form 10-Q for the quarter ended June 30, 2004)
87
Page
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Exhibit
No.
Description
10.26*
Phantom Performance Share Award Agreement between the Company and Bob R. Simpson, dated June 18, 2004 (incorporated by referenced
to Form 10-Q for the quarter ended June 30, 2004)
10.27*
Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis
G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated June 24, 2004 (incorporated by referenced to Form 10-Q for the quarter
ended June 30, 2004)
10.28*
Form of Agreement for Grant of Phantom Performance Shares between the Company and each of Bob R. Simpson, Steffen E. Palko, Louis
G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II, dated July 8, 2004 (incorporated by referenced to Form 10-Q for the quarter
ended June 30, 2004)
10.29
Five-Year Revolving Credit Agreement dated February 17, 2004, between the Company and certain commercial banks named therein
(incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 2003)
10.30
Term Loan Credit Agreement dated November 10, 2004 between the Company and certain commercial banks named therein (incorporated
by reference to Exhibit 10.20 to Form S-4 dated December 13, 2004)
12.1
Computation of Ratio of Earnings to Fixed Charges
21.1
Subsidiaries of XTO Energy Inc.
23.1
Consent of KPMG LLP
23.3
Consent of Miller and Lents, Ltd.
31
Rule 13a-14(a)/15d-14(a) Certifications
31.1 Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 Chief Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32
Section 1350 Certifications
32.1 Chief Executive Officer and Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
+ All schedules and similar attachments have been omitted. The Company agrees to furnish supplementally a copy of the omitted schedules and similar
attachments to the Securities and Exchange Commission upon request.
* Management contract or compensatory plan
Copies of the above exhibits not contained herein are available, at the cost of reproduction, to any security holder upon written request to the Secretary, XTO
Energy Inc., 810 Houston Street, Fort Worth, Texas 76102.
88
Page
EXHIBIT 2.2
AGREEMENT AND PLAN OF MERGER
by and among
ANTERO RESOURCES CORPORATION,
XTO ENERGY INC.
and
XTO BARNETT INC.
Dated as of January 9, 2005
TABLE OF CONTENTS
Page
ARTICLE 1
DEFINED TERMS
1.1
1.2
Definitions
List of Defined Terms
1
12
ARTICLE 2
THE MERGER
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
2.10
2.11
2.12
2.13
2.14
2.15
Merger
Effective Time
Effects of the Merger
Certificate of Incorporation and Bylaws
Directors and Officers
Conversion of Outstanding Shares
Treatment of Options
Dissenters’ Rights
Closing of Transfer Books
Merger Consideration
Closing Payments
Payment
Per Share Consideration Amendment
Debt
Tax-Related Adjustments
13
13
13
14
14
14
14
15
16
16
17
17
19
19
19
ARTICLE 3
REPRESENTATIONS AND WARRANTIES
3.1
3.2
Representations and Warranties of the Company
Representations and Warranties of Parent and Merger Subsidiary
20
31
ARTICLE 4
COVENANTS OF THE COMPANY
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
Conduct of Business
Access and Information
Third Party Consents
Notification of Certain Matters; Supplemental Disclosure Letters
Termination of Agreements
Company Transaction Costs
Sale of Pipeline Assets
Drilling Contracts and Landmen
Loan Agreements
Repurchase of Unvested Shares
34
38
38
39
39
39
39
39
40
40
i
ARTICLE 5
COVENANTS OF PARENT AND MERGER SUBSIDIARY
5.1
5.2
5.3
5.4
5.5
5.6
5.7
Notification of Certain Matters
Access to Information
Indemnification of Officers, Directors, Employees and Agents
Name Change
Pipeline Assets
Registration of Parent Common Stock
Delivery of Allocated Values
40
40
41
43
43
43
43
ARTICLE 6
OTHER COVENANTS OF THE PARTIES
6.1
6.2
6.3
6.4
Governmental Consents
Investigation and Agreement by Parent and Merger Subsidiary; No Other Representations or Warranties
Confidentiality of Agreement
Tax Treatment
43
44
45
45
ARTICLE 7
CONDITIONS PRECEDENT
7.1
7.2
7.3
Conditions to Each Party’s Obligation
Conditions to Obligation of Parent and Merger Subsidiary
Conditions to Obligations of the Company
45
46
47
ARTICLE 8
CLOSING
8.1
8.2
8.3
Closing
Actions to Occur at Closing
Waiver of Breaches
48
48
49
ARTICLE 9
TERMINATION, AMENDMENT AND WAIVER
9.1
9.2
9.3
Termination
Effect of Termination
Return of Information
49
50
50
ARTICLE 10
GENERAL PROVISIONS
10.1
10.2
10.3
10.4
Survival of Representations and Warranties
Reasonable Efforts; Further Assurances
Amendment and Modification
Waiver of Compliance
51
51
51
51
ii
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
Severability
Expenses and Obligations
Parties in Interest
Notices
Counterparts
Time
Entire Agreement
Public Announcements
Attorneys’ Fees
Assignment
Rules of Construction
Joint Liability
Affiliate Liability
Governing Law
Waiver Of Jury Trial
Consent to Jurisdiction; Venue
52
52
52
52
53
53
53
54
54
54
54
55
55
56
56
56
EXHIBITS:
Exhibit A
Exhibit B
Exhibit C
Exhibit D
Exhibit E
—
—
—
—
—
Pipeline Assets – 1
Pipeline Assets – 2
Form of Warrant Agreement
List of Officers to Sign Non-Competition Agreements
Form of Registration Rights Agreement
iii
THIS AGREEMENT AND PLAN OF MERGER (this “Agreement”), dated as of January 9, 2005, is made by and among Antero Resources Corporation,
a Delaware corporation (the “Company”), XTO Energy Inc., a Delaware corporation (“Parent”), and XTO Barnett Inc., a Delaware corporation and a
wholly-owned subsidiary of Parent (“Merger Subsidiary”).
PRELIMINARY STATEMENTS
WHEREAS, the Boards of Directors of the Company, Parent and Merger Subsidiary deem it advisable and in the best interest of their respective
stockholders to consummate the transactions contemplated by this Agreement on the terms and subject to the conditions provided for herein;
WHEREAS, in furtherance thereof it is proposed that the acquisition of the Company by Parent be accomplished by the merger of Merger Subsidiary with
and into the Company, with the Company being the surviving corporation, in accordance with the General Corporation Law of the State of Delaware (the
“DGCL”);
WHEREAS, the Boards of Directors of the Company, Parent (on its own behalf and as sole stockholder of Merger Subsidiary) and Merger Subsidiary
have each approved and adopted this Agreement, the Merger (as hereinafter defined) and the other transactions contemplated hereby and declared the advisability
of this Agreement (and, in the case of the Company, recommended that this Agreement be adopted by its Stockholders); and
WHEREAS, the Company, Parent and Merger Subsidiary desire to make certain representations, warranties, covenants and agreements in connection with
the Merger and also to prescribe various conditions to the Merger.
AGREEMENTS
NOW, THEREFORE, in consideration of the representations, warranties, covenants and agreements set forth herein, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, and upon the terms and subject to the conditions hereinafter set forth, the parties
hereto, intending to be legally bound hereby, agree as follows:
ARTICLE 1
DEFINED TERMS
1.1 Definitions. The following terms shall have the following meanings in this Agreement:
“Affiliate” means, with respect to any Person, any other Person controlling, controlled by or under common control with such Person. For purposes
of this definition, the term “control” (and correlative terms) means the power, whether by contract, equity ownership or otherwise, to direct the policies or
management of a Person.
1
“Allocated Value” means the value of each Scheduled Oil and Gas Property to be set forth on a supplement to Company Disclosure Schedule
3.1(w)(ii) to be delivered by Parent not later than January 14, 2005.
“Antero II” means Antero Resources II Corporation, a Delaware corporation.
“Antitrust Laws” means, collectively, (a) the HSR Act; (b) the Sherman Antitrust Act of 1890, as amended; (c) the Clayton Act of 1914, as
amended; (d) the Federal Trade Commission Act of 1914, as amended; and (e) any other Applicable Law designed to prohibit, restrict, or regulate actions for the
purpose or effect of monopolization or restraint of trade.
“Applicable Laws” means all laws, statutes, rules, regulations, ordinances, judgments, orders, decrees, injunctions and writs of any Governmental
Authority having jurisdiction over the business or operations of the Company and its Subsidiaries, as may be in effect on the date of this Agreement.
“Business Day” means any day other than (a) a Saturday, Sunday or federal holiday or (b) a day on which commercial banks in New York, New
York are authorized or required to be closed.
“Certificate” means a certificate representing Vested Common Shares or outstanding shares of Series A Preferred Stock, as the case may be.
“Code” means the United States Internal Revenue Code of 1986, as amended. All references to the Code, U.S. Treasury regulations or other
governmental pronouncements shall be deemed to include references to any applicable successor regulations or amending pronouncement.
“Common Stock” means the common stock of the Company, par value $0.001 per share.
“Common Stockholders” means the holders of shares of outstanding shares of Common Stock.
“Company Disclosure Schedule” means, collectively, that certain disclosure letter of even date with this Agreement from the Company to Parent
delivered concurrently with the execution and delivery of this Agreement and any Supplemental Disclosure Letters delivered by the Company to Parent from
time to time after the date of this Agreement.
“Company Transaction Costs” means all fees, costs and expenses of any brokers, financial advisors, consultants, accountants, attorneys, the
Exchange Agent or other professionals engaged by the Company in connection with the structuring, negotiation or consummation of the transactions
contemplated by this Agreement and the other Transaction Documents, including the proposed sale of the Pipeline Assets.
“Confidentiality Agreement” means the Confidentiality Agreement, dated as of November 4, 2004, by and between the Company and Parent.
2
“Consents” means all authorizations, consents, orders or approvals of, or registrations, declarations or filings with, or expiration of waiting periods
imposed by, any Governmental Authority, in each case that are necessary in order to consummate the transactions contemplated by this Agreement and the other
Transaction Documents, and all consents and approvals of third parties necessary to prevent any conflict with, violation or breach of, or default under, the
Material Contracts.
“Debt” means, except for accounts and obligations owed by the Company to any of its Subsidiaries or owed by a Subsidiary of the Company to the
Company and/or one or more of its Subsidiaries, (a) all indebtedness of the Company and its Subsidiaries for the repayment of borrowed money, whether or not
represented by bonds, debentures, notes or similar instruments, all accrued and unpaid interest thereon, and, solely with respect to the Loan Agreements, all
premiums, prepayment penalties, fees and other amounts; (b) all other indebtedness of the Company and its Subsidiaries evidenced by bonds, debentures, notes
or similar instruments, including all accrued and unpaid interest thereon; and (c) all obligations of the Company and its Subsidiaries as lessee or lessees under
leases that have been recorded by the Company as capital leases in accordance with GAAP.
“Disclosure Schedules” means the Company Disclosure Schedule and the Parent Disclosure Schedule.
“Easement” means any easements, rights-of-way, licenses or permits supporting or permitting the locations of the pipeline systems comprising a
part of the Gathering Assets.
“Employee Benefit Plan” means any “employee benefit plan” within the meaning of Section 3(3) of ERISA and any bonus, deferred compensation,
incentive compensation, stock ownership, stock purchase, stock option, phantom stock, vacation, severance, disability, death benefit, hospitalization or insurance
plan providing benefits to any present or former employee or contractor of the Company or any member of the Aggregated Group maintained by any such entity.
“Environmental Liabilities” means any losses or liabilities (a) in connection with any violation of any Environmental Laws or (b) in connection
with a claim by any private or public Person arising out of any exposure of any Person or property to Hazardous Substances or (c) which constitute a breach of
the Company’s representations and warranties set forth in Section 3.1(q) that has not been cured on or prior to the Closing; provided that for the purposes of
Section 2.10(b)(iv) such Environmental Liabilities must be identified by Parent and disclosed in writing to the Company prior to 5 p.m. MST on March 7, 2005.
“Environmental Laws” means the Applicable Laws pertaining to the environment, natural resources and employee health and safety, including: (a)
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”); (b) the Emergency Planning and Community
Right to Know Act, as amended; (c) the Solid Waste Disposal Act, as amended; (d) the Clean Air Act, as amended; (e) the Clean Water Act, as amended; (f) the
Toxic Substances Control Act, as amended; (g) the Occupational Safety and Health Act of 1970, as amended; (h) the Oil Pollution Act of 1990, as amended; and
3
(i) the Hazardous Materials Transportation Act, as amended, as each of the foregoing are in effect on the date of this Agreement.
“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.
“Fully Diluted Outstanding Shares” means the Outstanding Shares and the Outstanding In-the-Money Option Shares.
“GAAP” means generally accepted accounting principles in the United States, consistently applied.
“Gathering Assets” means (a) that certain gas gathering system located in Tarrant County, Wise County and Denton County, Texas, and (b) all of
the Company’s and its Subsidiaries’ rights, titles and interests, whether direct or indirect, in and to all of the property, rights or interests incident to such
gathering system, including, without limitation, all of the Company’s and its Subsidiaries’ rights, titles and interests in and to all Oil and Gas Contracts relating
thereto, easements, rights of way, system permits, equipment, facilities, fixtures and other items of personal property and improvements on the date of this
Agreement appurtenant to such gathering system or used, obtained or held for use in connection with the operation of such gathering system.
“Good and Defensible Title” shall mean title that (a) is not held in violation of any Applicable Laws, rules, regulations or orders of any
Governmental Authority, (b) is such that a reasonable and prudent Person engaged in the business of the ownership, development and operation of gas processing
facilities and gas gathering pipeline systems with the knowledge of all the facts and their legal bearing would be willing to accept, and (c) is free and clear from
Liens and encumbrances, other than Permitted Liens.
“Good and Marketable Title” shall mean such title that: (a) is deducible of record (from the records of the applicable parish or county or (i) in the
case of federal leases, from the records of the applicable office of the Minerals Management Service or Bureau of Land Management, (ii) in the case of Indian
leases, from the applicable office of the Bureau of Indian Affairs, (iii) in the case of state leases, from the records of the applicable state land office) or is
assignable to Company or its Subsidiaries out of an interest of record (as so defined) because of the performance by Company or its Subsidiaries of all operations
required to earn an enforceable right to such assignment; (b) does not materially restrict the ability of Company or its Subsidiaries to use the properties as
currently intended; (c) is such that a reasonable and prudent Person engaged in the business of the ownership, development and operation of oil and gas
properties with the knowledge of all the facts and their legal bearing would be willing to accept; and (d) except as set forth on Company Disclosure Schedule
3.1(w)(ii), entitles Company or its Subsidiaries to receive a percentage of Hydrocarbons produced, saved and marketed from such well or property not less than
the interest set forth in Company Disclosure Schedule 3.1(w)(ii) as applicable, with respect to each Scheduled Oil and Gas Interest therein under the caption “Net
Revenue Interest” or “NRI” without reduction during the life of such property except as stated in Company Disclosure Schedule 3.1(w)(ii), as applicable; (e)
obligates Company and its Subsidiaries to pay costs and expenses relating to each such proved property in an amount not
4
greater than the interest set forth under the caption “Working Interest” or “WI” in Company Disclosure Schedule 3.1(w)(ii), as applicable, with respect to such
property without increase over the life of such property except as shown on Company Disclosure Schedule 3.1(w)(ii).
“Governmental Authority” means any governmental department, commission, board, bureau, agency, court or other instrumentality, whether
foreign or domestic, of any country, nation, republic, federation or similar entity or any state, county, parish or municipality, jurisdiction or other political
subdivision thereof.
“Hazardous Substances” means all petroleum hydrocarbons, petroleum products, natural gas, crude oil and any components, fractions, or
derivatives thereof, explosive or radioactive substances, materials or wastes, hazardous or toxic substances, materials or wastes, asbestos, asbestos-containing
materials, pollutants and contaminants and all other substances, materials or wastes, whether or not defined as such, that are regulated pursuant to or that could
result in liability under any applicable Environmental Laws.
“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
“Intellectual Property” means the following intellectual property rights, including both statutory and common law rights, as applicable: (a)
copyrights; (b) trademarks, service marks, trade names, slogans, domain names, logos, and trade dress, and registrations and applications for registrations thereof;
(c) patents and patent applications (including all reissues, divisions, continuations, continuations-in-part, renewals and extensions of the foregoing); (d) trade
secrets and confidential information, including, but not limited to, ideas, designs, concepts, compilations of information, methods, techniques, procedures,
processes and other know-how, whether or not patentable; and (e) registrations for any of the foregoing.
“Knowledge” means with respect to the Company, the actual knowledge of the following individuals: the Chief Executive Officer, the Chief
Financial Officer, the Vice President Land, the Vice President Production, the Vice President Gas Marketing and Transportation, Vice President Business
Development and the Controller/Treasurer of the Company.
“Lease” means an oil and gas lease or other similar lease or a right permitting the owner thereof to use, sever, process, operate and occupy oil, gas,
Hydrocarbon interests and associated fixtures or structures for a specified period of time.
“Leased Real Property” means all of the real property leased by the Company or any of its Subsidiaries excluding the Leases.
“Letters of Credit” means those certain letters of credit described on Company Disclosure Schedule 3.1(h)(ii).
“Liens” means liens, pledges, voting agreements, voting trusts, proxy agreements, security interests, mortgages, and other possessory interests,
conditional sale or other title retention agreements, assessments, easements, rights-of-way, covenants, restrictions, rights of first refusal, encroachments, and
other burdens, options or encumbrances of any kind.
5
“Loan Agreements” means, collectively, (a) that certain Credit Agreement dated May 6, 2004 by and among the Company, Antero II and the
Lenders named therein, (b) that certain Senior Term Agreement dated July 7, 2004 by and among the Company, Antero II and the Lenders named therein, and (c)
that certain Revolver Promissory Note made in favor of Antero II dated September 23, 2004.
“Master Agreement” means the Master Agreement dated May 6, 2004, by and among the Company, Antero II and their stockholders.
“Material Adverse Effect” means any change, circumstance, effect, event or fact that has a material and adverse effect on the business, assets,
financial condition or results of operations of the Company and its Subsidiaries, taken as a whole; provided, however, that no change, circumstance, effect, event
or fact shall be deemed (individually or in the aggregate) to constitute, nor shall any of the foregoing be taken into account in determining whether there has been
or may be, a Material Adverse Effect, to the extent that such change, circumstance, effect, event or fact results from, arises out of, or relates to (a) a general
deterioration in the economy or changes in Hydrocarbon prices or other changes affecting the oil and gas industry generally; (b) the outbreak or escalation of
hostilities involving the United States, the declaration by the United States of a national emergency or war or the occurrence of any other calamity or crisis,
including acts of terrorism; (c) the disclosure of the fact that Parent is the prospective acquirer of the Company; (d) the announcement or pendency of the
transactions contemplated by this Agreement or any other Transaction Document; (e) the announcement of the Company’s intention to review the possibility of
selling itself; (f) any change in accounting requirements or principles imposed upon the Company, its Subsidiaries or their respective businesses by GAAP or any
change in Applicable Laws, or the interpretation thereof; (g) actions taken by Parent or any of its Affiliates; or (h) compliance with the terms of, or the taking of
any action required by, this Agreement or any other Transaction Document.
“Material Contract” means, excluding each Lease and Oil and Gas Contract:
(a) each contract or agreement that is executory in whole or in part and was not entered into in the ordinary course of business and that
involves expenditures or receipts of the Company or any of its Subsidiaries for goods or services of an amount in excess of $100,000 after the date of this
Agreement;
(b) each lease, rental or occupancy agreement, installment and conditional sale agreement, and any other contract or agreement, in each case,
affecting the ownership of, leasing of, title to or use of any Real Property providing for payments at an annual rate in excess of $100,000;
(c) each joint venture, partnership or any other material contract or agreement involving a sharing of profits, losses, costs or liabilities by the
Company or any of its Subsidiaries with any other Person providing for any capital contribution or expenditure at an annual rate in excess of $100,000;
(d) each contract or agreement containing covenants that in any way purport to restrict or prohibit the business activity of the Company or any
of its
6
Subsidiaries or limit the freedom of the Company or any of its Subsidiaries thereof to engage in any line of business or to compete with any Person;
(e) each contract or agreement with any director or officer of the Company;
(f) the Loan Agreements and each other indenture, mortgage, promissory note or other agreement or commitment for the Debt, or the direct or
indirect guarantee by such entities of any such Debt in excess of $100,000;
(g) surety, performance and maintenance bonds in excess of $100,000;
(h) brokerage or finder’s agreements;
(i) any contract, commitment or agreement that involves the disposition after the Effective Time of any assets of the Company or any of its
Subsidiaries not in the ordinary course of business; and
(j) any other contract, agreement or other arrangement that is material to the Company and its Subsidiaries taken as a whole.
“Merger Consideration Certificate” means the certificate executed on behalf of the Company by its Chief Executive Officer and Chief Financial
Officer setting forth: (a) the Securityholders of the Company to whom merger consideration will be payable pursuant to this Agreement; and (b) with regard to
each such Securityholder (i) the number of Vested Common Shares, shares of Series A Preferred Stock and Vested Options, as applicable, owned by such
Securityholder, and in the case of Vested Options, the number of shares of Common Stock issuable upon the exercise of such Vested Option and the per share
exercise price of each such Vested Option, (ii) the amount of cash merger consideration to be paid to such Securityholder pursuant to this Agreement; (iii) the
denomination of the Stock Certificate to be issued to such Securityholder as Parent Stock Merger Consideration; and (iv) the denomination of the Warrant to be
issued to such Securityholder as Parent Warrant Merger Consideration.
“Oil and Gas Contracts” means any farmout, farming, operating agreement, unit agreement, pooling or communitization agreement, declaration or
order, joint venture or acquisition agreement relating to the Oil and Gas Interests and oil and gas production, sales, exchange and processing contracts and
agreements or other contract affecting the ownership or operation of any of the properties comprising the Oil and Gas Interests or the disposition of the
Hydrocarbons produced therefrom.
“Oil and Gas Interests” means: (a) the interests of the Company or any of its Subsidiaries in the Oil and Gas Properties and wells located thereon,
together with the interests of the Company or any of its Subsidiaries in and to all property and rights incident thereto, including all rights in respect of any pooled
or unitized acreage by virtue of any Oil and Gas Property being a part thereof, all production from the pool or unit allocated to any such Oil and Gas Property and
all interests in any wells within the pool or unit associated with the Oil and Gas Properties; and (b) the interests of the Company or any of its Subsidiaries in and
to all of the personal property, fixtures and improvements on such Oil and Gas Properties or appurtenant
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thereto or used, held or obtained in connection with the Oil and Gas Properties or the production, treatment, sale or disposal of Hydrocarbons or water or other
substances produced therefrom or attributable thereto (whether located on or off the Oil and Gas Properties) including all interests in equipment and machinery,
(including wells, well equipment and machinery, casing, tanks, boilers, generators) oil and gas production, gathering, transmission, treating, processing, and
storage facilities (including tanks, tank batteries, pipelines, the Gathering Assets, crude oil, condensate or other production in storage or in pipelines, flow lines,
tubing, motors, and field separators), pumps, water plants, electric plants, and other tangible personal property and fixtures associated with, appurtenant to, or
necessary for the operation of any of the foregoing, and all other tenements, hereditaments, improvements and appurtenances thereunto belonging. Oil and Gas
Interests shall be deemed to include all direct and indirect interests in and rights with respect to oil, gas, mineral, and related properties and assets of any kind and
nature, including the Oil and Gas Properties and other non-working interests and non-operating interests; all of the Company’s or any Subsidiary’s interests in
rights with respect to Hydrocarbons and other minerals or revenues therefrom.
“Oil and Gas Properties” means any oil, gas (including coalbed methane), Hydrocarbon or other mineral fee estate, severed mineral estate, Lease,
royalty interest, net profits interest, license, concession, permit or other interest in oil, gas, Hydrocarbons or other minerals in which the Company or any of its
Subsidiaries holds an interest.
“Options” means the collective reference to all options to purchase shares of Common Stock issued pursuant to the Stock Option Plan and any and
all other options to purchase shares of Common Stock.
“Outstanding In-the-Money Option Shares” means as of any given date the aggregate number of shares of Common Stock issuable pursuant to
Vested Options as of such date.
“Outstanding Shares” means, as of any given date, the outstanding Vested Common Shares as of such date and the shares of Common Stock
issuable upon the conversion of the outstanding shares of Series A Preferred Stock as of such date assuming such shares were converted on such date.
“Owned Real Property” means those parcels of real property, other than Oil and Gas Interests, owned in fee and used or held for use by the
Company or any of its Subsidiaries, and all buildings, structures, improvements, and fixtures thereon, together with all rights of way, easements, privileges and
appurtenances pertaining or belonging thereto, including any right, title and interest of the Company or any of its Subsidiaries in and to any street or other
property adjoining any portion of such property.
“Parent Common Stock” means the publicly traded common stock of Parent, par value $0.01 per share.
“Parent Disclosure Schedule” means the disclosure letter of even date with this Agreement from the Parent to the Company delivered concurrently
with the execution and delivery with this Agreement.
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“Per Share Merger Consideration” means (a) cash in an amount equal to the quotient of (i) the Adjusted Cash Merger Consideration plus the
aggregate exercise price of all Outstanding In-the-Money Option Shares less the Series A Preferential Merger Consideration divided by (ii) the number of Fully
Diluted Outstanding Shares, (b) the number of shares of Parent Common Stock equal to the quotient of (i) 10,000,000 (as adjusted as applicable by Section 2.15)
divided by (ii) the number of Fully Diluted Outstanding Shares and (c) a Warrant to purchase that number of Parent Common Stock equal to the quotient of (i)
1,500,000 divided by (ii) the number of Fully Diluted Outstanding Shares.
“Permitted Encumbrances” means (a) statutory Liens for current Taxes not yet due and payable or being contested in good faith by appropriate
proceedings; (b) mechanics’, carriers’, workers’, repairers’ and other similar Liens imposed by Applicable Law arising or incurred in the ordinary course of
business and consistent with past practices of the Company or any of its Subsidiaries for obligations that are not overdue or that are being contested in good faith
by appropriate proceedings; (c) in the case of leases of vehicles, rolling stock and other personal property, encumbrances that do not materially impair the
operation of the business at the location at which such leased equipment or other personal property is located; (d) easements, rights-of-way, servitudes, permits,
surface leases and other rights in respect of surface operations; (e) deposits to secure the performance of bids, contracts (other than for borrowed money), leases,
statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business and consistent
with past practices of the Company or any of its Subsidiaries; (f) zoning regulations and restrictive covenants and easements of record that do not detract in any
material respect from the value of the Real Property or Oil and Gas Interests and do not materially and adversely affect, impair or interfere with the use of any
property affected thereby; (g) public utility easements of record, in customary form, to serve the Real Property or Oil and Gas Interests; (h) Liens securing all or
any portion of the amounts outstanding under the Loan Agreements; (i) landlords’ Liens in favor of landlords under the leases with respect to the Leased Real
Property; and (j) mortgages, deeds of trust and other security instruments, and ground leases or underlying leases covering the title, interest or estate of such
landlords with respect to the Leased Real Property and to which the leases with respect to the Leased Real Property are subordinate.
“Person” means an individual, corporation, partnership, limited liability company, association, trust, unincorporated organization or other entity.
“Pipeline Assets” means the portion of the Gathering Assets that are set forth on Exhibit A and Exhibit B which are currently owned by or prior to
the Closing will be conveyed to Antero Resources Pipeline, LP, a Texas limited partnership.
“Pipeline Assets Sale Price” means the aggregate dollar amount of consideration received by the Company from a sale of the Pipeline Assets
accomplished by the sale of all of the membership interests in Antero Resources I GP, LLC and Antero Resources I LP, LLC, the sole general partner and sole
limited partner, respectively, of Antero Resources Pipeline, LP, or an equivalent transaction that does not adversely affect Parent or the Company.
“Real Property” means the Leased Real Property and the Owned Real Property.
9
“Securityholders” means, collectively, the Stockholders and the Optionholders.
“Series A Preferred Stockholders” means the holders of the Series A Convertible Participating Preferred Stock.
“Series A Preference Amount” has the meaning ascribed to it in the Certificate of Designations for the Series A Preferred Stock.
“Series A Preferential Merger Consideration” means the aggregate amount of the Series A Preference Amount for the outstanding shares of
Series A Preferred Stock as of the Effective Time.
“Services Agreement” means the Services Agreement dated May 6, 2004, by and between the Company and Antero II.
“Stock Certificates” means stock certificates representing shares of duly authorized and validly issued Parent Common Stock.
“Stock Option Plan” means the 2003 Stock Incentive Plan of the Company, as amended.
“Stockholders” means the Common Stockholders and the Series A Preferred Stockholders.
“Stockholders’ Agreement” means the Amended and Restated Stockholders’ Agreement dated May 6, 2004, by and among the Company and
certain Stockholders named therein.
“Subsidiary” means, with respect to any Person, another Person in which such first Person owns, directly or indirectly, an amount of the voting
securities, other voting ownership or voting partnership interests of which is sufficient to elect at least a majority of its board of directors or other governing body
(or, if there are no such voting interests, fifty percent (50%) or more of the equity interests of such Person).
“Taxes” means taxes, charges, fees, imposts, levies, interest, penalties, additions to tax or other assessments or fees of any kind, including, but not
limited to, income, corporate, capital, excise, property, sales, use, turnover, value added and franchise taxes, deductions, withholdings and customs duties,
imposed by any Governmental Authority.
“Tax Returns” means any return, report, statement, information return or other document (including any related or supporting information) filed or
required to be filed with any Governmental Authority in connection with the determination, assessment, collection or administration of any Taxes or the
administration of any laws, regulations or administrative requirements relating to any Taxes.
“Title Benefit Amount” means:
10
(a) any increase in the Allocated Value of any Scheduled Oil and Gas Interest that has been agreed to by the Company and Parent; and
(b) in the event of a discrepancy in favor of the Company between (A) the actual Net Revenue Interest for any Scheduled Oil and Gas Interest
and (B) the Net Revenue Interest stated on Company Disclosure Schedule 3.1(w)(ii), then the Title Benefit Amount shall be the product of the Allocated
Value of such Scheduled Oil and Gas Interest multiplied by a fraction, the numerator of which is the Net Revenue Interest increase and the denominator of
which is the Net Revenue Interest stated on Company Disclosure Schedule 3.1(w)(ii), provided that if the discrepancy is not effective or does not affect an
Scheduled Oil and Gas Interest throughout its entire term, the Title Benefit Amount determined under this subsection shall be reduced accordingly.
“Title Defect” means a Lien or other failure or impairment of Good and Marketable Title, other than a Permitted Lien, identified by Parent and
disclosed in writing to the Company prior to 5 p.m. MST on March 7, 2005, the presence of which constitutes a breach in the Company’s representations and
warranties set forth in Section 3.1(w)(iii) with regard to Scheduled Oil and Gas Interests that has not been cured or removed prior to the Closing.
“Title Defect Amount” means:
(a) any reduction in the Allocated Value of any Scheduled Oil and Gas Interest arising from a Title Defect that has been agreed to by the
Company and Parent;
(b) in the event of a Title Defect that is undisputed and liquidated in amount, the amount required to be paid to remove such Title Defect from
the affected Scheduled Oil and Gas Interest;
(c) in the event of a Title Defect which represents a discrepancy between (A) the actual Net Revenue Interest for any Scheduled Oil and Gas
Interest and (B) the Net Revenue Interest stated on Company Disclosure Schedule 3.1(w)(ii), then the Title Defect Amount shall be the product of the
Allocated Value of such Scheduled Oil and Gas Interest multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the
denominator of which is the Net Revenue Interest stated on Company Disclosure Schedule 3.1(w)(ii), provided that if the Title Defect is not effective or
does not affect an Scheduled Oil and Gas Interest throughout its entire term, the Title Defect Amount determined under this subsection shall be reduced
accordingly;
(d) notwithstanding anything to the contrary herein, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any
given Scheduled Oil and Gas Interest shall not exceed the Allocated Value of such Scheduled Oil and Gas Interest;
(e) in the event that a Title Defect may reasonably be cured, the Title Defect Amount determined under subsections (c) or (d) above shall not
be greater than the lesser of (A) the reasonable cost and expense of curing such Title Defect or (B) the share of such curative work cost and expense which
is allocated to such Scheduled Oil and Gas Interest pursuant to subsection (f) below; and
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(f) the Title Defect Amount with respect to a Scheduled Oil and Gas Interest shall be determined without duplication of any costs or losses
included in another Title Defect Amount hereunder. To the extent that the cost to cure any Title Defect will result in the curing of all or a part of one or
more other Title Defects, such cost of cure shall be allocated among the Scheduled Oil and Gas Interests so affected on a fair and reasonable basis.
“Transaction Documents” means, collectively, this Agreement and each other agreement, document and instrument required to be executed in
accordance herewith.
“Vested Common Shares” means shares of Common Stock outstanding immediately prior to the Effective Time to the extent such shares have
become vested at the Effective Time (including shares that vest as a result of the Merger).
“Vested Options” means Options outstanding immediately prior the Effective Time to the extent that such Options have become vested and
exercisable in accordance with their terms at the Effective Time (including Options that vest and become exercisable as a result of the Merger).
“Warrants” means warrants to purchase shares of Parent Common Stock substantially in the form as attached to the Warrant Agreement attached
as Exhibit C hereto.
1.2
List of Defined Terms.
Terms
Defined in Section
Agreement
Aggregated Group
Antero Affiliate
Balance Sheet
Balance Sheet Date
Cash Merger Consideration
CERCLIS
Certificate of Merger
Closing
Closing Date
Company
Company Permits
Cure Period
DGCL
Dissenting Shares
D&O Indemnified Liabilities
D&O Indemnified Persons
Effective Time
Exchange Account
Exchange Agent
Express Affiliate Obligations
Preamble
3.1(t)
10.17
3.1(h)(i)
3.1(h)(ii)
2.10(a)
3.1(q)(v)
2.2
8.1
8.1
Preamble
3.1(l)
9.1(b)(i)
Preliminary Statements
2.8(b)
5.3(a)
5.3(a)
2.2
2.12(a)
2.11(b)
10.17
12
Terms
Defined in Section
Financial Statements
Letter of Transmittal
Merger
Merger Subsidiary
National Priorities List
Optionholder
Option Consideration
Option Surrender Agreement
Other Pipeline Assets
Parent
Parent Stock Merger Consideration
Parent Warrant Merger Consideration
Permitted Liens
Preferred Stock
Reserve Report
Scheduled Oil and Gas Interest
Series A Preferred Stock
Supplemental Disclosure Item
Supplemental Disclosure Letter
Surviving Corporation
Termination Date
Waived Breaches
3.1(h)(i)
2.12(b)(i)
2.1
Preamble
3.1(q)(v)
2.7
2.7
2.12(b)(ii)
3.1(w)(ii)
Preamble
2.10(a)(ii)
2.10(a)(iii)
3.1(p)
3.1(c)
3.1(u)
3.1(w)(ii)
3.1(c)
4.4(b)
4.4(b)
2.1
9.1(b)(iii)
8.3
ARTICLE 2
THE MERGER
2.1 Merger. Upon the terms and subject to the conditions set forth in this Agreement, at the Effective Time, Merger Subsidiary shall be merged with and
into the Company (the “Merger”) in accordance with the terms of, and subject to the conditions set forth in, this Agreement and the DGCL. At the Effective
Time, the Company shall continue as the surviving corporation in the Merger (sometimes hereinafter referred to as the “Surviving Corporation”) and the
separate corporate existence of Merger Subsidiary shall cease.
2.2 Effective Time. Upon the terms and subject to the conditions set forth in this Agreement, as soon as practicable after the satisfaction or waiver of the
conditions set forth in ARTICLE 7, the Company, Parent and Merger Subsidiary shall cause a Certificate of Merger meeting the requirements of Section 251 of
the DGCL (the “Certificate of Merger”) to be properly executed and filed with the Secretary of State of the State of Delaware in accordance with the terms and
conditions of the DGCL. The Merger shall become effective at the time of filing of the Certificate of Merger with the Secretary of State of the State of Delaware
in accordance with the DGCL (the “Effective Time”) or at such subsequent date and hour as the Company and Parent shall agree and specify in the Certificate of
Merger.
2.3 Effects of the Merger. At and after the Effective Time, the Merger shall have the effects set forth in the DGCL. Without limiting the generality of the
foregoing and subject
13
thereto, at the Effective Time all the property, rights, privileges, immunities, powers and franchises of the Company and Merger Subsidiary shall vest in the
Surviving Corporation, and all Debts, liabilities, obligations and duties of the Company and Merger Subsidiary shall become the debts, liabilities, obligations and
duties of the Surviving Corporation.
2.4 Certificate of Incorporation and Bylaws. The certificate of incorporation and bylaws of the Company in effect immediately prior to the Effective
Time shall be the certificate of incorporation and bylaws of the Surviving Corporation as of the Effective Time, until duly amended in accordance with
Applicable Laws.
2.5 Directors and Officers. The directors and officers of Merger Subsidiary immediately prior to the Effective Time shall be the directors and officers of
the Surviving Corporation as of the Effective Time.
2.6 Conversion of Outstanding Shares. At the Effective Time, by virtue of the Merger and without any action on the part of any party:
(a) Each share of Common Stock, par value $0.001 per share, of Merger Subsidiary issued and outstanding immediately prior to the Effective Time
shall be converted into one (1) share of Common Stock, par value $0.001 per share, of the Surviving Corporation, so that, after the Effective Time, Parent shall
be the holder of all of the issued and Outstanding Shares of the Surviving Corporation’s Common Stock.
(b) Each Vested Common Share outstanding immediately prior to the Effective Time (i) shall be converted into the right to receive the Per Share
Merger Consideration, payable (in accordance with Section 2.12) to the holder thereof, without interest thereon, and (ii) shall otherwise cease to be outstanding,
shall be canceled and retired and cease to exist; provided, however, that Dissenting Shares shall not be so converted or represent the right to receive the foregoing
consideration, but the holders of such Dissenting Shares shall only be entitled to such rights as are set forth in Section 2.8.
(c) Each share of Common Stock held in the treasury of the Company, including shares repurchased prior to the Effective Time pursuant to Section
4.10, or by any of the Company’s Subsidiaries immediately prior to the Effective Time shall be canceled and retired without any conversion thereof, and no
payment or distribution shall be made with respect thereto.
(d) Each share of Series A Preferred Stock outstanding immediately prior to the Effective Time (i) shall be converted into the right to receive (A)
cash in an amount equal to the Series A Preference Amount for such share plus (B) the Per Share Merger Consideration for such share, payable (in accordance
with Section 2.12) to the holder thereof, without interest thereon, and (ii) shall otherwise cease to be outstanding, shall be canceled and retired and cease to exist;
provided, however, that any Dissenting Shares shall not be so converted or represent the right to receive the foregoing consideration, but the holders of such
Dissenting Shares shall only be entitled to such rights as are set forth in Section 2.8.
2.7 Treatment of Options. Prior to the Closing, the Company shall give notice in writing to each holder of a Vested Option (each an “Optionholder” and
collectively, the
14
“Optionholders”) outstanding immediately prior to the Effective Time that notwithstanding anything to the contrary in the Stock Option Plan or in any stock
option agreement, (a) each Vested Option outstanding at the Effective Time shall be converted into the right to receive the Per Share Merger Consideration less
the exercise price per share of Common Stock pursuant to such Vested Option (with respect to each such Vested Option, the “Option Consideration”), payable
(in accordance with Section 2.12) to the holder thereof, and (b) with respect to each such Option that is not a Vested Option as of the Effective Time, such Option
shall be cancelled by the Company and terminated in full without consideration immediately prior to the Effective Time. The Company shall take such actions,
including amending the Stock Option Plan and stock option agreements, as may be required to facilitate the foregoing.
2.8 Dissenters’ Rights.
(a) Promptly following the execution of this Agreement, the Company shall provide each record holder of Common Stock or shares of Series A
Preferred Stock, who shall not have voted in favor of the Merger or consented thereto in writing, with notice of such holder’s appraisal rights pursuant to Section
262 of the DGCL. The Company shall give Parent prompt notice of any demands for appraisal pursuant to Section 262 of the DGCL received by the Company
from any Stockholders, withdrawals of such demands and any other instruments served pursuant to the DGCL and received by the Company in connection
therewith and the opportunity to participate in and direct all negotiations with respect to any such demands for appraisal. No later than ten (10) days following the
date on which the Effective Time occurs, Parent and the Surviving Corporation shall provide notice of the Effective Time to each Stockholder who has neither
voted in favor of the Merger nor consented thereto in writing and has not withdrawn or lost the right to the appraisal pursuant to Section 262 of the DGCL. The
Company shall not, except with the prior written consent of the Parent, make any payment or agree to make any payment with respect to any demand for
appraisal or agree to settle any such demands.
(b) Notwithstanding any provision of this Agreement to the contrary, no shares of Common Stock or shares of Series A Preferred Stock that are held
immediately prior to the Effective Time by holders who have neither voted in favor of the Merger nor consented thereto in writing and who have demanded and
perfected the right, if any, for appraisal of such shares of Common Stock or shares of Series A Preferred Stock in accordance with the provisions of Section 262
of the DGCL and have not withdrawn or lost such right to appraisal (collectively, the “Dissenting Shares”) shall be converted into or represent a right to receive
the merger consideration pursuant to Section 2.6(b) or 2.6(d), respectively, but the holder of such Dissenting Shares shall only be entitled to such appraisal rights
as are granted by the DGCL. If a holder of shares of Common Stock or shares of Series A Preferred Stock that demands appraisal of such shares of Common
Stock or shares of Series A Preferred Stock under the DGCL shall thereafter effectively withdraw or lose (through failure to perfect or otherwise) the right to
appraisal with respect to such shares of Common Stock or shares of Series A Preferred Stock, then, as of the occurrence of such withdrawal or loss, each such
share of Common Stock or share of Series A Preferred Stock shall be deemed to have been converted into and represent only the right to receive the merger
consideration pursuant to Sections 2.6(b) or 2.6(d), respectively, in each case, without interest thereon.
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2.9 Closing of Transfer Books. From and after the Effective Time, the stock transfer books of the Company shall be closed and no transfer of Common
Stock or Series A Preferred Stock shall thereafter be made. From and after the Effective Time, the holders of Certificates evidencing ownership of shares of
Common Stock or shares of Series A Preferred Stock immediately prior to the Effective Time shall cease to have any rights with respect to such shares of
Common Stock or shares of Series A Preferred Stock, except as otherwise provided for in this Agreement or by Applicable Law.
2.10 Merger Consideration.
(a) The Merger consideration, subject to adjustment in accordance with the terms of this Agreement, paid by Parent in connection with the Merger
shall be as follows:
(i) $337,500,000 in cash (the “Cash Merger Consideration”);
(ii) 10,000,000 shares of duly issued Parent Common Stock (the “Parent Stock Merger Consideration”) subject to adjustment as
applicable pursuant to Section 2.15; and
(iii) Warrants to purchase a total of 1,500,000 shares of Parent Common Stock (the “Parent Warrant Merger Consideration”).
(b) The Cash Merger Consideration shall be adjusted as set forth in this Section 2.10(b) (as adjusted, the “Adjusted Cash Merger
Consideration”):
(i) decreased by the Company Transaction Costs;
(ii) increased by (A) 50% of the amount, if any, that the Pipeline Assets Sale Price exceeds $175,000,000 up to a maximum of $5,000,000,
and (B) the amount, if any, that the Pipeline Assets Sale Price is greater than $185,000,000;
(iii) decreased by (A) 50% of the amount, if any, that the Pipeline Assets Sale Price is less than $175,000,000 up to a maximum of
$5,000,000 and (B) the amount, if any, that that the Pipeline Assets Sale Price is less than $165,000,000;
(iv) decreased by the aggregate amount of Environmental Liabilities; provided, that there shall be no decrease in the Cash Merger
Consideration due to Environmental Liabilities until and unless the aggregate amount of Environmental Liabilities shall have exceeded $15,000,000, at which
time the Cash Merger Consideration will be decreased by the entire amount of the Environmental Liabilities;
(v) decreased by the aggregate of the Title Defect Amounts; provided, that there shall be no decrease in the Cash Merger Consideration due
to Title Defect Amounts until and unless the aggregate of the Title Defect Amounts, net of any Title Benefit Amounts, shall have exceeded $15,000,000, at
which time the Cash Merger Consideration will be decreased by all such Title Defect Amounts;
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(vi) decreased by the aggregate of any bonus amounts determined and approved by the Company’s board of directors and paid by the
Company prior to Closing unless otherwise allowed by or disclosed on the date of this Agreement pursuant to Section 4.1 hereof;
(vii) decreased if necessary pursuant to Section 2.15; and
(viii) decreased by the payments made pursuant to Section 4.10.
(c) In the event that the Company receives an offer from a bona fide purchaser to pay a Pipeline Assets Sale Price that is not approved by Parent in
accordance with Section 4.7 hereof, and is greater than the Pipeline Assets Sale Price actually received from a buyer approved by Parent, then such higher
Pipeline Assets Sale Price shall be used for the purposes of Section 2.10(b)(ii) or (b)(iii).
2.11 Closing Payments. At the Closing, Parent shall pay or cause to be paid the following amounts by wire transfers of immediately available funds:
(a) Parent shall pay or cause to be paid all Company Transaction Costs that remain outstanding as of the Closing Date to such account or accounts as
are designated by the Company in accordance with Section 4.6; and
(b) Parent shall deliver or cause to be delivered to a trust company designated by the Company (the “Exchange Agent”) for payment and delivery to
the Securityholders in accordance with this ARTICLE 2 through the Exchange Agent:
(i) the Adjusted Cash Merger Consideration;
(ii) Stock Certificates representing in the aggregate the Parent Stock Merger Consideration; and
(iii) Warrants representing in the aggregate the Parent Warrant Merger Consideration.
(c) Parent shall pay, or provide funds for the Company to pay, any amounts paid pursuant to Section 2.10(b)(vi).
2.12 Payment.
(a) The funds, Stock Certificates and Warrants received by the Exchange Agent pursuant to Section 2.11(b) shall be deposited by the Exchange
Agent in an account (the “Exchange Account”) established for the benefit of the Securityholders. The Exchange Agent shall pay and deliver:
(i) out of the Exchange Account, to each Common Stockholder holding a Certificate that immediately prior to the Effective Time
represented a Vested Common Share, promptly upon receipt by the Exchange Agent of a completed and duly executed Letter of Transmittal and the Certificate,
the Per Share Merger Consideration for each Vested Common Share previously represented by such Certificate;
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(ii) out of the Exchange Account, to each Series A Preferred Stockholder holding a Certificate that immediately prior to the Effective Time
represented outstanding shares of Series A Preferred Stock, promptly upon receipt by the Exchange Agent of a completed and duly executed Letter of
Transmittal and the Certificate, the Series A Preference Amount in cash and the Per Share Merger Consideration for each such outstanding share of Series A
Preferred Stock previously represented by such Certificate; and
(iii) out of the Exchange Account, to each Optionholder, promptly upon receipt by the Exchange Agent of a completed and duly executed
Option Surrender Agreement, the aggregate Option Consideration for the Vested Options surrendered pursuant to the Option Surrender Agreement.
(b) At or immediately following the Effective Time, Parent shall deliver:
(i) to each record holder of Vested Common Shares or Series A Preferred Stock (A) a letter of transmittal, which shall specify that delivery
shall be effected, and risk of loss and title to the Certificates shall pass, only upon delivery of the Certificates to the Exchange Agent (the “Letter of
Transmittal”) and (B) instructions for effecting the surrender of such Certificates in exchange for the consideration such Stockholder has the right to receive
pursuant to Sections 2.6 and 2.12(a)(i) or (a)(ii), as applicable;
(ii) to each holder of an Vested Option (A) an option surrender agreement (the “Option Surrender Agreement”) and (B) instructions for
effecting the surrender of such Option in exchange for the consideration such Optionholder has the right to receive pursuant to Sections 2.7 and 2.12(a)(iii); and
(c) Parent shall deliver all Letters of Transmittal, Certificates and Option Surrender Agreements received by it at or prior to Closing to the Exchange
Agent promptly after Closing, and Parent shall deliver all Letters of Transmittal, Certificates and Option Surrender Agreements, received by it after Closing to
the Exchange Agent promptly after receipt thereof.
(d) Each of the Surviving Corporation and Parent shall be entitled to deduct and withhold from the consideration otherwise payable to any
Securityholder pursuant to this ARTICLE 2 any amounts as the Surviving Corporation or Parent, as the case may be, is required to deduct and withhold with
respect to payment under any provision of federal, state or local income Tax law. If the Surviving Corporation or Parent, as the case may be, so withholds
amounts, such amounts shall be treated for all purposes of this Agreement as having been paid to the Securityholders in respect of which the Surviving
Corporation or the Parent, as the case may be, made such deduction or withholding. No interest shall accrue or be paid on the merger consideration payable upon
the delivery of Certificates or Option Surrender Agreements.
(e) The Exchange Agent will, within five (5) Business Days after the 270th day following the Closing Date, return to the Surviving Corporation any
portion of the consideration remaining to be paid to Securityholders pursuant to this ARTICLE 2 who have not yet surrendered their Certificates or Option
Surrender Agreements or perfected their rights of appraisal, as the case may be, and any other funds in the Exchange Account which are to be distributed to
Securityholders. Any Securityholders shall thereafter be entitled to look only to
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Parent and the Surviving Corporation for payment of their claims for the consideration set forth in Sections 2.6, 2.7 and in this Section 2.12, without interest
thereon.
(f) If any Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the Person claiming such Certificate to
be lost, stolen or destroyed and, if required by Parent, an indemnity against any claim that may be made against it with respect to such Certificate, the Parent or
the Exchange Agent, as applicable, will issue in exchange for such lost, stolen or destroyed Certificate the consideration otherwise payable pursuant to this
ARTICLE 2.
(g) Any amounts paid and any Stock Certificates or Warrants delivered to the Exchange Agent for the benefit of a Securityholder that are
attributable to a Dissenting Share shall be available to pay the fair value of such Dissenting Share for which appraisal rights are perfected pursuant to Section 262
of the DGCL.
2.13 Per Share Consideration Amendment. Parent agrees to enter into an amendment to this Agreement proposed by the Company in order to reallocate
the merger consideration among the individual holders of the Vested Common Shares, shares of Series A Preferred Stock and Vested Options to the extent such
amendment does not (a) increase the total consideration to be paid by Parent under this Agreement nor (b) otherwise adversely affect Parent or the assets or
liabilities of the Company at Closing.
2.14 Debt. On the Closing Date, the Company shall deliver to Parent a schedule of Debt of the Company and its Subsidiaries (excluding all capital leases
of the Company and its Subsidiaries) as of immediately prior to the Closing.
2.15 Tax-Related Adjustments. Notwithstanding anything in this Agreement to the contrary, to preserve the status of the Merger as a tax-free
reorganization within the meaning of Section 368(a) of the Code, if, based upon the closing price of the Parent Common Stock as reported on the New York
Stock Exchange (the “NYSE”) on the Business Day immediately preceding the Effective Time, the Parent Stock Merger Consideration would be less than 43%
(or such lesser percentage as would preserve the status of the Merger as a tax-free reorganization within the meaning of Section 368(a) of the Code) of the sum of
the Adjusted Cash Merger Consideration plus the positive value of the Parent Stock Merger Consideration plus the positive value of the Parent Warrant Merger
Consideration, then, at the option of the Company, Parent will (a) increase the number of shares of Parent Common Stock included in the Parent Stock Merger
Consideration and (b) decrease the amount of the Adjusted Cash Merger Consideration by an amount equal to (i) the number of shares added to Parent Common
Stock pursuant to subsection (a) above multiplied by (ii) $33.75 so that the aggregate value of the Parent Stock Merger Consideration, as determined based upon
the closing price of the Parent Common Stock on the NYSE on the Business Day immediately preceding the Effective Time, is equal to 43% (or such lesser
percentage as would preserve the status of the Merger as a tax-free reorganization within the meaning of Section 368(a) of the Code) of the sum of the Adjusted
Cash Merger Consideration plus the positive value of the Parent Stock Merger Consideration plus the positive value of the Parent Warrant Merger Consideration.
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ARTICLE 3
REPRESENTATIONS AND WARRANTIES
3.1 Representations and Warranties of the Company. Except as set forth on the Company Disclosure Schedule, as of the date of this Agreement and as
of the Effective Time (except to the extent such representations and warranties speak expressly as of an earlier date), the Company represents and warrants to
Parent and the Merger Subsidiary as follows:
(a) Organization, Good Standing and Other Matters. Each of the Company and its Subsidiaries is duly organized, validly existing and in good
standing under the laws of its respective jurisdiction of incorporation or organization, has all requisite power and authority to own, lease and operate its
properties and to carry on its business as now being conducted, and is duly qualified to do business as a foreign corporation, partnership or limited liability
company in good standing to conduct business in each jurisdiction in which the business it is conducting, or the operation, ownership or leasing of its properties,
makes such qualification necessary. A true, correct and complete copy of the Company’s Certificate of Incorporation and Bylaws and its Subsidiaries’ respective
certificates of incorporation and bylaws, or other comparable organizational documents, as in effect on the date of this Agreement has been furnished or made
available to Parent or its representatives. The Company and its Subsidiaries are in material compliance with all provisions of their Certificate of Incorporation, as
amended, Bylaws, Limited Partnership Agreements and Limited Liability Company Agreements, as applicable. All Subsidiaries of the Company, their respective
jurisdictions of incorporation or organization and their respective jurisdictions where qualified to do business are set forth on Company Disclosure Schedule
3.1(a).
(b) Corporate Records. The minute books of the Company and its Subsidiaries accurately reflect actions taken by their Board of Directors,
committees of its Board of Directors, and shareholders. All such actions were properly taken with a quorum present and acting throughout each such meeting.
The stock transfer books of the Company and its Subsidiaries accurately reflect all issuances and transfers of shares of the Company’s and its Subsidiaries’
capital stock. The Company possesses its and its Subsidiaries’ minute books and stock transfer books.
(c) Capitalization of the Company. As of the date of this Agreement, the authorized capital stock of the Company consists of 33,000,000 shares of
Common Stock and 28,000,000 shares of preferred stock, par value $0.001 per share (the “Preferred Stock”), all shares of which are designated as Series A
Convertible Participating Preferred Stock (the “Series A Preferred Stock”). As of the date of this Agreement, (i) 3,715,000 shares of Common Stock are issued
and outstanding; (ii) no shares of Common Stock are held by the Company in treasury; and (iii) 7,583,785 shares of Series A Preferred Stock are issued and
outstanding. No bonds, debentures, notes or other instruments or evidence of indebtedness having the right to vote (or convertible into, or exercisable or
exchangeable for, securities having the right to vote) on any matters on which the Company’s Stockholders may vote are issued or outstanding. All outstanding
shares of Common Stock and Preferred Stock are duly authorized, validly issued, fully paid and nonassessable and were not issued in violation of any preemptive
or other similar rights. Except as set forth above, as set forth on Company Disclosure Schedule 3.1(d) and as set forth on Company Disclosure Schedule 3.1(c), as
of the date of this
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Agreement, there are outstanding (A) no shares of capital stock or other voting securities of the Company; (B) no securities of the Company convertible into, or
exchangeable or exercisable for, shares of capital stock or other voting securities of the Company; and (C) other than the Options, no options, warrants, calls,
rights, commitments or agreements to which the Company is a party or by which it is bound, in any case obligating the Company to issue, deliver, sell, purchase,
redeem or acquire, or cause to be issued, delivered, sold, purchased, redeemed or acquired, shares of capital stock or other voting securities of the Company, or
obligating the Company to grant, extend or enter into any such option, warrant, call, right, commitment or agreement.
(d) Options. Immediately prior to the Effective Time, there will be outstanding Options to acquire an aggregate of 1,240,000 shares of Common
Stock with each such Option having the per share exercise price of $2.50.
(e) Capitalization of the Subsidiaries. As of the date of this Agreement, the authorized issued and outstanding limited liability company interests and
partnership interests, as applicable, of each Subsidiary of the Company are listed on Company Disclosure Schedule 3.1(e). The Company directly or indirectly is
the record and beneficial owner of all issued and outstanding limited liability company interests and partnership interests, as applicable, of each such Subsidiary
and such ownership is free and clear of all Liens other than Permitted Liens. All of such limited liability company interests and partnership interests, as
applicable, of the Subsidiaries have been validly issued and have not been issued in violation of any preemptive or similar rights. There are no contracts,
agreements, commitments or arrangements obligating any such Subsidiary to issue, deliver, sell, purchase, redeem or acquire, cause to be issued, delivered, sold,
purchased, redeemed or acquired, any limited liability company interests and partnership interests, as applicable, or obligating any such Subsidiary to grant,
extend, or enter into any option, warrant, call, right, commitment or agreement of any kind to acquire any such limited liability company interests and partnership
interests, as applicable.
(f) Authority. The Company has the requisite power and authority to execute and deliver this Agreement and the other Transaction Documents to
which it is a party and to perform its obligations hereunder and thereunder and to consummate the transactions contemplated herein and therein. The execution,
delivery and performance of this Agreement and the other Transaction Documents by the Company and the consummation by the Company of the transactions
contemplated herein or therein have been duly and validly authorized by all necessary corporate action on the part of the Company. The Board of Directors of the
Company has adopted a resolution, as contemplated by Section 251(b) of the DGCL, declaring the advisability of, and recommending that the Stockholders
approve, this Agreement. Contemporaneously with the execution and delivery of this Agreement by the Company, (i) holders of Series A Preferred Stock, voting
separately as a single class, who collectively own of record at least sixty-nine percent (69%) of the shares of Series A Preferred Stock outstanding as of the date
of this Agreement have approved and adopted this Agreement and the transactions contemplated hereby, and (ii) holders of Common Stock and holders of Series
A Preferred Stock, voting together as a single class (with each share of Common Stock entitled to one vote and each share of Series A Preferred Stock entitled to
one vote for each share of Common Stock issuable upon conversion of the Series A Preferred Stock as of the date of this Agreement), who collectively own of
record and beneficially a majority of the shares of Common Stock outstanding as of the date of this Agreement or issuable upon conversion of the shares of
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Series A Preferred Stock outstanding as of the date of this Agreement have approved and adopted this Agreement and the transactions contemplated hereby. No
other proceedings on the part of the Company or the Stockholders are necessary to authorize this Agreement and the other Transaction Documents to which the
Company is a party, perform its obligations hereunder or thereunder or for the Company to consummate the transactions contemplated herein and therein. This
Agreement and each of the other Transaction Documents to which the Company is or will be a party has been, or upon execution and delivery thereof will be,
duly and validly executed and delivered by the Company and, assuming that this Agreement and the other Transaction Documents to which the Company is a
party constitute the valid and binding agreement of the other parties hereto and thereto, constitute, or upon execution and delivery will constitute, the valid and
binding obligations of the Company, enforceable against the Company in accordance with their respective terms and conditions, except that the enforcement
hereof and thereof may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or other similar laws now or
hereafter in effect relating to creditors’ rights generally and (ii) general principles of equity (regardless of whether enforceability is considered in a proceeding at
law or in equity).
(g) No Conflict; Required Filings and Consents. The execution, delivery and performance by the Company of this Agreement and the other
Transaction Documents to which it is a party do not, and the consummation by the Company of the transactions contemplated herein and therein will not, (i)
violate, conflict with, or result in any breach of any provision of the Company’s Certificate of Incorporation, as amended, or Bylaws, or its Subsidiaries’
respective organizational documents; (ii) violate, conflict with or result in a violation or breach of, or constitute a default (with or without due notice or lapse of
time or both) under, any of the terms, conditions or provisions of any Material Contract, Lease or Oil and Gas Contract, except for those set forth on, or
incorporated by reference into, Company Disclosure Schedule 3.1(g); (iii) subject to obtaining the Consents or making the registrations, declarations or filings set
forth in the next sentence, violate any Applicable Law binding upon the Company or any of its Subsidiaries or by which or to which a material portion of the
Company’s or any of its Subsidiaries’ respective assets is bound. No Consent of any Governmental Authority is required by the Company or any of its
Subsidiaries in connection with the execution, delivery and performance by the Company of this Agreement and the other Transaction Documents to which it is a
party or the consummation by the Company of the transactions contemplated herein or therein, except for (A) the filing of a pre-merger notification and report
form by the Company under the HSR Act, and the expiration or termination of the applicable waiting period thereunder, (B) the filing of the Certificate of
Merger with the Secretary of State of the State of Delaware, and (C) such Consents as may be required under any environmental, health or safety law or
regulation pertaining to any notification, disclosure or required approval necessitated by the Merger or the other transactions contemplated in this Agreement and
the other Transaction Documents to which the Company is a party.
(h) Financial Statements; Absence of Certain Changes or Events.
(i) The Company has furnished or made available to Parent or its representatives copies of (A) the audited consolidated balance sheets of the
Company and its Subsidiaries as of December 31, 2003, together with the audited consolidated statements of operations, cash flows and stockholders’ equity of
the Company and its Subsidiaries for the year
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then ended, and the related notes thereto, accompanied by the reports thereon of KPMG LLP, independent public accountants, and (B) the unaudited consolidated
balance sheet of the Company and its Subsidiaries as of September 30, 2004, together with the related unaudited consolidated statements of operations, cash
flows and stockholders’ equity of the Company and its Subsidiaries for the nine (9)-month period then ended, and (C) the unaudited consolidated balance sheet of
the Company and its Subsidiaries as of October 31, 2004 (the “Balance Sheet”) together with the related unaudited consolidated statements of operations, cash
flows and stockholders’ equity of the Company and its Subsidiaries for the ten (10)-month period then ended (such audited and unaudited financial statements
collectively being referred to herein as the “Financial Statements”). The Financial Statements, together with the notes thereto, have been prepared in
accordance with GAAP (except that the unaudited Financial Statements do not contain all notes required by GAAP, are subject to normal year-end audit
adjustments and do not reflect adjustments required by FAS 123 or FAS 133) applied on a consistent basis throughout the periods covered thereby (except to the
extent disclosed therein or required by changes in GAAP) and fairly present in all material respects the consolidated financial position of the Company and its
Subsidiaries at the dates thereof and the consolidated results of the operations of the Company and its Subsidiaries for the respective periods indicated.
(ii) Except as set forth on Company Disclosure Schedule 3.1(h)(ii), as of the date of this Agreement there is no liability, contingent or
otherwise, of the Company or any of its consolidated Subsidiaries that is not reflected or reserved against in the Balance Sheet, other than liabilities that are either
(A) liabilities incurred in the ordinary course of business and consistent with past practices of the Company since October 31, 2004 (the “Balance Sheet Date”);
(B) any such liability that would not be required to be presented in unaudited interim financial statements prepared in conformity with GAAP; (C) liabilities
under this Agreement; or (D) liabilities for fees and expenses incurred in connection with the transactions contemplated by this Agreement and the other
Transaction Documents. Company Disclosure Schedule 3.1(h)(ii) contains a list of all of the Company’s Letters of Credit.
(iii) Except as set forth on Company Disclosure Schedule 3.1(h)(iii), or as provided in or contemplated by this Agreement or the other
Transaction Documents, since the Balance Sheet Date and prior to the date of this Agreement, the Company and each of its Subsidiaries have conducted their
respective businesses in all material respects in the ordinary course of business and consistent with past practices of the Company. Except as set forth on
Company Disclosure Schedule 3.1(h)(iii), since the Balance Sheet Date (A) and prior to the date of this Agreement, neither the Company nor any of its
Subsidiaries has acted or failed to act in a manner that would have been prohibited by Section 4.1 if the terms of such Section had been in effect as of and after
the Balance Sheet Date and prior to the date of this Agreement; and (B) there has not occurred, and neither the Company nor any of its Subsidiaries has incurred
or suffered, any change, circumstance, effect, event or fact that has resulted in or would reasonably be expected to result in a Material Adverse Effect.
(iv) Except as set forth on Company Disclosure Schedule 3.1(h)(iv), or as provided in or contemplated by this Agreement or the other
Transaction Documents, since November 30, 2004: (A) cancelled, waived or released any rights or claims against, or indebtedness owed by, third parties; (B)
made any advances or loans to anyone other than a Subsidiary; (C) cancelled, compromised, waived, or released any right or claim (or series of
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related rights and claims) involving more than $100,000 individually or $300,000 in the aggregate, or outside the ordinary course of business; or (D) made any
loan to, or entered into any other transaction with, any of its directors, officers, or employees.
(i) Internal Accounting Controls. The Company keeps accounts, books, and records that accurately, fairly, and in reasonable detail reflect its assets,
business, liabilities, and transactions. In addition, the Company maintains a system of internal accounting controls sufficient to provide reasonable assurance that
(i) transactions are accurately and promptly recorded to permit the preparation of the Company’s financial statements, (ii) transactions are executed in accordance
with management’s general or specific authorizations, and (iii) access to the Company’s assets is permitted only in accordance with management’s general or
specific authorization. The Company has not made or received any payment in violation of application law.
(j) Accounts Receivable. Except as otherwise set forth in the Company Disclosure Schedule 3.1(j), (i) all of the accounts, notes and loans receivable
that have been recorded on the books of the Company and its Subsidiaries are bona fide and represent accounts, notes and loans receivable validly due for goods
sold or services rendered and are reasonably expected to be collected in full within ninety (90) days after the applicable invoice or note maturity date (other than
such accounts, notes and loans receivable that do not have a book value as of the date hereof in excess of $500,000 in the aggregate); and (ii) except for Permitted
Liens, all of such accounts, notes and loans receivable are free and clear of any and all Liens and other adverse claims and charges, and none of such accounts,
notes or loans receivable is subject to any offsets or claims of offset.
(k) Bank Accounts. Company Disclosure Schedule 3.1(k) describes each bank or brokerage account that the Company maintains at any financial
institution or otherwise, including any lock box arrangements or safe deposit boxes.
(l) Compliance with Applicable Laws. Except as set forth on Company Disclosure Schedule 3.1(l), each of the Company and its Subsidiaries (i) has,
since the Balance Sheet Date, complied with, is in compliance with and has operated its business and maintained its assets in compliance with all Applicable
Laws, and (ii) holds all permits, licenses, variances, exemptions, orders, franchises and approvals of all Governmental Authorities necessary for the lawful
conduct of its business (the “Company Permits”). Except as set forth on Company Disclosure Schedule 3.1(l), the Company and its Subsidiaries are in
compliance with the terms of the Company Permits. As of the date of this Agreement, except as set forth on Company Disclosure Schedule 3.1(l), no
investigation or review by any Governmental Authority with respect to the Company or any of its Subsidiaries is pending or, to the Knowledge of the Company,
threatened. For purposes of this Section 3.1(l), the term “Applicable Laws,” as used in clause (i) above, shall not include any Environmental Laws, any
Applicable Laws relating to Taxes or the subject matters of Sections 3.1(q), (r) or (t).
(m) Absence of Litigation. Except as set forth on Company Disclosure Schedule 3.1(m), as of the date of this Agreement there is no claim, action,
suit, inquiry, judicial or administrative proceeding, grievance or arbitration pending or, to the Knowledge of the Company, threatened against the Company or
any of its Subsidiaries by or before any arbitrator
24
or Governmental Authority, nor are there any reviews or investigations relating to the Company or any of its Subsidiaries pending or, to the Knowledge of the
Company, threatened by or before any arbitrator or any Governmental Authority. There are no outstanding judgments, decrees, injunctions, awards or orders
against the Company or any of its Subsidiaries.
(n) Insurance. Set forth on Company Disclosure Schedule 3.1(n), as of the date of this Agreement, is a true, correct and complete list of all workers’
compensation, title, fire, general liability, fiduciary liability, directors’ and officers’ liability, theft and other forms of property and casualty insurance held by the
Company and each of its Subsidiaries and all fidelity bonds that are material to the Company and its Subsidiaries. Except for policies that have been, or are
scheduled to be, terminated in the ordinary course of business and consistent with past practices of the Company and in accordance with the terms thereof, each
of the insurance policies set forth on Company Disclosure Schedule 3.1(n) is in full force and effect.
(o) Certain Property.
(i) Set forth on Company Disclosure Schedule 3.1(o)(i) is a list of all the Owned Real Property. Except as set forth on Company Disclosure
Schedule 3.1(o)(i), the Company or a Subsidiary of the Company has title insurance insuring indefeasible, fee simple title in and to the Owned Real Property,
free and clear of all Liens other than Permitted Liens, except as specifically noted in such title insurance policies. The material improvements on each parcel of
Owned Real Property have access to such sewer, water, gas, electric, telephone and other utilities as are necessary to allow the business of the Company and each
of its Subsidiaries operated thereon to be operated in the ordinary course of business and consistent with past practices of the Company as currently operated.
Except as set forth on Company Disclosure Schedule 3.1(o)(i), the material improvements located on each parcel of Owned Real Property are in sufficiently good
condition (except for ordinary wear and tear) to allow the business of the Company and its Subsidiaries to be operated in the ordinary course of business and
consistent with past practices of the Company as currently operated. The current use of the Owned Real Property by the Company and its Subsidiaries does not
violate in any material respect any restrictive covenants of record listed in the applicable title insurance policies as affecting any of the Owned Real Property.
(ii) Except for Leased Real Property obligations which are less than $50,000 annually and as set forth on Company Disclosure Schedule
3.1(o)(ii) is a list of all Leased Real Property. Each lease set forth on Company Disclosure Schedule 3.1(o)(ii) is a valid and binding obligation of the Company
or one of its Subsidiaries and (subject to any of such leases being terminated in the ordinary course of business and consistent with past practices of the Company
and in accordance with the terms thereof) is in full force and effect. To the Knowledge of the Company, except as otherwise set forth on Company Disclosure
Schedule 3.1(o)(ii), neither the Company nor any of its Subsidiaries is in default in any material respect under any lease set forth on Company Disclosure
Schedule 3.1(o)(ii).
(p) Liens and Encumbrances. As of the date of this Agreement, all of the material assets of the Company and its Subsidiaries are free and clear of all
Liens except (i) Permitted Encumbrances and (ii) Liens set forth on Company Disclosure Schedule 3.1(p) (the Liens referred to in clauses (i) and (ii) being
“Permitted Liens”).
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(q) Environmental Matters. Except as disclosed on Company Disclosure Schedule 3.1(q):
(i) The Real Property, Oil and Gas Properties, Oil and Gas Interests and the operations of the Company and its Subsidiaries thereon comply
with all applicable Environmental Laws.
(ii) As of the date of this Agreement, no judicial proceedings are pending or, to the Knowledge of the Company, threatened against the
Company or any of its Subsidiaries alleging the violation of any applicable Environmental Laws, and, as of the date of this Agreement, there are no
administrative proceedings pending or, to the Knowledge of the Company, threatened, against the Company or any of its Subsidiaries alleging the violation of
any applicable Environmental Laws and, as of the date of this Agreement, no written notice from any Governmental Authority or any private or public Person
has been received by the Company or any of its Subsidiaries claiming any violation of any applicable Environmental Laws by any Real Property, Oil and Gas
Property or Oil and Gas Interest, or requiring any remediation, clean-up, modification, repairs, work, construction, alterations or installations on any Real
Property, Oil and Gas Property or Oil and Gas Interest that are necessary to comply with any applicable Environmental Laws and that have not been complied
with or otherwise resolved to the satisfaction of the party giving such notice, and, to the Knowledge of the Company, there are no conditions or circumstances
that would reasonably be expected to result in the receipt of such written notice.
(iii) All permits, registrations, licenses and authorizations required to be obtained or filed by the Company or any of its Subsidiaries under
any applicable Environmental Laws in connection with the Company’s or any of its Subsidiaries’ operations, including those activities relating to the generation,
use, storage, treatment, disposal, release or remediation of Hazardous Substances have been duly obtained or filed, and the Company and each of its Subsidiaries
is in compliance with the terms and conditions of all such permits, registrations, licenses and authorizations. To the Knowledge of the Company, there are no
conditions or circumstances that would limit or preclude the Company or its Subsidiaries from renewing such permits, registrations, licenses and authorizations.
(iv) All Hazardous Substances used or generated by the Company or any of its Subsidiaries at or on any of the Owned Real Property, Leased
Real Property, Oil and Gas Property or Oil and Gas Interest have been managed in such manner as not to result in any Environmental Liabilities.
(v) To the Knowledge of the Company, there have been no releases of Hazardous Materials on, under or from the Company or its
Subsidiaries’ real properties, and there are no investigations, remediations, removals, or monitoring of Hazardous Materials required under Environmental Laws
at such properties.
(vi) As of the date of this Agreement, neither the Company nor any of its Subsidiaries has received any written notification from any source
advising the Company or any of its Subsidiaries that (A) it is a potentially responsible party under CERCLA or any other applicable Environmental Laws, (B)
any Real Property, Oil and Gas Property or Oil and Gas
26
Interest is identified or proposed for listing as a federal National Priorities List (“NPL”) (or state-equivalent) site or a Comprehensive Environmental Response,
Compensation and Liability Information System (“CERCLIS”) (or state-equivalent) site or (C) any facility to which it currently transports or otherwise arranges
for the disposal of Hazardous Substances is identified or proposed for listing as an NPL (or state-equivalent) site or CERCLIS (or state-equivalent) site.
(vii) Neither the Company nor its Subsidiaries have received any written notice asserting an alleged liability or obligation under any
Environmental Laws with respect to the investigation, remediation, removal, or monitoring of any Hazardous Substances at, under, or released or threatened to be
released from any offsite non-Company real property and, to the Knowledge of the Company, there are no conditions or circumstances that would reasonably be
expected to result in the receipt of such written notice.
(r) Taxes. Except as set forth on Company Disclosure Schedule 3.1(r):
(i) (A) All material Tax Returns which have been required to be filed by the Company or any of its Subsidiaries have been timely filed; (B)
all material Taxes which have become due by the Company or any of its Subsidiaries have been timely paid in full; (C) all withholding Tax requirements
imposed on the Company or any of its Subsidiaries have been satisfied in full in all material respects; (D) there is not in force any waiver or agreement for any
extension of time for the assessment or payment of any material Tax with respect to the periods covered by any such Tax Returns; (E) no material claim,
assessment or deficiency against the Company or any of its Subsidiaries for any Taxes has been asserted in writing by any Government Authority with respect to
any such Tax Returns; and (F) the Company and its Subsidiaries have not executed any extension agreement or waiver of any statute of limitations with respect
to the assessment or collection of any tax against them.
(ii) There is no existing Tax sharing agreement that may or will require that any payment be made by or to the Company or any of its
Subsidiaries on or after the Closing Date.
(iii) There is no contract, agreement, plan or arrangement covering any Person that as a consequence of the transactions contemplated by
this Agreement or otherwise, could give rise to the payment of any amount that would not be deductible by the Company or any of its Subsidiaries, as the case
may be, by reason of Section 280G of the Code.
(iv) Except as stated on Company Disclosure Schedule 3.1(r)(iv), neither the Internal Revenue Service (“IRS”) nor any other taxing
authority has contacted the Company or its Subsidiaries concerning a future audit or examination of any tax reports and returns that include the Company or its
Subsidiaries. In addition, no such audit or examination is in process or has occurred with respect to any period for which the statue of limitations has not expired.
(s) Material Contracts. Set forth on, or incorporated by reference into, Company Disclosure Schedule 3.1(s), as of the date of this Agreement, is a
true, correct and complete list of all Material Contracts (excluding any Easements) to which the Company or any of its Subsidiaries is a party or by which any of
the Company or any of its Subsidiaries is
27
otherwise bound. A true, correct and complete copy of each Material Contract (excluding any Easements) has been furnished or made available to Parent or its
representatives. As of the date of this Agreement, neither the Company nor any of its Subsidiaries is in default under any such Material Contract, except as set
forth on Company Disclosure Schedule 3.1(s). To the Company’s Knowledge, as of the date of this Agreement, there has not occurred any event that (with the
lapse of time or the giving of notice or both) would constitute a default under any Material Contract by the Company or any of its Subsidiaries, except as set forth
on Company Disclosure Schedule 3.1(s).
(t) ERISA Compliance; Labor.
(i) Except as set forth on Company Disclosure Schedule 3.1(t), neither the Company nor any other entity required to be aggregated with the
Company under Section 414 of the Code (the “Aggregated Group”) sponsors, maintains or contributes to any Employee Benefit Plan.
(ii) As of the Effective Time, the Company will not sponsor, maintain or have any obligation to contribute to any Employee Benefit Plan
and, except as provided in Section 2.7, will not have any liability under any Employee Benefit Plan.
(iii) None of the Company or any of its Subsidiaries will have any employees as of the Effective Time or, except as provided in Section 2.7,
any obligations to any former employees.
(iv) No labor associations, organizations, or unions have been certified to represent any employee of the Company, and no collective
bargaining agreement or other labor union contract has been requested by any employee or group of employees of the Company, and no discussions or
negotiations with respect to any such agreement or contract have occurred.
(v) The Company and its Subsidiaries are in material compliance with all laws, rules, regulations and orders relating to the employment of
labor, including all such laws, rules, regulations and orders relating to wages, hours, collective bargaining, discrimination, civil rights, safety and health, workers’
compensation and the collection and payment of withholding or Social Security taxes and similar taxes.
(u) Reserve Information. The underlying factual information provided to Netherland, Sewell & Associates, Inc. by or on behalf of the Company or
its Subsidiaries in connection with their Reserve Report dated December 1, 2004 (the “Reserve Report”), to the extent that it was relied upon by Netherland,
Sewell & Associates, Inc. in the preparation of its report on the Company’s proved reserves as of December 1, 2004 was, at the time of delivery, true and correct
in all material respects. The Company has no Knowledge of any material errors in such underlying factual information supplied to Netherland, Sewell &
Associates, Inc. for purposes of preparing such report and the conclusions in such report are not in any material way unreasonable when compared with the
Company’s own evaluation of the properties included in such report as of December 1, 2004 taken as a whole. The Company has provided Parent with a true,
correct and complete copy of the Reserve Report. Except for changes (including changes in
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commodity prices or service costs) generally affecting the oil and gas industry and disposition of Oil and Gas Properties since the date thereof, there have been
no changes in respect of the Oil and Gas Properties covered by the Reserve Report; provided further that changes in evaluation methods, criteria or techniques
used by Parent will not constitute such a change. Set forth in Company Disclosure Schedule 3.1(u)-1 is a list of all material Oil and Gas Properties that were
acquired by the Company subsequent to the date of the Reserve Report. Set forth in Company Disclosure Schedule 3.1(u)-2 is a list of all material Oil and Gas
Properties that were included in the Reserve Report that have been disposed of prior to the date of this Agreement.
(v) Intellectual Property. Set forth on Company Disclosure Schedule 3.1(v) is a list of all issued Patents and pending Patent applications, registered
trademarks and registered domain names owned by the Company or one of its Subsidiaries and used in the United States. The Company or one of its Subsidiaries
owns, or has the license or right to use in the United States, all Intellectual Property currently used and necessary to conduct its business as presently conducted.
To the Knowledge of the Company, as of the date of this Agreement, no third party has asserted against the Company or any of its Subsidiaries a claim in writing
that the Company or any of its Subsidiaries is infringing the Intellectual Property of such third party that has not been resolved. To the Knowledge of the
Company, as of the date of this Agreement, no third party is infringing the Intellectual Property owned or exclusively licensed by the Company or one of its
Subsidiaries. The Company is a party to a Licensing Agreement with Antero II, pursuant to which the Company has granted to Antero II a non-exclusive,
perpetual, irrevocable, royalty-free, worldwide, fully paid-up license to make use of the Company’s seismic data collected prior to the Effective Time. The
Company and its Subsidiaries are parties to a Licensing Agreement with Antero II pursuant to which Antero II has granted to the Company and its Subsidiaries a
non-exclusive license to use the name “Antero” for a limited period of time.
(w) Status and Operation of Oil and Gas Properties.
(i) The Leases which are included in the Oil and Gas Properties are (A) in full force and effect in accordance with their respective terms, (B)
all royalties, rentals and other payments due under the Leases have been properly and timely paid and (C) there are currently pending no written requests or
demands for payments, adjustments of payments or performance pursuant to obligations under the Leases.
(ii) Company Disclosure Schedule 3.1(w)(ii) sets forth the Scheduled Oil and Gas Interests.
(iii) Company Disclosure Schedule 3.1(w)(iii) sets forth (A) a map depicting the pipeline portion of the Pipeline Assets, (B) a map depicting
the pipeline portion of the Gathering Assets other than the Pipeline Assets, and (C) a list of tangible personal property with a value in excess of $100,000
associated with the Pipeline Assets (the “Other Pipeline Assets”). Except as set forth on Company Disclosure Schedule 3.1(w)(iii), the Company has Good and
Marketable Title for all Oil and Gas Properties set forth in the Reserve Report and all Scheduled Oil and Gas Interests and Good and Defensible Title to the
Other Pipeline Assets. Without limiting the generality of the foregoing, the Company owns and will at the Effective Time own the Net Revenue Interest, and will
own the related Working Interest, in each case as
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set forth on Company Disclosure Schedule 3.1(w)(ii) for each of the Scheduled Oil and Gas Interests. The Other Pipeline Assets are in good operating condition,
ordinary wear and tear excepted, except where the failure to maintain such personal property in such condition would not have, individually or in the aggregate, a
Material Adverse Effect.
(iv) The Oil and Gas Contracts and Leases of the Company and any of its Subsidiaries are set forth on Company Disclosure Schedule
3.1(w)(iv) are in full force and effect in accordance with their respective terms. None of the Company or any of its Subsidiaries is in breach of any of its material
obligations under any such Oil and Gas Contract or Lease, nor to the Company’s Knowledge, is any other party to such Oil and Gas Contract or Lease in breach
of any of its material obligations thereunder.
(v) Except as set forth on Company Disclosure Schedule 3.1(w)(v), to the Knowledge of the Company, all pipelines, gathering systems,
plants or other material facilities owned or used by the Company or any of its Subsidiaries are located on easements, rights-of-way or on real property, permits or
licenses owned or leased by the Company and its Subsidiaries.
(vi) Every well included in the Oil and Gas Interests has been drilled and completed within the boundaries covered by the Oil and Gas
Properties or within the limits otherwise permitted by contract, pooling or unit agreement and by Applicable Laws. No well located on the Oil and Gas Interests
is subject to penalties on allowables after the date hereof because of any overproduction or any other violation of Applicable Laws of any Governmental
Authority, which would prevent such well from being entitled to its full legal and regular allowable, from and after the date hereof as prescribed by any
Governmental Authority.
(x) Prepayments; Hedging; Calls. Except as set forth in Company Disclosure Schedule 3.1(x):
(i) neither the Company nor any of its Subsidiaries has any outstanding obligations for the delivery of Hydrocarbons attributable to any of
the Oil and Gas Interests of the Company or any of its Subsidiaries in the future on account of prepayment, advance payment, take-or-pay or similar obligations
without then or thereafter being entitled to receive full value therefor;
(ii) neither the Company nor any of its Subsidiaries is bound by any future, hedge, swap, collar, put, call, floor, cap, option or other contract
that is intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons, interest rates,
currencies or securities; and
(iii) no Person has any call upon, option to purchase, or similar rights with respect to the production of Hydrocarbons attributable to the Oil
and Gas Interests of the Company and its Subsidiaries, except for any such call, option or similar right at market prices, and upon consummation of the
transactions contemplated by this Agreement, the Company or its Subsidiaries will have the right to market production from the Oil and Gas Interests of the
Company and its Subsidiaries on terms no less favorable than the terms upon which such production is currently being marketed.
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(y) Broker’s Commissions. Except as set forth on Company Disclosure Schedule 3.1(y), neither the Company nor any Subsidiary thereof has,
directly or indirectly, entered into any agreement with any Person that would obligate the Company or any Subsidiary thereof to pay any commission, brokerage
fee or “finder’s fee” in connection with the transactions contemplated herein.
(z) Excluded Assets and Liabilities. Prior to Closing the Company has or will have transferred the following assets to Antero II, and Antero II has
accepted such assets and all liabilities related thereto:
(i) the office equipment, software and other personal property set forth on Company Schedule 3.1(z)(i);
(ii) the Company’s office leases for the Fort Worth, Texas and Denver, Colorado offices; and
(iii) all compensation and benefit plans and obligations of any kind.
(aa) Affiliate Transactions. Except as disclosed in Company Disclosure Schedule 3.1(aa), (i) there is no Debt between the Company or any
Subsidiary, on the one hand, and any Securityholder or any Affiliate (other than the Company or any Subsidiary) of such Securityholder, on the other, (ii) none of
the Securityholders nor any such Affiliate provides or causes to be provided any assets, services or facilities to the Company or any Subsidiary, and (iii) neither
the Company nor any Subsidiary provides or causes to be provided any assets, services or facilities to any Securityholder or any such Affiliate. Except as
disclosed in Company Disclosure Schedule 3.1(aa), each of the transactions listed in Company Disclosure Schedule 3.1(aa) was incurred or engaged in, as the
case may be, on an arm’s-length basis and in the ordinary course of business.
(bb) No Competing Interest. Except as stated in the Company Disclosure Schedule 3.1(bb), none of the officers of the Company own, directly or
indirectly, any interest in, or serves as a director, officer, or employee of, or consultant to, other than a passive investor of, any corporation, partnership, firm,
association, or business organization, entity or enterprise which is a supplier or customer of the Company or its Subsidiaries or is in any way associated with or
involved in the business conducted by the Company or its Subsidiaries or is competing with the Company in the Barnett Shale formation of the Fort Worth
Basin.
3.2 Representations and Warranties of Parent and Merger Subsidiary. Except as set forth on Parent Disclosure Schedule, as of the date of this
Agreement and as of the Effective Time (except to the extent such representations and warranties speak expressly as of an earlier date), Parent and the Merger
Subsidiary jointly and severally represent and warrant to the Company and the Securityholders as follows:
(a) Organization Good Standing and Other Matters. Each of Parent and Merger Subsidiary is a corporation duly organized, validly existing and in
good standing under the laws of its respective jurisdiction of incorporation, has all requisite power and authority to own, lease and operate its properties and to
carry on its business as now being conducted, and is duly qualified to do business as a foreign corporation in good standing to conduct business in
31
each jurisdiction in which the business it is conducting, or the operation, ownership or leasing of its properties, makes such qualification necessary, other than in
such jurisdictions where the failure so to qualify would not materially impair the ability of Parent and Merger Subsidiary to consummate the transactions
contemplated in this Agreement. Parent directly owns all of the issued and outstanding capital stock of Merger Subsidiary free and clear of all Liens. A true,
correct and complete copy of Parent’s Certificate of Incorporation and Bylaws and the certificate of incorporation and bylaws of Merger Subsidiary, as in effect
on the date of this Agreement, has been furnished to the Company or its representatives.
(b) Authority. Each of Parent and Merger Subsidiary has all requisite power and authority to execute and deliver this Agreement and the other
Transaction Documents to which it is a party, to perform its obligations hereunder and thereunder, and to consummate the transactions contemplated herein and
therein. The execution, delivery and performance of this Agreement and the other Transaction Documents by each of Parent and Merger Subsidiary and the
consummation of the transactions contemplated herein and therein have been duly and validly authorized by all necessary corporate or stockholder action on the
part of Parent and Merger Subsidiary. No other proceedings on the part of Parent or Merger Subsidiary are necessary to authorize this Agreement and the other
Transaction Documents to which Parent or Merger Subsidiary is a party, to perform Parent’s or Merger Subsidiary’s obligations hereunder and thereunder or for
Parent and Merger Subsidiary to consummate the transactions contemplated herein and therein. This Agreement and the other Transaction Documents to which
either of Parent or Merger Subsidiary is or will be a party have been, or upon execution and delivery will be, duly and validly executed and delivered by each of
Parent and Merger Subsidiary, as applicable, and, assuming that this Agreement and the other Transaction Documents constitute the valid and binding agreement
of the other parties thereto, constitute, or upon execution and delivery will constitute, the valid and binding obligations of Parent and Merger Subsidiary,
enforceable against Parent and Merger Subsidiary in accordance with their respective terms and conditions, except that the enforcement hereof and thereof may
be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or other similar laws now or hereafter in effect relating to
creditors’ rights generally and (ii) general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity).
(c) No Conflict; Required Filings and Consents. The execution, delivery and performance by Parent and Merger Subsidiary of this Agreement and
the other Transaction Documents to which either is a party do not, and consummation of the transactions contemplated herein and therein will not, (i) violate,
conflict with, or result in any breach of any provisions of the Certificate of Incorporation or Bylaws of Parent or Merger Subsidiary; (ii) violate, conflict with or
result in a violation or breach of, or constitute a default (with or without due notice or lapse of time or both) under, any of the terms, conditions or provisions of
any material contract, loan or credit agreement, note, bond, mortgage, indenture or deed of trust, or any license, lease, agreement, or other instrument or
obligation, to which Parent or Merger Subsidiary is a party or by which Parent or Merger Subsidiary or any material portion of their respective assets is bound; or
(iii) subject to obtaining the Consents or making the registrations, declarations or filings set forth in the next sentence, violate any Applicable Law binding upon
Parent or Merger Subsidiary or by which they or any material portion of their respective assets is bound, except, with respect to clauses (ii) and (iii), such
violations, conflicts, breaches or defaults as would not interfere with
32
the ability of either of Parent or Merger Subsidiary to perform its obligations under this Agreement and the other Transaction Documents to which it is a party.
No Consent of any Governmental Authority is required by or with respect to Parent or Merger Subsidiary in connection with the execution, delivery and
performance by Parent and Merger Subsidiary of this Agreement and the other Transaction Documents to which either of them is a party or the consummation of
the transactions contemplated herein and therein, except for (A) filings under the HSR Act, (B) the filing of the Certificate of Merger with the Secretary of State
of the State of Delaware, (C) such Consents as may be required under any environmental, health or safety law or regulation pertaining to any notification,
disclosure or required approval necessitated by the Merger or the other transactions contemplated by this Agreement and the other Transaction Documents to
which Parent or Merger Subsidiary is a party, and (D) such other Consents, the failure of which to obtain would not interfere with the ability of Parent and
Merger Subsidiary to perform their respective obligations under this Agreement and the other Transaction Documents to which either of them is or will be a
party.
(d) Litigation. As of the date of this Agreement, there is no action, suit or judicial or administrative proceeding pending or, to the Knowledge of
Parent or Merger Subsidiary, threatened against Parent or Merger Subsidiary relating to the transactions contemplated by this Agreement or which, if adversely
determined, would adversely affect the ability of Parent or Merger Subsidiary to perform its obligations and agreements under this Agreement and the other
Transaction Documents to which it is or will be a party and to consummate the transactions contemplated herein and therein.
(e) Surviving Corporation After the Merger. Assuming that the representations and warranties of the Company contained in this Agreement are true
and correct in all material respects, at and immediately after the Effective Time, and after giving effect to the Merger and the other transactions contemplated
herein, the Surviving Corporation (i) will be solvent (in that both the fair value of its assets will not be less than the sum of its debts and that the present fair
saleable value of its assets will not be less than the amount required to pay its probable liability on its debts as they become absolute and matured); (ii) will have
adequate capital with which to engage in its business; and (iii) will not have incurred and does not plan to incur debts beyond its ability to pay as they become
absolute and matured.
(f) SEC Reports; Financial Statements.
(i) Parent has filed and made available to the Company all forms, reports and other documents required to be filed by Parent with the
Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”) since January 1, 2004. All such required
forms, reports and other documents (including those that Parent may file after the date hereof and prior to the Closing) are referred to herein as the “Parent SEC
Reports.” The Parent SEC Reports (i) were or will be filed on a timely basis, (ii) were or will be prepared in compliance with the applicable requirements of the
Exchange Act and the rules and regulations of the SEC thereunder, and (iii) did not, or will not at the time they were or are filed, contain any untrue statement of
a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances
under which they were made, not misleading. Since the last date on which a Parent SEC Report was filed, there has been no material adverse change in the
assets, liabilities,
33
condition (financial or otherwise), operating results, business or prospects of Parent or in the ability of Parent to perform its obligations under this Agreement or
that could materially impair or prohibit the consummation of the transactions contemplated by this Agreement.
(ii) Each of the consolidated financial statements (including, in each case, any related notes and schedules) contained or to be contained in
the Parent SEC Reports (i) complied or will comply as to form in all material respects with applicable accounting requirements and the published rules and
regulations of the SEC with respect thereto, (ii) were or will be prepared in accordance with GAAP (except as may be indicated in the notes to such financial
statements or, in the case of unaudited statements, as permitted by the SEC on Form 10-Q under the Exchange Act) and (iii) fairly presented or will fairly present
the consolidated financial position of Parent and its subsidiaries as of the dates and the consolidated results of its operations and cash flows for the periods
indicated, consistent with the books and records of Parent and its subsidiaries, except that the unaudited interim financial statements were or will be subject to
normal and recurring year-end adjustments that were not or are not expected to be material.
ARTICLE 4
COVENANTS OF THE COMPANY
4.1 Conduct of Business.
(a) Except as expressly permitted under this Agreement or in Company Disclosure Schedule 4.1 or to the extent that Parent shall otherwise consent
in writing or by electronic transmission (which consent shall not be unreasonably withheld), from the date of this Agreement until the Closing, the Company
covenants and agrees with Parent that the Company shall not, and shall not permit any of its Subsidiaries to:
(i) fail to use all commercially reasonable efforts to (A) preserve substantially intact the Company’s and each of its Subsidiaries’ present
business organization and (B) preserve its present relationships with customers, suppliers and others having business dealings with it;
(ii) fail to use all commercially reasonable efforts to maintain all tangible assets of the Company and each of its Subsidiaries in good
operating order, condition, and repair, except for ordinary wear and tear;
(iii) except for amendments, modifications, terminations or non-renewals in the ordinary course of business and consistent with past
practices of the Company and its Subsidiaries, amend, modify, terminate or fail to use its commercially reasonable efforts to renew any Material Contract;
(iv) merge or consolidate with or into any other Person, dissolve or liquidate;
(v) acquire (including, without limitation, by merger, consolidation or the acquisition of any equity interest or assets), sell, lease or dispose
of any assets, except in accordance with all of the following: (A) the ordinary course of business consistent with past
34
practices of the Company and its Subsidiaries, (B) the Company’s 2005 first quarter budget attached hereto as Company Disclosure Schedule 4.1(a)(v), and (C)
limited to expenditures in connection with acquisition of new oil and gas leases, renewals of oil and gas leases, non-producing leasehold acquisitions, and
acquisitions of producing Oil and Gas Properties as identified in the said 2005 budget;
(vi) mortgage, pledge or subject to any Lien, other than Permitted Liens, any of its assets;
(vii) except as required by GAAP or by Applicable Law, change any of the accounting principles or practices used by the Company or its
Subsidiaries;
(viii) pay, discharge or satisfy any claims, liabilities or obligations (absolute, accrued, asserted or unasserted, contingent or otherwise), other
than in the ordinary course of business and consistent with past practices of the Company and its Subsidiaries;
(ix) (A) except for dividends or distributions payable to the Company and dividends to be declared in connection with the preferred rights of
the Series A Preferred Stock, declare, set aside or pay any dividends on, or make any other distributions (whether in cash, securities or property) in respect of,
any of its capital stock or other voting securities, (B) adjust, split, combine, or reclassify any of its capital stock or other voting securities or issue or authorize the
issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock or other voting securities, or (C) except for the shares of
unvested Common Stock purchased pursuant to Section 4.10, and except in the case of an employee whose employment has terminated, purchase, redeem or
otherwise acquire any shares of capital stock or other voting securities of the Company or any of its Subsidiaries or any Options;
(x) except for the issuance of options to purchase not more than 566,050 shares of capital stock of the Company pursuant to the Stock
Option Plan and not more than 8,823,785 shares of capital stock of the Company issuable upon the exercise of any Options or upon the conversion of shares of
Series A Preferred Stock outstanding on the date of this Agreement or as required by the terms of any written contracts between the Company or any of its
Subsidiaries and an employee thereof as in existence on the date of this Agreement, issue, sell, pledge, dispose of, encumber or deliver (whether through the
issuance or granting of any options, warrants, commitments, subscriptions, rights to purchase or otherwise) any capital stock or voting securities of any class or
any securities convertible into or exercisable or exchangeable for shares of capital stock or voting securities of any class (except for the issuance of certificates in
replacement of lost certificates);
(xi) change or amend its charter documents or bylaws;
(xii) except under the Loan Agreements in the ordinary course of business and consistent with past practices of the Company and its
Subsidiaries and in any event not to exceed an aggregate amount of total borrowings of more than $193 million whether under the Loan Agreements or new
working capital facility, and except for capital leases and current liabilities (excluding short-term Debt) within the meaning of GAAP incurred in the ordinary
course of business and consistent with past practices of the Company, incur or assume any
35
indebtedness for borrowed money, assume, guarantee, endorse or otherwise become liable or responsible for the obligations of any other Person (other than
endorsements of checks in the ordinary course) or make any loans, advances or capital contributions to, or investments in, any Person (other than among the
Company and its Subsidiaries and among such Subsidiaries, and other than advances to directors, officers and employees in the ordinary course of business and
consistent with past practices of the Company);
(xiii) make any settlement of or compromise any Tax liability, change any Tax election or Tax method of accounting or make any new Tax
election or adopt any new Tax method of accounting;
(xiv) fail to (A) transfer on or prior to the Effective Time all Employee Benefit Plans and all employees to Antero II and (B) cause Antero II
to assume all related obligations;
(xv) waive any rights relating to the Oil and Gas Properties or Oil and Gas Interests;
(xvi) release or abandon any Oil and Gas Properties or Oil and Gas Interests (except the abandonment of a lease, license, or concession upon
the expiration of its primary term or upon failure to satisfy drilling commitments);
(xvii) commence or consent to any material operation on any Oil and Gas Properties which are not a property identified in the Company’s
proposed 2005 drilling schedule attached hereto as Company Disclosure Schedule 4.1(a)(xvii) (except for emergency operations, in which case the Company
shall promptly notify Parent and from the date of Parent’s response to such notice shall once again be subject to the limitations contained in this subsection
(xvii)); for purposes of this subsection (xvii) an operation shall be deemed material if its estimated cost is $100,000 or more net to the interest of the Company;
(xviii) convey, farmout, encumber, mortgage, pledge, or dispose of any Oil and Gas Properties or Oil and Gas Interests except for Permitted
Liens and pooling activities in the ordinary course;
(xix) other than as contemplated by Section 4.8, enter into any new material contracts or agreements relating to any Oil and Gas Properties
or Oil and Gas Interests, other than periodic production purchase and sale agreements terminable on not more than thirty (30) days notice;
(xx) make, institute, or introduce any methods of purchase, sale, lease, management, accounting, billing, or operation of the Oil and Gas
Properties or Oil and Gas Interests or other business of the Company that are not customary in the industry and consistent with the Company’s past practices;
(xxi) enter into any contract or commitment or engage in any transaction not in the ordinary course of the Company’s business consistent
with the Company’s past practices; or
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(xxii) authorize, or commit or agree to take, any of the foregoing actions.
(b) Likewise, except as otherwise permitted under this Agreement or in Company Disclosure Schedule 4.1 or to the extent that Parent shall
otherwise consent in writing or by electronic transmission (which consent shall not be unreasonably withheld), from the date of this Agreement until the Closing,
the Company covenants and agrees with Parent that the Company shall, and shall cause each of its Subsidiaries to:
(i) use all commercially reasonable efforts to carry on the Company’s business in its usual, regular, and ordinary manner, and preserve intact
the Company’s present business organization relating to that business and the Company’s relationships with suppliers, customers, and other persons having
business dealings with the Company;
(ii) use all commercially reasonable efforts to maintain all tangible assets and property of the Company in good operating order, condition,
and repair, ordinary wear and tear excepted;
(iii) maintain the books, accounts, and records of the Company consistently with prior years and in accordance with sound commercial
practices;
(iv) promptly notify Parent of the receipt of any notice or claim, or any threat of a notice or claim, of which the Company or any of its
Affiliates become aware after such date, relating to any default or breach by the Company or any of its Affiliates under, or any termination or cancellation of, any
Material Contract, Lease or Oil and Gas Contract (or in the case of any production sales contract, any notice of intent to exercise any price renegotiation or other
option available to the purchasers thereunder, to terminate such contract, to alter pricing, delivery, or other material provisions thereof, or to contest or dishonor
any material provisions thereof);
(v) use all commercially reasonable efforts to maintain in force the insurance policies referred to in Section 3.1(n), use the Company’s
reasonable efforts to have Parent added as an additional named insured under such insurance with respect to the period beginning on the date of this Agreement
(or, if acceptable to the insurer(s)) and ending at the Effective Time, and promptly notify Parent of any condemnation of, or any loss of or damage to, any
material assets of the Company of which the Company or any of its Affiliates becomes aware;
(vi) operate the Oil and Gas Properties in compliance in all material respects with all applicable laws, rules, regulations, and orders;
(vii) notify Parent before the Company or any of its Affiliates fail to pay any rentals, shut-in royalties, minimum royalties, or other similar
periodic payments that are necessary to maintain the Company’s Oil and Gas Interests or other rights in and to the Oil and Gas Properties;
(viii) continue Company’s drilling and development activities on the Oil and Gas Properties in accordance with all of the following: (A) the
ordinary course of business consistent with past practices of the Company and its Subsidiaries, (B) the Company’s
37
2005 budget attached hereto as Company Disclosure Schedule 4.1(a)(v), and (C) limited to expenditures in connection with its drilling and completion activities
(both on Company-operated and non-operated properties), as identified in the Company’s proposed 2005 drilling schedule attached hereto as Company
Disclosure Schedule 4.1(a)(xvii);
(ix) maintain the current lease acquisition program underway by the Company in accordance with the stated plans and in accordance with
past practices of the Company and within the Company’s 2005 budget, with monthly reports to Parent related to the acreage targeted and acquired, and
expenditures made in connection therewith; and
(x) notify Parent promptly after the Company or its Affiliates becomes aware of any breach by the Company or its Affiliates of the
covenants contained within this Section 4.1.
4.2 Access and Information. Until the Closing, the Company shall afford to Parent and its representatives (including accountants and counsel) reasonable
access, in each case, only at such locations and in accordance with such procedures (including prior notice requirements, the time and duration of access and the
manner in which access and discussions may be held) as are mutually agreed to between Parent and the Company prior to any such access, to all properties,
books, records, and Tax Returns of the Company and each of its Subsidiaries and all other information with respect to their respective businesses, together with
the opportunity, at the sole cost and expense of Parent, to make copies of such books, records and other documents and to discuss the business of the Company
and each of its Subsidiaries with such directors, officers and counsel for the Company as Parent may reasonably request for the purposes of familiarizing itself
with the Company and each of its Subsidiaries including providing the Company’s consent to the release of any information regarding the Company and its
Subsidiaries held by its independent auditors. Notwithstanding the foregoing provisions of this Section 4.2, the Company shall not be required to, or to cause any
of its Subsidiaries to, grant access or furnish information to Parent or any of Parent’s representatives to the extent that such information is subject to an
attorney/client or attorney work product privilege or that such access or the furnishing of such information is prohibited by an existing contract or agreement.
Notwithstanding the foregoing, Parent shall not have access to personnel records of the Company or any of its Subsidiaries relating to individual performance or
evaluation records, medical histories or other information that in the Company’s good faith opinion is sensitive or the disclosure of which could subject the
Company or any of its Subsidiaries to risk of liability. In addition, Parent shall not contact any personnel of the Company or its Subsidiaries regarding the
transactions contemplated by this Agreement without the express prior written consent of the Chief Financial Officer of the Company. All information provided
pursuant to this Agreement shall remain subject in all respects to the Confidentiality Agreement until the Effective Time.
4.3 Third Party Consents. After the date of this Agreement and prior to the Closing, the Company shall use its commercially reasonable efforts, but
excluding making any payments unless made in the Company’s sole and absolute discretion, to obtain the Consent from any party to a Material Contract that is
set forth on Company Disclosure Schedule 4.3.
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4.4 Notification of Certain Matters; Supplemental Disclosure Letters.
(a) The Company shall give prompt notice to Parent of (i) the occurrence, or failure to occur, of any event of which it has Knowledge that has
caused any representation or warranty of the Company contained in this Agreement to be untrue or inaccurate in any material respect and (ii) the failure of the
Company to comply with or satisfy in any material respect any covenant to be complied with by it hereunder. Except as set forth in Section 4.4(b), no such
notification shall affect the representations or warranties of the parties or the conditions to their respective obligations hereunder.
(b) The Company shall have the right, and the continuing obligation, to disclose additional matters (a “Supplemental Disclosure Item”) in a letter
to Parent (a “Supplemental Disclosure Letter”) from time to time prior to the Closing that come to the Knowledge of the Company after the date hereof that,
had such additional matters been existing, occurring or known on the date hereof, would have been required to be set forth or described in the Company
Disclosure Schedules delivered to Parent on the date of this Agreement in order to make the representations and warranties true and correct as of the date of this
Agreement and as of the Effective Time. The delivery of a Supplemental Disclosure Letter shall not diminish Parent’s right to terminate this Agreement pursuant
to Section 9.1(b)(i).
4.5 Termination of Agreements. Prior to the Effective Time, the Company shall take such action as may be necessary to cause the Stockholders’
Agreement, the Series A Preferred Stock Purchase Agreement, the Master Agreement and the Services Agreement to be terminated in full and of no further force
or effect as of and after the Effective Time.
4.6 Company Transaction Costs. No later than two (2) Business Days prior to the Closing Date, the Company shall provide the amount, in the aggregate,
of all Company Transaction Costs that were previously paid and that are to be paid or caused to be paid by Parent at Closing and shall provide Parent with a
certificate setting forth (a) the identity of each Person that is to be paid at Closing; (b) the amount owed or to be owed to each such Person; and (c) the bank
account and wire transfer information for each such Person.
4.7 Sale of Pipeline Assets. The Company will use commercially reasonable efforts to sell the Pipeline Assets prior to the Closing on terms and conditions
negotiated by the Company; provided that Parent will have the right to approve the buyer in such sale. Upon receipt from a bona fide purchaser of an offer to
purchase the Pipeline Assets, the Company shall promptly provide written notice of the offer and its material terms, including the offeror and the proposed
Pipeline Assets Sale Price, to Parent for such approval. Parent shall provide such approval within five (5) business days. The Pipeline Assets Sale Price, if any,
received by the Company prior to the Closing will be used to repay outstanding Debt of the Company and its Subsidiaries to the extent of such Debt. In the event
that Parent does not approve any bona fide purchaser for which the Company has given notice pursuant to this Section 4.7, the Parent agrees to consummate the
Merger and deem the Pipeline Assets Purchase Price to be the highest dollar amount bid for the Pipeline Assets from a bona fide purchaser.
4.8 Drilling Contracts and Landmen. Prior to the Closing, the Company will use commercially reasonable best efforts to (a) enter into agreements to
commit at least ten (10)
39
drilling rigs to drilling contracts for a term through March 30, 2006; and (b) extend the existing contracts and agreements with landmen providing services in the
Barnett Shale for a term of twelve (12) months after Closing for the benefit of Parent as successor to the interests, in each case on terms and conditions approved
by Parent in writing or electronically, such approval not to be unreasonably withheld or delayed.
4.9 Loan Agreements. Prior to the Closing, the Company shall use all commercially reasonable best efforts to separate between the Company and Antero
II the liabilities and obligations allocable to each, respectively, under that certain Credit Agreement dated May 6, 2004 by and among the Company, Antero II
and the Lenders named therein and that certain Senior Term Agreement dated July 7, 2004 by and among the Company, Antero II and the Lenders named therein
such that the Company shall not be held liable for any liabilities or obligations allocable to Antero II thereunder and Antero II shall not be held liable for any
liabilities or obligations of the Company or Surviving Corporation thereunder.
4.10 Repurchase of Unvested Shares. Prior to the Closing the Company will exercise its rights to repurchase any shares of outstanding Common Stock
that are not Vested Common Shares immediately prior to the Effective Time by paying to the holders thereof an amount equal to the par value of those shares.
ARTICLE 5
COVENANTS OF PARENT AND MERGER SUBSIDIARY
5.1 Notification of Certain Matters. Parent and Merger Subsidiary shall give prompt written notice to the Company of (a) the occurrence, or failure to
occur, of any event of which either of them has Knowledge that has caused any representation or warranty of Parent or Merger Subsidiary contained in this
Agreement to be untrue or inaccurate in any material respect and (b) the failure of Parent or Merger Subsidiary to comply with or satisfy in any material respect
any covenant to be complied with by it hereunder. No such notification shall affect the representations or warranties of the parties or the conditions to their
respective obligations hereunder. If Parent, Merger Subsidiary or any of their Affiliates obtains Knowledge of a breach by the Company of a representation,
warranty, covenant or agreement made by the Company contained in this Agreement, Parent shall promptly notify the Company of such breach; provided that
such notification shall not result in the waiver by Parent or Merger Subsidiary of any of their respective rights or remedies under this Agreement.
5.2 Access to Information. From and after the Effective Time, Parent shall (and shall cause the Surviving Corporation and each of its Subsidiaries and
other Affiliates to), during normal business hours and upon reasonable notice, make available and provide each Securityholder and their respective
representatives (including, without limitation, counsel and independent auditors) with access to the facilities and properties of the Surviving Corporation and
each of its Subsidiaries and to all information, files, documents and records (written and computer) relating to the Surviving Corporation and its Subsidiaries or
any of their businesses or operations for any and all periods prior to and including the Closing Date that they may require with respect to any reasonable business
purpose (including, without limitation, any Tax matter) or in connection with any claim, dispute, action, cause of action, investigation or proceeding of any kind
by or against any Person, and shall (and shall cause the Surviving Corporation and each
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of its Subsidiaries and other Affiliates) to cooperate fully with such Securityholders and their respective representatives (including counsel and independent
auditors) in connection with the foregoing, at the sole cost and expense of Parent, the Surviving Corporation and its Subsidiaries and other Affiliates, as
applicable, including, without limitation, by making tax, accounting and financial personnel and other appropriate employees and officers of the Surviving
Corporation and each of its Subsidiaries available to such Securityholders and their respective representatives (including counsel and independent auditors), with
regard to any reasonable business purpose. Notwithstanding the foregoing, the Securityholders shall not have access to personnel records of the Surviving
Corporation or any of its Subsidiaries relating to individual performance or evaluation records, medical histories or other information that in Parent’s good faith
opinion is sensitive or the disclosure of which could subject the Surviving Corporation or any of its Subsidiaries to risk of liability; provided that the
Securityholders shall not be prohibited from accessing such information pursuant to a valid court order.
5.3 Indemnification of Officers, Directors, Employees and Agents.
(a) From and after the Effective Time, the Surviving Corporation and any successor entities which own and operate the business and properties
owned by the Company and its Subsidiaries (collectively for the purposes of the indemnification provided by this Section 5.3 (the “Surviving Corporation”)
shall, jointly and severally, indemnify, defend and hold harmless each Person who is now, or has been at any time prior to the date hereof or who becomes prior
to the Effective Time, a director or officer of the Company or any of its Subsidiaries (the “D&O Indemnified Persons”) against all losses, claims, damages,
costs, expenses (including attorneys’ and other professionals’ fee and expenses), liabilities or judgments or amounts that are paid in settlement with the approval
of the indemnifying party (which approval shall not be unreasonably withheld) of or in connection with any threatened or actual claim, action, suit, proceeding or
investigation based in whole or in part on or arising in whole or in part out of the fact that such Person is or was a director or officer of the Company or any of its
Subsidiaries or is or was serving at the request of the Company or any of its Subsidiaries as a director, officer employee or agent of another corporation,
partnership, limited liability company, joint venture, employee benefit plan, trust or other enterprise or by reason of anything done or not done by such Person in
any such capacity, arising out of or pertaining to acts or omissions in their capacities as such, and whether asserted or claimed prior to, at or after the Effective
Time (“D&O Indemnified Liabilities”), including all D&O Indemnified Liabilities based in whole or in part on, or arising in whole or in part out of, or
pertaining to the Transaction Documents or the transactions contemplated hereby and thereby, in each case to the fullest extent a corporation is permitted under
the DGCL to indemnify its own directors or officers (and Parent and the Surviving Corporation shall, jointly and severally, pay expenses in advance of the final
disposition of any such claim, action, suit, proceeding or investigation to each D&O Indemnified Person to the fullest extent a corporation is permitted under the
DGCL to advance expenses to its directors and officers in connection with claims, actions and suits involving such Persons) only upon delivery to the Company
or Surviving Corporation, as the case may be, of an undertaking, by or on behalf of such D&O Indemnified Person, to repay all amounts so advanced if it shall
ultimately be determined that such indemnified person is not entitled to be indemnified under this Section 5.3(a) or otherwise. In determining whether a D&O
Indemnified Person is entitled to indemnification under this Section 5.3, if requested by such D&O Indemnified Person, such determination shall be made by
special, independent
41
counsel selected by the Surviving Corporation and approved by the D&O Indemnified Person (which approval shall not be unreasonably withheld) and who has
not otherwise performed services for the Surviving Corporation or its Affiliates within the last three (3) years (other than in connection with such matters).
Without limiting the foregoing, in the event any such claim, action, suit, proceeding or investigation is brought against any D&O Indemnified Persons (whether
arising before or after the Effective Time), (i) the D&O Indemnified Persons may retain the Company’s regularly engaged independent legal counsel or other
counsel satisfactory to them and reasonably satisfactory to the Company (or satisfactory to them and reasonably satisfactory to Parent and the Surviving
Corporation after the Effective Time), and Parent and the Surviving Corporation shall pay all reasonable fees and expenses of such counsel for the D&O
Indemnified Persons as promptly as statements therefor are received and (ii) Parent shall cause the Surviving Corporation to use its commercially reasonable best
efforts to assist in the vigorous defense of any such matter, provided that the Surviving Corporation shall not be liable for any settlement effected without its prior
written consent (which consent shall not be unreasonably withheld), and provided further that neither Parent nor the Surviving Corporation shall be obligated
pursuant to this Section 5.3 to pay the fees and disbursements of more than one counsel for all Indemnified Parties in any single claim, action, suit, proceeding or
investigation, unless there is or may be a conflict of interests between two or more of such Indemnified Parties, in which case there may be separate counsel for
each similarly situated group. Any D&O Indemnified Person wishing to claim indemnification under this Section 5.3, upon learning of any such claim, action,
suit, proceeding or investigation, shall notify the Surviving Corporation (but the failure so to notify shall not relieve a party from any liability that it may have
under this Section 5.3 except to the extent such failure materially prejudices such party’s position with respect to such claims) and shall deliver to Parent and the
Surviving Corporation the undertaking contemplated by Section 145(e) of the DGCL, but without any requirement for the posting of a bond or any other terms or
conditions other than those expressly set forth herein.
(b) Parent and the Surviving Corporation shall not amend, repeal or otherwise modify the certificate of incorporation and bylaws of the Surviving
Corporation or manage the Surviving Corporation or any of its Subsidiaries in any manner that would affect adversely the rights thereunder of individuals who at
and at any time prior to the Effective Time were directors, officers, employees or agents of the Company or any of its Subsidiaries. Parent shall, and shall cause
the Surviving Corporation to, honor any indemnification agreements between the Company and any of its directors, officers or employees. To the extent not
already in existence, D&O indemnification agreements consistent with the terms of the certificate of incorporation and bylaws will be executed by Company
directors and management prior to consummation of the Merger.
(c) Parent and the Surviving Corporation shall indemnify any D&O Indemnified Person against all reasonable costs and expenses (including
attorneys’ fees and expenses), such amounts to be payable in advance upon request as provided in Section 5.3(a), relating to the enforcement of such D&O
Indemnified Person’s rights under this Section 5.3 or under any charter, bylaw or contract only upon delivery to the Company or Surviving Corporation, as the
case may be, of an undertaking, by or on behalf of such D&O Indemnified Person, to repay all amounts so advanced if it shall ultimately be determined that such
indemnified person is not entitled to be indemnified under this Section 5.3(a) or otherwise. Any amounts due pursuant to this Section 5.3 shall be payable upon
request by the
42
D&O Indemnified Person and shall bear interest from the date such were originally due and payable at a rate equal to the prime rate of interest as announced by
JPMorgan Chase Bank, N.A. as in effect on the date of such initial request plus three percent (3%).
(d) Prior to Closing, the Company will purchase a six (6) year directors’ and officers’ liability insurance and fiduciary liability insurance covering
the D&O Indemnified Persons who are currently covered by the Company’s existing directors’ and officers’ liability insurance or fiduciary liability insurance
policies and the Parent will take no action which would interfere with the benefit of such policy during such term.
5.4 Name Change. Parent agrees that (a) within ninety (90) days after the Effective Time it will cause the Surviving Corporation and each of its
Subsidiaries to take all necessary steps to change their names so as not to include, and cease doing business under any name that includes, the word “Antero,” or
any derivative, (b) at any time after the Effective Time, Antero II and its Affiliates may engage in business in the oil and gas industry or any other activity using a
name that includes the word “Antero,” and (iii) after the Effective Time Parent will and will cause the Surviving Corporation and each of its Subsidiaries to take
all necessary steps to consent to the formation by Antero II or its Affiliates of any entity under a name, and the use of a name by that entity, that includes the
word “Antero” in any jurisdiction, to the extent contemplated by clause (b).
5.5 Pipeline Assets. Parent agrees that if it fails to approve any bid on the Pipeline Assets from a bona fide purchaser for which the Company has provided
notice pursuant to Section 4.7, the Pipeline Assets Sale Price shall be deemed to equal the highest bid on the Pipeline Assets from a bona fide purchaser for
which the Company has provided notice pursuant to Section 4.7. Further, in this event, the Company shall amend this Agreement to include such additional
representations and warranties as the Company is or was prepared to make to such bona fide purchaser with respect to the Pipeline Assets.
5.6 Registration of Parent Common Stock. Parent agrees to prepare and file with the SEC a Registration Statement on Form S-3 (the “Registration
Statement”) for the benefit of the Securityholders covering all of the Parent Common Stock to be issued as Parent Stock Merger Consideration and the Parent
Common Stock underlying the Warrants. The Registration Statement shall be filed as soon as reasonably practicable after the date of this Agreement in the form
mutually agreed to by the Company and Parent. Parent also agrees to use its commercially reasonable best efforts to cause the Registration Statement to become
effective as soon as practicable after the Closing.
5.7 Delivery of Allocated Values. Parent hereby agrees to prepare and deliver to the Company the Allocated Values on a written supplement to Company
Disclosure Schedule 3.1(w)(ii) not later than January 14, 2005.
ARTICLE 6
OTHER COVENANTS OF THE PARTIES
6.1 Governmental Consents. Promptly following the execution of this Agreement, the parties shall proceed to prepare and file with the appropriate
Governmental Authorities such
43
Consents that are necessary in order to consummate the transactions contemplated by this Agreement, including pursuant to the HSR Act or any other applicable
Antitrust Law, if applicable, and shall diligently and expeditiously prosecute, and shall cooperate fully with each other in the prosecution of, such matters.
6.2 Investigation and Agreement by Parent and Merger Subsidiary; No Other Representations or Warranties.
(a) Each of Parent and Merger Subsidiary acknowledges and agrees that it has made its own inquiry and investigation into, and, based thereon, has
formed an independent judgment concerning, the Company and its Subsidiaries and their businesses and operations, and Parent and Merger Subsidiary have been
furnished with or given full access to such information about the Company and its Subsidiaries and their businesses and operations as they requested. In
connection with Parent’s and Merger Subsidiary’s investigation of the Company and its Subsidiaries and their businesses and operations, Parent, Merger
Subsidiary and their respective representatives have received from the Company or its representatives certain projections and other forecasts for the Company
and its Subsidiaries and certain estimates, plans and budget information. Parent and Merger Subsidiary acknowledge and agree that (i) there are uncertainties
inherent in attempting to make such projections, forecasts, estimates, plans and budgets; (ii) Parent and Merger Subsidiary are familiar with such uncertainties;
and (iii) Parent and Merger Subsidiary are taking full responsibility for making their own evaluations of the adequacy and accuracy of all estimates, projections,
forecasts, plans and budgets so furnished to them or their representatives.
(b) Each of Parent and Merger Subsidiary agrees that, except for the representations and warranties made by the Company that are expressly set
forth in Section 3.1 of this Agreement, none of the Company, any Subsidiary of the Company, any Securityholder, or any of their respective Affiliates or
representatives has made and shall not be deemed to have made to any of Parent, Merger Subsidiary or their respective Affiliates or representatives any
representation or warranty of any kind. Without limiting the generality of the foregoing, and notwithstanding any otherwise express representations and
warranties made by the Company and set forth in Section 3.1, each of Parent and Merger Subsidiary agrees that none of the Company, any Subsidiary of the
Company, any Securityholder, or any of their respective Affiliates or representatives makes or has made any representation or warranty to Parent, Merger
Subsidiary or to any of their respective representatives or Affiliates with respect to:
(i) any projections, forecasts, estimates, plans or budgets of future revenue, expenses or expenditures, future results of operations (or any
component thereof), future cash flows (or any component thereof) or future financial condition (or any component thereof) of the Company or any of its
Subsidiaries or the future business, operations or affairs of the Company or any of its Subsidiaries heretofore or hereafter delivered to or made available to
Parent, Merger Subsidiary or their respective representatives or Affiliates; or
(ii) any other information, statements or documents heretofore or hereafter delivered to or made available to Parent, Merger Subsidiary or
their respective representatives or Affiliates, including the information contained in the on-line data room, with respect to the Company or any of its Subsidiaries
or the business, operations or affairs of the
44
Company or any of its Subsidiaries, except as expressly covered by representations and warranties made by the Company and set forth in Section 3.1.
(c) The Company acknowledges and agrees that, except for the representations and warranties made by Parent or Merger Subsidiary as expressly set
forth in Section 3.2, none of Parent, Merger Subsidiary or any of their respective Affiliates or representatives makes or has made to any of the Company, any
Subsidiary of the Company, any Securityholder or any of their respective Affiliates or representatives any representation or warranty of any kind.
6.3 Confidentiality of Agreement. The parties agree to keep the terms of this Agreement confidential, subject to such announcements regarding its
execution as are mutually applied by the parties. Further, Parent agrees that at the time it files this Agreement as an exhibit to its periodic reports with the SEC,
Parent will prepare a confidential treatment request for submission to the SEC requesting that those items mutually identified by the Company and Parent be
afforded confidential treatment in accordance with the regulations of the SEC. Parent agrees to use its commercially reasonable best efforts to obtain approval of
such request, subject to the final approval authority of the SEC.
6.4 Tax Treatment. Between the date of this Agreement and the Effective Time, each of the Company and Parent agrees (a) not to take any actions that
would adversely affect the ability of the Company and its Securityholders to characterize the Merger as a tax-free reorganization under Section 368(a) of the
Code, and (b) to take such action as may be reasonably required, if such action may be reasonably taken to reverse the impact of any past actions that would
adversely impact the ability for the Merger to be characterized as a tax-free reorganization under Section 368(a) of the Code.
ARTICLE 7
CONDITIONS PRECEDENT
7.1 Conditions to Each Party’s Obligation. The respective obligations of the Company, Parent and Merger Subsidiary to effect the transactions
contemplated by this Agreement are subject to the satisfaction on or prior to the Closing Date of the following conditions:
(a) Consents and Approvals. All Consents of or imposed by any Governmental Authority necessary (excluding Consents relating to use, occupancy,
Taxes, environmental and similar matters) for the consummation of the transactions contemplated by this Agreement and the other Transaction Documents shall
have been obtained, occurred or have been made, including those arising under all applicable Antitrust Laws and the applicable waiting period under the HSR
Act shall have expired or terminated.
(b) No Injunctions or Restraints. No temporary restraining order, preliminary or permanent injunction or other order issued by any court of
competent jurisdiction or other legal restraint or prohibition preventing the consummation of the transactions contemplated by this Agreement or any other
Transaction Document shall be in effect.
45
(c) No Action. No action shall have been taken nor any statute, rule or regulation shall have been enacted by any Governmental Authority that
makes the consummation of the transactions contemplated by this Agreement or any other Transaction Document illegal.
7.2 Conditions to Obligation of Parent and Merger Subsidiary. The obligation of Parent and Merger Subsidiary to effect the transactions contemplated
by this Agreement is subject to the satisfaction of the following conditions unless waived, in whole or in part, by Parent:
(a) Representations and Warranties. Each of the representations and warranties of the Company set forth in Section 3.1 shall be true and correct in
all material respects as of the date of this Agreement and (except to the extent such representations and warranties speak expressly as of an earlier date) as of the
Effective Time as though made on and as of the Effective Time; provided, however, that this condition shall be deemed to have been satisfied unless the
individual or aggregate impact of all inaccuracies of such representations and warranties would be reasonably likely to have a Material Adverse Effect. Parent
shall have received a certificate signed on behalf of the Company by the Chief Executive Officer or the Chief Financial Officer of the Company to such effect;
(b) Performance of Obligations of the Company. The Company shall have performed in all material respects all obligations required to be performed
by it under this Agreement at or prior to the Effective Time, and Parent shall have received a certificate signed on behalf of the Company by the Chief Executive
Officer or the Chief Financial Officer of the Company to such effect;
(c) Transition Services Agreement. A Transition Services Agreement between Parent and Antero II for the provision of accounting and general and
administrative services and such other operational support as is appropriate to continue the development of the Company’s Oil and Gas Interests and to
consummate the transactions contemplated hereby. The Transition Services Agreement shall contain mutually acceptable terms and conditions which are
consistent with the terms and conditions set forth in the Letter of Intent among Parent, the Company and Antero II dated January 4, 2005 (the “LOI”) and shall
have been executed by Antero II;
(d) Closing Deliveries. All documents, instruments, certificates or other items required to be delivered at the Closing by the Company pursuant to
Section 8.2(b) of this Agreement shall have been delivered; and
(e) Non-Competition Agreements. Each of the Persons listed on Exhibit D shall have executed and delivered to Parent a Non-Competition
Agreement in a form consistent with paragraph 9 of the LOI for the number of years set forth next to such Person’s name on Exhibit D.
(f) Stockholder Vote. The Agreement shall have been adopted by the requisite affirmative vote of the Company’s stockholders in accordance with
the DGCL and the Company’s Certificate of Incorporation.
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(g) Receivables. All receivables from the Company’s Affiliates shall have been fully collected prior to Closing.
7.3 Conditions to Obligations of the Company. The obligation of the Company to effect the transactions contemplated by this Agreement is subject to
the satisfaction of the following conditions unless waived, in whole or in part, by the Company:
(a) Representations and Warranties. Each of the representations and warranties of Parent and Merger Subsidiary set forth in this Agreement shall be
true and correct in all material respects as of the date of this Agreement and (except to the extent such representations and warranties expressly speak as of an
earlier date) as of the Effective Time as though made on and as of the Effective Time. The Company shall have received a certificate signed on behalf of Parent
by the Chief Executive Officer, the Chief Financial Officer or Executive Vice President of Parent to such effect.
(b) Performance of Obligations of Parent and Merger Subsidiary. Each of Parent and Merger Subsidiary shall have performed in all material respects
all obligations required to be performed respectively by them under this Agreement at or prior to the Effective Time, and the Company shall have received a
certificate signed on behalf of Parent by the Chief Executive Officer, the Chief Financial Officer or Executive Vice President of Parent to such effect.
(c) Sale of Pipeline Assets. The Pipeline Assets shall have been sold by the Company for a Pipeline Assets Sale Price of not less than $140,000,000.
(d) Listing of Parent Common Stock on New York Stock Exchange. The Parent Common Stock to be issued at the Closing as the Parent Stock
Merger Consideration shall have been approved for listing, upon official notice of issuance, on the New York Stock Exchange.
(e) Registration Statement. Parent shall have filed the Registration Statement with the SEC.
(f) Transition Services Agreement. A Transition Services Agreement between Parent and Antero II for the provision of accounting and general and
administrative services and such other operational support as is appropriate to continue the development of the Company’s Oil and Gas Interests and to
consummate the transactions contemplated hereby. The Transition Services Agreement shall contain mutually acceptable terms and conditions which are
consistent with the terms and conditions set forth in the LOI and shall have been executed by Parent.
(g) Registration Rights Agreement. A Registration Rights Agreement, substantially in the form attached as Exhibit E hereto, between Parent and the
Securityholders providing for the establishment of a shelf registration statement for the benefit of the Securityholders shall have been executed by Parent.
(h) Debt to Antero II. All of the Company’s Debt owed to Antero II shall have been paid under the terms of this Agreement.
47
(i) Closing Deliveries. All documents, instruments, certificates or other items required to be delivered at Closing by Parent and Merger Subsidiary
pursuant to Section 8.2(a) this Agreement shall have been delivered.
ARTICLE 8
CLOSING
8.1 Closing. Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to ARTICLE
9, and subject to the satisfaction or waiver of the conditions set forth in ARTICLE 7, the closing of the Merger (the “Closing”) shall take place at 9:00 a.m., not
later than the fifth Business Day after termination or expiration of the applicable waiting period (and any extension thereof) under the HSR Act, at the offices of
Vinson & Elkins L.L.P., 2300 First City Tower, 1001 Fannin, Houston, Texas, unless another date, time or place is mutually agreed to in writing by Parent and
the Company. If any of the conditions set forth in ARTICLE 7 are not satisfied or waived at the time the Closing is to occur pursuant to this Section 8.1, Parent
or the Company may, by notice to the other, adjourn the Closing to a date specified in that notice (but not later than the Termination Date). (The date and time on
which the Closing, as it may have been adjourned, occurs is the “Closing Date.”)
8.2 Actions to Occur at Closing.
(a) At the Closing, Parent and Merger Subsidiary shall deliver or pay, as the case may be, the following in accordance with the applicable provisions
of this Agreement:
(i) Closing Payments. To the Securityholders and the Exchange Agent and the other payees identified in Section 2.11, by wire transfers of
immediately available funds, the payments required to be made by Parent under Sections 2.11 and 2.12;
(ii) Certificates. The certificates described in Section 7.3(a) and (b);
(iii) Assumption of Debt. Evidence of the assumption by Parent of the Debt, if any, of the Company and its Subsidiaries; and
(iv) Assumption of Letters of Credit. Evidence of the assumption by Parent of the Letters of Credit.
(b) At the Closing, the Company shall deliver to Parent the following:
(i) Certificate. The certificates described in Section 7.2(a) and (b);
(ii) Resignations. The resignations of the officers and directors of the Company and each of its Subsidiaries;
(iii) Merger Consideration Certificate. The Merger Consideration Certificate;
48
(iv) Releases and Waivers. Releases and waivers executed by each of the employees of the Company who have been employed by the
Company on or after December 31, 2004;
(v) Termination of Agreements. Evidence of the termination of the Stockholders’ Agreement, the Series A Preferred Stock Purchase
Agreement, the Master Agreement and the Services Agreement; and
(vi) Acknowledgements. Written acknowledgments pursuant to which the Company’s outside legal counsel and any financial advisor,
accountant or other Person who performed services for or on behalf of the Company acknowledges the total amount of Company Transaction Costs previously
paid or remaining payable to such Person.
(c) Pursuant to Section 2.2, the Company and Parent shall cause the Certificate of Merger to be properly executed and filed with the Secretary of
State of the State of Delaware.
8.3 Waiver of Breaches. If the Closing occurs, Parent, Merger Subsidiary and the Surviving Corporation shall be deemed to have waived all breaches of
representations, warranties and covenants of the Company of which Parent or Merger Subsidiary has Knowledge or which are set forth in a Supplemental
Disclosure Letter (“Waived Breaches”), and the Securityholders shall have no liability with respect thereto after the Closing.
ARTICLE 9
TERMINATION, AMENDMENT AND WAIVER
9.1 Termination. This Agreement may be terminated and the Merger may be abandoned at any time prior to the Effective Time:
(a) by mutual written consent of Parent and the Company;
(b) by either Parent or the Company:
(i) if there shall have been any breach by the other party (which, in the case of the right of termination by the Company, shall also include
any breach by Merger Subsidiary) of any representation, warranty, covenant or agreement set forth in this Agreement, which breach (A) would give rise to the
failure of a condition to the Closing hereunder and (B) either (1) cannot be cured or (2) if it can be cured, has not been cured prior to the first to occur of (x) 5:00
p.m. on the date that is twenty (20) days following receipt by the breaching party of written notice of such breach or (y) 5:00 p.m. on the date immediately
preceding the Termination Date (the “Cure Period”); and, without limiting the generality of the foregoing, there shall be no Cure Period for Parent’s failure to
obtain all funds on or prior to the Closing Date necessary to consummate the Merger and the other transactions contemplated by this Agreement and the other
Transaction Documents in accordance with the terms and conditions hereof and thereof (which failure shall constitute a material breach of this Agreement);
(ii) if a court of competent jurisdiction or other Governmental Authority shall have issued an order, decree or ruling or taken any other
action (which order,
49
decree or ruling Parent and the Company shall use their reasonable best efforts to lift), in each case permanently restraining, enjoining or otherwise prohibiting
the transactions contemplated by this Agreement and the other Transaction Documents and such order, decree, ruling or other action shall have become final and
nonappealable; provided, however, that the right to terminate this Agreement under this Section 9.1(b)(ii) shall not be available to any party who did not use
reasonable best efforts to lift any such order, decree, ruling or other action or whose failure to comply with Section 6.1 has been the primary cause of the
condition set forth in this Section 9.1(b)(ii) not being satisfied; or
(iii) if the Closing shall not have occurred on or before 5:00 p.m. on May 1, 2005 (the “Termination Date”); provided, however, that the
right to terminate this Agreement under this clause (iii) shall not be available to any party whose breach of this Agreement has been the cause of, or resulted in,
the failure of the Closing to occur on or before such date.
(iv) by Parent, if this Agreement shall fail to be adopted by the requisite vote of the Company’s stockholders in accordance with the DGCL
or the Company’s Certificate of Incorporation.
9.2 Effect of Termination.
(a) In the event of the termination of this Agreement by either the Company or Parent as provided in Section 9.1, this Agreement shall forthwith
become void and there shall be no liability or obligation hereunder on the part of Parent, Merger Subsidiary or the Company or their respective Affiliates,
directors, officers, employees or stockholders, except that (i) ARTICLE 1, this ARTICLE 9 and ARTICLE 10 shall survive such termination and (ii) subject to
Section 9.2(b), no such termination shall relieve any party from liability for breach of any term or provision hereof.
(b) If Parent terminates this Agreement pursuant to Section 9.1(b)(i) due to a breach by the Company of one or more representations or warranties of
the Company, the Company and its Affiliates, directors, officers, employees or stockholders shall have no liability or obligation hereunder to the extent that any
such breach is based on one or more Supplemental Disclosure Items that (i) did not arise from facts or circumstances of which the Company had Knowledge as
of the date of this Agreement, and (ii) did not arise from the Company’s breach of a covenant contained in this Agreement or in any of the other Transaction
Documents to which it is a party.
9.3 Return of Information. Within ten (10) Business Days following termination of this Agreement in accordance with Section 9.1, Parent shall, and shall
cause Merger Subsidiary and their respective Affiliates and representatives to, return to the Company, or destroy, all Confidential Information (as defined in the
Confidentiality Agreement) furnished or made available to Parent and Merger Subsidiary and their respective Affiliates and representatives by or on behalf of the
Company, and all analyses, compilations, data, studies, notes, interpretations, memoranda or other documents prepared by Parent or Merger Subsidiary or any of
their
respective Affiliates or representatives (including electronic copies thereof) that refer to, relate to, discuss or contain, or are based on, in whole or in part, any
such Confidential Information.
50
Parent shall deliver a certificate signed by its Chief Executive Officer, which certificate shall provide evidence reasonably substantiating the return or destruction
of the Confidential Information as required under this Section 9.3.
ARTICLE 10
GENERAL PROVISIONS
10.1 Survival of Representations and Warranties. The representations and warranties contained herein and in any certificate or other writing delivered
pursuant hereto shall not survive the Effective Time. This Section 10.1 shall not limit any covenant or agreement of the parties to this Agreement which, by its
terms, contemplates performance after the Effective Time.
10.2 Reasonable Efforts; Further Assurances.
(a) Prior to the Closing, upon the terms and subject to the conditions set forth in this Agreement, the Company, Parent and Merger Subsidiary agree
to use commercially reasonable efforts to take, or cause to be taken, all actions, and to do, or cause to be done, all things necessary, proper or advisable (subject
to any Applicable Laws) to consummate the Merger and make effective the Merger and the other transactions contemplated by this Agreement and the other
Transaction Documents as promptly as practicable, including (i) the obtaining of all Consents of, and the making of all registrations, declarations and filings
with, Governmental Authorities and (ii) the execution and delivery of any additional instruments necessary to consummate the transactions contemplated by, and
to fully carry out the purposes of this Agreement and the other Transaction Documents. In addition, no party hereto shall take any action after the date of this
Agreement to materially delay the obtaining of, or result in not obtaining, any Consent from any Governmental Authority necessary to be obtained prior to
Closing.
(b) At and after the Effective Time, the officers and directors of the Surviving Corporation shall be authorized to execute and deliver, in the name
and on behalf of the Company or Merger Subsidiary, any deeds, bills of sale, assignment or assurances and to take and do, in the name and on behalf of the
Company or Merger Subsidiary, any other actions and things to vest, perfect or confirm of record or otherwise in the Surviving Corporation any and all right, title
and interest in, to and under any of the rights, properties or assets of the Company acquired or to be acquired by the Surviving Corporation as a result of, or in
connection with, the Merger.
10.3 Amendment and Modification. This Agreement may be amended by the parties hereto, by action taken or authorized by their respective Boards of
Directors, provided that no amendment shall be made which by Applicable Law requires further approval or adoption by a parties’ stockholders without such
further approval or adoption.
10.4 Waiver of Compliance. Except as otherwise provided in Section 8.3, any failure of Parent or Merger Subsidiary on the one hand, or the Company,
on the other hand, to comply with any obligation, covenant, agreement or condition contained herein may be waived only if set forth in an instrument in writing
signed by the party or parties to be bound by such waiver
51
(including if such waiver is after the Closing the third-party beneficiaries set forth in Section 10.7), but such waiver or failure to insist upon strict compliance
with such obligation, covenant, agreement or condition shall not operate as a waiver of, or estoppel with respect to, any other failure.
10.5 Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any Applicable Law or public
policy, all other terms and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the
transactions contemplated herein is not affected in any manner materially adverse to any party. Upon such determination that any term or other provision is
invalid, illegal or incapable of being enforced, the Governmental Authority making such determination is authorized and instructed to modify this Agreement so
as to effect the original intent of the parties as closely as possible in order that the transactions contemplated herein are consummated as originally contemplated
to the fullest extent possible.
10.6 Expenses and Obligations. Except as otherwise expressly provided in this Agreement, all costs and expenses incurred by the parties hereto in
connection with the transactions contemplated by this Agreement shall be borne solely and entirely by the party that has incurred such expenses.
10.7 Parties in Interest. This Agreement shall be binding upon and inure solely to the benefit of each party hereto and its successors and permitted
assigns. Nothing in this Agreement is intended to confer upon any other Person any rights or remedies of any nature whatsoever under or by reason of this
Agreement except as expressly set forth herein. Notwithstanding the foregoing, from and after the Closing, as may be applicable, each of Sections 3.2(e), 5.3 and
this ARTICLE 10 (to the extent necessary to enforce surviving provisions of the Agreement) are made for the benefit of (a) the Securityholders and (b) any of the
Company’s and/or its Subsidiaries’ (i) directors and officers, (ii) former directors and officers, and (iii) employees. From and after the Closing, all of the Persons
identified in clauses (a) and (b) in the immediately preceding sentence shall be entitled to enforce such provisions and to avail themselves of the benefits of any
remedy for any breach of such provisions, all to the same extent as if such Persons were parties to this Agreement.
10.8 Notices. All notices and other communications hereunder shall be in writing and shall be deemed given if delivered by hand, mailed by registered or
certified mail (return receipt requested), sent by facsimile or sent by Federal Express or other recognized overnight courier to the parties at the following
addresses (or at such other address for a party as shall be specified by like notice):
(a)
If to Parent or Merger Subsidiary, to:
XTO Energy Inc.
810 Houston Street
Fort Worth, Texas 76102
Attention: Executive Vice President - Administration
Facsimile: (817) 870-0379
52
with copies to:
XTO Energy Inc.
810 Houston Street
Attention: Vice President & General Counsel – Land & Acquisitions
Facsimile: (817) 885-2278
(b)
If to the Company, to:
Antero Resources Corporation
1625 17th Street, Suite 300
Denver, Colorado 80202
Attention: Glen C. Warren, Jr.
Facsimile: (303) 357-7299
with a copy to:
Vinson & Elkins L.L.P.
2300 First City Tower
1001 Fannin
Houston, Texas 77002
Attention: David P. Oelman
Facsimile: (713) 615-5861
Any of the above addresses may be changed at any time by notice given as provided above; provided, however, that any such notice of change of
address shall be effective only upon receipt. All notices, requests or instructions given in accordance herewith shall be deemed received on the date of delivery, if
hand delivered, on the date of receipt, if transmitted by facsimile, three (3) Business Days after the date of mailing, if mailed by registered or certified mail,
return receipt requested and one (1) Business Day after the date of sending, if sent by Federal Express or other recognized overnight courier.
10.9 Counterparts. This Agreement may be executed and delivered (including by facsimile transmission) in one or more counterparts, all of which shall
be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the parties and delivered to
the other parties, it being understood that all parties need not sign the same counterpart.
10.10 Time. Time is of the essence in each and every provision of this Agreement.
10.11 Entire Agreement. This Agreement (which term shall be deemed to include the exhibits and schedules hereto and the other certificates, documents
and instruments delivered hereunder), the other Transaction Documents and the Confidentiality Agreement constitute the entire agreement of the parties hereto
and supersede all prior agreements, letters of intent and understandings, both written and oral, among the parties with respect to the subject matter of this
Agreement, the other Transaction Documents and the Confidentiality Agreement. There are no
53
representations or warranties, agreements or covenants other than those expressly set forth in this Agreement, the other Transaction Documents and the
Confidentiality Agreement.
10.12 Public Announcements. On or prior to the Closing, no party hereto shall issue any press release or make any public statement with respect to this
Agreement or the transactions contemplated hereby without the prior written consent of Parent and the Company, except that any party may make any disclosure
required by Applicable Law (including federal securities laws) if it determines in good faith that it is required to do so and, with respect to each such disclosure,
provides the other with prior notice and a reasonable opportunity to review the disclosure.
10.13 Attorneys’ Fees. In any action or proceeding instituted by a party arising in whole or in part under, related to, based on, or in connection with, this
Agreement or the subject matter hereof, the prevailing party shall be entitled to receive from the losing party reasonable attorney’s fees, costs and expenses
incurred in connection therewith, including any appeals therefrom.
10.14 Assignment. Neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned by any of the parties hereto, whether
by operation of law or otherwise. Any assignment in violation of the foregoing shall be null and void.
10.15 Rules of Construction.
(a) Each of the parties acknowledges that it has been represented by independent counsel of its choice throughout all negotiations that have preceded
the execution of this Agreement and that it has executed the same with consent and upon the advice of said independent counsel. Each party and its counsel
cooperated in the drafting and preparation of this Agreement and the documents referred to herein, and any and all drafts relating thereto shall be deemed the
work product of the parties and may not be construed against any party by reason of its preparation. Accordingly, any rule of law or any legal decision that would
require interpretation of any ambiguities in this Agreement against any party that draft it is of no application and is hereby expressly waived.
(b) The inclusion of any information in the Disclosure Schedules shall not be deemed an admission or acknowledgment, in and of itself and solely
by virtue of the inclusion of such information in the Disclosure Schedules, that such information is required to be listed in the Disclosure Schedules or that such
items are material to the Company, Parent or Merger Subsidiary, as the case may be. The headings, if any, of the individual sections of each of the Disclosure
Schedules are inserted for convenience only and shall not be deemed to constitute a part thereof or a part of this Agreement.
(c) The specification of any dollar amount in the representations and warranties or otherwise in this Agreement or in the Disclosure Schedules is not
intended and shall not be deemed to be an admission or acknowledgment of the materiality of such amounts or items, nor shall the same be used in any dispute or
controversy between the parties to determine whether any obligation, item or matter (whether or not described herein or included in any schedule) is or is not
material for purposes of this Agreement.
54
(d) All references in this Agreement to Exhibits, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding
Exhibits, Schedules, Articles, Sections, subsections and other subdivisions of this Agreement unless expressly provided otherwise. Titles appearing at the
beginning of any Articles, Sections, subsections or other subdivisions of this Agreement are for convenience only, do not constitute any part of such Articles,
Sections, subsections or other subdivisions, and shall be disregarded in construing the language contained therein. The words “this Agreement,” “herein,”
“hereby,” “hereunder” and “hereof” and words of similar import, refer to this Agreement as a whole and not to any particular subdivision unless expressly so
limited. The words “this Section,” “this subsection” and words of similar import, refer only to the Sections or subsections hereof in which such words occur. The
word “including” (in its various forms) means “including, without limitation.” Pronouns in masculine, feminine or neuter genders shall be construed to state and
include any other gender and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa,
unless the context otherwise expressly requires. Unless the context otherwise requires, all defined terms contained herein shall include the singular and plural and
the conjunctive and disjunctive forms of such defined terms. Unless the context otherwise requires, all references to a specific time shall refer to Houston, Texas
time.
(e) Notwithstanding anything contained in this Agreement to the contrary, except as otherwise expressly provided in this Agreement, the parties
hereto covenant and agree that no amount shall be (or is intended to be) included, in whole or in part (either as an increase or a reduction), more than once in the
calculation of (including any component of) Per Share Merger Consideration, Combined Merger Consideration, Option Consideration, Series A Preferential
Merger Consideration or any other calculated amount pursuant to this Agreement if the effect of such additional inclusion (either as an increase or a reduction)
would be to cause such amount to be over- or under-counted for purposes of the transactions contemplated by this Agreement.
10.16 Joint Liability. Each representation, warranty, covenant and agreement made by Parent or Merger Subsidiary in this Agreement shall be deemed a
joint representation, warranty, covenant and agreement made by Parent and Merger Subsidiary jointly and all liability and obligations relating thereto shall be
deemed a joint liability and obligation of Parent and Merger Subsidiary.
10.17 Affiliate Liability. Each of the following is herein referred to as an “Antero Affiliate”: (a) any direct or indirect holder of equity interests or
securities in the Company (whether limited or general partners, members, stockholders or otherwise), (b) any director, officer, employee, representative or agent
of (i) the Company or (ii) any Person who controls the Company. No Antero Affiliate shall have any liability or obligation to Parent or Merger Subsidiary of any
nature whatsoever in connection with or under this Agreement, any of the Transaction Documents or the transactions contemplated herein or therein except to the
extent any such Antero Affiliate is a party to any Transaction Document and then only with respect to the express obligations of such Antero Affiliate under such
Transaction Document (the “Express Affiliate Obligations”), and Parent and Merger Subsidiary hereby waive and release all claims of any such liability and
obligation (such waiver and release to not apply to the Express Affiliate Obligations).
55
10.18 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF TEXAS, WITHOUT GIVING EFFECT TO ANY CONFLICTS OF LAW PROVISIONS.
10.19 Waiver Of Jury Trial. TO THE EXTENT NOT PROHIBITED BY APPLICABLE LAW THAT CANNOT BE WAIVED, EACH PARTY
HEREBY IRREVOCABLY WAIVES AND COVENANTS THAT IT WILL NOT ASSERT (WHETHER AS PLAINTIFF, DEFENDANT OR OTHERWISE)
ANY RIGHT TO TRIAL BY JURY IN ANY FORUM IN RESPECT OF ANY ISSUE, CLAIM, DEMAND, ACTION OR CAUSE OF ACTION ARISING IN
WHOLE OR IN PART UNDER, RELATED TO, BASED ON, OR IN CONNECTION WITH, THIS AGREEMENT OR THE SUBJECT MATTER HEREOF,
WHETHER NOW EXISTING OR HEREAFTER ARISING AND WHETHER SOUNDING IN TORT OR CONTRACT OR OTHERWISE. ANY PARTY
HERETO MAY FILE AN ORIGINAL COUNTERPART OR A COPY OF THIS SECTION 10.19 WITH ANY COURT AS WRITTEN EVIDENCE OF THE
CONSENT OF EACH SUCH PARTY TO THE WAIVER OF ITS RIGHT TO TRIAL BY JURY.
10.20 Consent to Jurisdiction; Venue.
(a) The parties hereto submit to the personal jurisdiction of the courts of the State of Texas and the Federal courts of the United States sitting in
Harris County, and any appellate court from any such state or Federal court, and hereby irrevocably and unconditionally agree that all claims with respect to any
such claim may be heard and determined in such Texas court or, to the extent permitted by law, in such Federal court. The parties hereto agree that a final
judgment in any such claim shall be conclusive and may be enforced in any other jurisdiction by suit on the judgment or in any other manner provided by law.
Nothing in this Agreement shall affect any right that any party may otherwise have to bring any claim relating to this Agreement or any related matter against any
other party or its assets or properties in the courts of any jurisdiction.
(b) Each of the parties hereto irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which
it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or any related matter in any
Texas state or Federal court located in Harris County and the defense of an inconvenient forum to the maintenance of such claim in any such court.
[Signature Page Follows]
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IN WITNESS WHEREOF, the Company, Parent and Merger Subsidiary have caused this Agreement to be signed, all as of the date first written above.
THE COMPANY:
ANTERO RESOURCES CORPORATION
By:
/S/ GLEN C. WARREN. JR.
Name: Glen C. Warren. Jr.
Title: President, Chief Financial Officer and
Secretary
PARENT:
XTO ENERGY INC.
By:
/S/ VAUGHN O. VENNERBERG II
Name: Vaughn O. Vennerberg II
Title: Executive Vice President - Administration
MERGER SUBSIDIARY:
XTO BARNETT INC.
By:
/S/ VAUGHN O. VENNERBERG II
Title: President
SIGNATURE PAGE
TO
AGREEMENT
AND PLAN
OF MERGER
EXHIBIT A
PIPELINE ASSETS - 1
Map depicting pipeline portion of Pipeline Assets (North Fort Worth)
EXHIBIT A
PIPELINE ASSETS - 1 (CONTINUED)
Map depicting pipeline portion of Pipeline Assets (South Fort Worth)
EXHIBIT B
PIPELINE ASSETS - 2
List of tangible personal property with a value in excess of $100,000 associated
with the Pipeline Assets.
In addition to the tangible personal property Antero Resources Pipeline, LP owns the Firm
Transportation Contracts.
All personal property either leased or owned at the following locations:
Main Station
Dido Station
West Lake Station
Midpoint Station
Marine Creek Station
Boswell Station
Railhead Station
Leming Station
Keller Station
Risinger Road Station
Praire Meadows Station
Except at Vinson Ranch, Antero Resources Pipeline, LP owns all meter tubes, Total Flow
equipment, well meters, and radios as well as base stations, towers and antennas and tower
licenses. All of the well gathering equipment (such as well separators, tank batteries, well head
equipment etc.) is owned by Antero Resources I, LP.
The Other Pipeline Assets described above includes, but is not limited to the equipment listed below.
Vendor
Description
Project
Sisco
Redman
Redman
Link Field Services
Redman
Mastec
Redman
Topaz
JD Fields
Bell Supply Company
Bell Supply Company
Pioneer Pipe
TEPSCO
Link Field Services
Pioneer Pipe
Redman
Redman
Travis Perry Company
Hanover
ValveSystems
Davis & Davis
JW Williams
ValveSystems
ATCO Noise
Pioneer
TEPSCO
ValveSystems
ValveSystems
Leed Fabrication
Redman Supply
10” Transitions & 3” Anchor Flange
Standard Fittings, Pipe, 3” Valves
10” 90&45 degree Ell, 10” Transitions
Xray
Additional 10” Pipe for New Route
Amy White 10” & 4” Install
Amy White Hot Tap Fittings
Amy White Hot Tap
10,000 ft. 8.625” .188 wt x-52
Baker Well Connect Valves and Fittings
2 - 3” 600 Series Spiral Gaskets
5700’ 6 5/8” x 0.188 wt X-52 w/FBE and 600’ Same w/Lilly
Installation - Beechwood 6”
X-Ray Inspection
Additional 6” Bore Pipe
Valves and Fittings
Valves and Fittings
Atmospheric Storage Tank
Carry Over Scrubber
Control Valves
Moisture Analyzer
2” fuel gas meter tube
Level Controller
Blowdown Silencer
4” .188” X-42 pipe
Install 2200’ 4” Pipe
Miscellanous Manual Valves
Relief Valves
Startup Strainers
Misc. pipe/valves/fittings
Amy White
Amy White
Amy White
Amy White
Amy White
Amy White
Amy White
Amy White
Amy White to Copeland
Baker Well Connects
Baker Well Connects
Beechwood P/L
Beechwood P/L
Beechwood P/L
Beechwood P/L
Beechwood P/L
Beechwood P/L
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Davis & Davis
Mike Fann & Assoc.
Bell Supply Company
QB Johnson
QB Johnson
Kleinfleder
Columbine Control Company
ValveSystems
ValveSystems
JW Williams
Valve Repair Consultants, LLC
Technical Sales
ValveSystems
Redman
Venable’s Construction
Link Field Services
ValveSystems
Tech Services
Horton Tree Service
QB Johnson
Rosemount Inc.
Gopher Electronics
Rexal/Ryall
Redman
Link Field Services
Redman
Redman
Redman
Red Man
Level Switches and Level Cages
Boswell Noise Survey
Misc Fittings for Boswell Meadows
45 MM TEG Dehydrator
Inlet Separator & TEG Carry Over Vessels
Boswell Meadows Soil Analysis
Level Switches for Boswell Meadows
Boswell Meadows ESD Valves
Boswell Meadows Control Valves
Boswell Meadows Fuel Meter
Boswell Meadows PSV’s
Boswell Meadows Block Valves
Piston Check Valve
Materials for Boswell Meadows
Boswell Meadows Compressor Station Install
X-ray on Boswell Meadows Station
Additional PSV’s for Boswell Meadows
Fuel Control Valve
Totalflow
Tree removal at Boswell Meadows
Kimray Pump
Pressure Transmitters
Relays
AB Analog Input Card
Standard wall pipe for C-800 connection and other projects
Chang #1 Connection
Misc Fittings for Christ Haven
Christ Haven Fittings
4 - 6” 3R 90s
Pipe and Fitting for Treater
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
Boswell Meadows
C-800 Connection
Chang Well
Christ Haven
Christ Haven
Christ Haven
CO2 Treater
LANShack, Inc
Coastal Chemical
Thermal Scientific
Scott Schamp
Valve Systems
Davis & Davis
Coastal Chemical
Rexal/Ryall
Rosemount Inc.
ATCO Noise
B&J
Beta Machinery
Best Pump Works
UE Compression
Universal Compression
UE Compression
UE Compression
UE Compression
Bell Supply Company
QB Johnson
Pioneer Pipe
Pioneer Pipe
ValveSystems
Leeds Fabrication
LanShack Fiber Optic Cables
Amine/Antifoam
Test Equipment
Deionized Water
Valve Systems Reg for Blanket gas
Davis & Davis HHLS for Flash tank
Travis Perry - Tanks and Installation
Amine
Rexell AI Card
Rosemount Transmitters
Silencer for vent stack
Hook up RO unit
Vibration Study on Pump Skid
Amine skid centrifugal pumps
Two 7044/Ariel
Two 7044/Ariel
Adder for Thomas Coupling
Coolant Filtration Systems
Adder for Ace T8-2 Cooler
Miscellaneous 10” Fittings
20 MM Dehy
Pipeline PSV
Pipeline PSV
4” x .156 wall bore pipe
8” 0.219 wall X-52
Control Valves
Basket Strainer
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
CO2 Treater
Compression
Compression
Compression
Compression
Compression
Copeland 10”
Dehy for future site
Devon Baptist SE
Devon Baptist SW
Devon SW Tie-in
Dido
East Texas
East Texas
Pioneer
Sisco
Redman
Link Field Services
TEPSCO
Link Field Services
Mastec
Redman
Redman
Sisco
Redman Supply
Redman Supply
Redman
Redman
Mastec
Mastec
Mastec
Redman
Redman
Pioneer Pipe
JD Fields
Redman
10” and 4” Line Pipe
10” Transitions & Anchor Flange
Standard Fittings, Pipe, 4” Valves
Xray
Lithographia Installation
X-ray on Fossil Creek Phase 2
Fossil Creek Phase 2 T&M Install
Fittings for Fossil Creek Phase 2
Phase 2 materials for Chang well
Phase 2 Materials
Fittings for Piggable Tee
8” & 10” Ball Valves
Railroad Bore Materials
Power Crete 10” pipe
Relocation of Parr launcher to FC Phase 2
Install 4” Chang Well Flowline
Fossil Creek Phase 3 T&M Install
Phase 3 materials for 10” valve set
Fossil Creek 3 0.365 pipe
10” Line Pipe
10.75 .219 wall pipe
Fossil Creek Phase 4 Laucher Materials
Fossil Creek Phase 1
Mastec
Redman
Pioneer Pipe
Redman
Redman
Sisco
Moylan Construction
Link Field Services
Bell Supply Company
Pioneer Pipe
Sisco
Redman
Redman
Sisco
Pioneer Pipe
Redman
Redman
Link Field Services
Sisco
JD Fields
Redman
Redman
Pioneer Pipe
TEPSCO
Redman
Sisco
Redman
Link Field Services
Fossil Creek Phase 4 Install
Materials to hook-up Martha Parr
6” & 8” Line Pipe
6” Launcher Fittings
8” Receiver Fittings
6” and 8” Transition Fittings, etc.
Hayco H Pad P/L Construction
Hayco H Pad P/L X-Ray Services
Misc. Fittings HEP Tie-in
Pipe for Indian Creek
Industrial Blvd 10” Materials
Industrial Blvd 10” Materials
Industrial Blvd Receiver Materials
Industrial Blvd Receiver Materials
Industrial Blvd 10” Install
10” Line Pipe
Tee and Valve for new well on Industrial Blvd
Industrial Blvd Tie-in Materials Open Ended
Industrial Blvd X-Ray
10” Transitions and 3R Fittings
Inventory 10” 0.219 X-52 and 8” 0.188 X-52
Isbell Tie In Fittings
Field Ordered Fittings
L&S Extension Pipeline Install
L&S L/R Fittings, valves, etc.
L&S 6” & 8” Transitions, Fittings
L&S 6” & 8” STD Fittings and valves, etc.
L&S Extension X-Ray Services
Hayco H Pad Line
Hayco H Pad Line
Hayco H Pad Line
Hayco H Pad Line
Hayco H Pad Line
Hayco H Pad Line
HEP Tie-in
Indian Creek I & H Leases
Industrial Blvd
Industrial Blvd
Industrial Blvd
Industrial Blvd
Industrial Blvd
Industrial Blvd
Industrial Blvd
Industrial Blvd
Industrial Blvd
Inventory
Inventory
Isbell
L&S
L&S Extension
L&S Extension
L&S Extension
L&S Extension
L&S Extension
L&S Extension
Redman
Pioneer Pipe
Pioneer Pipe
Mastec
Link Field Services
Bell Supply Company
Bell Supply Company
Redman Supply
Redman Supply
Redman Supply
Redman Supply
Redman Supply
Pioneer Pipe
Moylan Construction
Link Field Services
Sisco
Redman
Redman
Redman
Redman
Redman
Redman
JD Fields
ValveSystems
JW Williams
10”, 8” & 4” Pipe
8” Pipe - Legacy Bore to Legacy E Pad
4” Pipe Legacy E Pad to Devon SE Pad
Pipeline PSV
Legacy to Devon Baptist - Construction
Legacy to Devon Baptist - X-Ray Inspection
Legacy 8” Launcher - Valves and Fittings
4” Launcher/Receiver Fittings
Long-Lead Ftgs / Transition Ftgs
Class 300 Pig Launcher Ftgs
8” & 10” Ball Valves
Marine Creek Fittings
Class 600 Pig Receiver Ftgs
10” Line Pipe
Marine Creek 10” Pipeline Installation
Marine Creek X-Ray Services
10” 3R 90s, 45s, & Transitions
Balance of Ftgs and Valves
Field Ordered Pipe and Fittings
Field Ordered 6” and 4” Pipe and Fittings
40’ 12” X .250 wt ERW Seamed pipe for welding test
Fittings & Valves for Marine Creek Tie-In
Marine Creek tie-in at Boswell Meadows materials
10.75 .219 wall pipe & 8.625 .188 wall pipe
Produced water secondary containment & low profile tank
Fuel & Start Gas Regulators
Mid-Point Fuel Meter Tube
Legacy
Legacy
Legacy
Legacy
Legacy to Devon Baptist SE
Marine Ck/Fossil Ck Ph III
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek
Marine Creek & D2H
Mid Point
Mid Point
Mid Point
ValveSystems
Redman
QB Johnson
Redman
ValveSystems
Moylan Construction
Winn Marion
Applied Control Equipment
Bell Supply Company
JD Fields
Pioneer Pipe
QB Johnson
ValveSystems
JW Williams
QB Johnson
Link Field Services
Bell Supply Company
Suction & Recycle Controls, Valves
Pipe, Valves & Fittings
16”x4’ Starting Gas Scrubber
Inlet Separator Relief Valve
Miscellanous Fittings
Level Controller and Dump Valve
Labor
Fairchild Mod 91 Signal Selector
Fisher 4160 Direct Acting Prop. Plus Reset Pressure Controller
Fittings for hydrotest
10” Pipe - Mid-Point to Copeland
8” Pipe - Mid-Point to Walsh-Dido
30 MM Dehy
MidPoint HP Compression Control and Check Valves
Fuel Meter
Inlet Separator & Fuel Scrubber
Mid-Point HP Compressor
PSV’s for Mid-Point HP Compression
PSV for Mid-Point Discharge Line
Field Ordered Fittings
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
Mid Point
MidPoint - High Pressure Compression
ValveSystems
10” 300# ESD Valve Operator
Redman
Midpoint 10” Piping and Walsh/Dido 8” Lilly Pipe
Kleinfleder
Mid-Point Geotechnical work
ValveSystems
Mid-Point Recycle Valve
UE Compression
Start-Up Assist
ValveSystems
PSV for Mid-Point Fuel
1200 psig PSV for Mid Point Dehy
Jet Specialty
Cathodic Wire for Mid-Point Loop and Others
Bell Supply Company
Welder Qualification Pipe
Jet Specialty
Fittings for Mid-Point
Dress out UE Compressors
Poly tank and containment for Mid Point dehy
Link Field Services
x-ray for weld repair on Mid Point HP compression
Bell Supply Company
Misc. fittings for Mid Point HP
Weld Repair for Mid Point HP Compression
Pipeline PSV
MidPoint - High Pressure
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Compression
Mid-Point North Loop 10”
Redman
Redman
Redman
SISCO
JD Fields
ValveSystems
Redman
Bell Supply Company
Mastec
JD Fields
Sisco
Bell Supply Company
Link Field Services
Pioneer Pipe
Orbit
Sisco
Link Field Services
Redman
Redman
Redman
Redman
Redman
Redman
Redman
JD Fields
Redman
JD Fields
Mastec
Fittings
Launcher/Receiver Fittings
L&R Valves, ESD Valves, Closures
L&R Transitions, 45 Ells, Anchor Flange
20,000’ of 10.75” x .250 wt API5L - X-52 Line Pipe
8” and 10” 600# Ball valves
Miscellaneous Valves and Fittings
Launcher/Receiver Fittings
MidPoint 10”1 Loop P/L Construction
2150’ 4 /2” 0.156 wt X-42
10” Transition Fittings
4” Valves and Fittings
X-Ray Inspection
Prairie Meadows Pipeline Install
6” and 8” Transition Fittings, etc.
Prairie Meadows P/L X-Ray Services
Prairie Meadows Materials
8” x 8” x 8” Tee, 8” weld cap
6 - 4” 90s
3-R Fittings for
Prairie Meadows
5
750’ of 8 /8” 0.188 X-52
Piping for various Prairie Meadows Well connects
200’ 6” .188 wt Lilly Coat
1000’ 4” .188 wt X42, FBE
Christ Haven Well Hookup - T&M
Mid-Point/Amy White
Mid-Point/Amy White
Mid-Point/Amy White
Mid-Point/Amy White
MidPoint/TriCounty Loop
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
TEPSCO
Pioneer Pipe
Sisco
Hanover
Bell Supply Company
Mastec
Link Field Services
JD Fields
Bell Supply Company
Jet Specialty
QB Johnson
ValveSystems
JW Williams
ValveSystems
Kleinfleder
Technical Sales
Moylan Construction
Redman
Moylan Construction
Link Field Services
Tech Services
ValveSystems
Insight
Insight Automation
Redman
Prairie Meadows 6” P/L to Baker #1 - T&M
2000’ 6.625” x 0.188 wt X-52
6” Transitions
Pigging Separator
Prairie Meadows PSV
8” Launcher & Receiver Materials
8” L/R Fabrication - T&M
8” L/R - X-ray
10” 0.219 X-52 for Quant Line
Fittings for Railhead
Railhead Materials
Inlet Separator & TEG Carry Over Vessels
Railhead Control Valves
Railhead Meter Tube
Railhead PSV’s
Railhead ESD valves
Railhead Soil Analysis
Railhead Block Valves
Railhead Installation
Railhead Materials
Railhead Foundations
X-ray on Railhead Station
Additional PSV for Railhead
Totalflow
Railhead Fuel Valve
Radio Survey - Database Import
SCADA Upgrades
20,000 ft. 10” .250 wall
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Prairie Meadows
Quant Line
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
Railhead
SCADA
SCADA
South Fort Worth
Bell Supply Company
Link Field Services
JD Fields
Bell Supply Company
Bell Supply Company
Bell Supply Company
Moylan Construction
Gopher Electronics
Rexall
Moylan Construction
Elliot
Davis & Davis
Analytical Systems
BJJ&A
Rosemount Inc.
Rawley Equipment
Moylan Construction
QB Johnson
Moylan Construction
Moylan Construction
ValveSystems
Link Field Services
ValveSystems
Insight
SISCO
Pipeline PSV
South Ft. Worth 10” Launcher/Receiver Fittings
South Ft. Worth 10” P/L Installation
X-Ray Inspection
Additional 10” Pipe for New Route
Pipe Materials for Mainline Block Valves
Additional Materials for Block valve and Well Pad Risers
Additional 3” and 10” Valves and materials
Civil Work at Tri-County
Relay and mount for MCC
MCC for Amine Unit
Site Work and Foundations
Cable Tray
Treater Inlet Meter
CO2 Analyzer
Water Treater
Rosemount Transmitters
Solenoids
Electrical Installation
QB Johnson Adders
Civil Work at Tri-County
Mechanical Installation
Actuated Ball Valve
Link Field Svc - X-ray
Regulators for Treater
Amine Plant Interface to Wonderware
12”, 0.250”, 3-R Sweeps
South Fort Woth
South Ft. Worth
South Ft. Worth
South Ft. Worth
South Ft. Worth
South Ft. Worth
South Ft. Worth
South Ft. Worth
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Treater
Tri-County
ValveSystems
ValveSystems
Mobile Mini
ValveSystems
Goolsby Testing Laboratories, Inc
Redman
Moylan Construction
Redman
SISCO
Redman
SISCO
ValveSystems
Natco
Mike Fenn & Assoc.
Redman
Trinity
Link Field Services
Wildcat Cranes
Redman
Redman
Redman
Redman
Redman
Redman
Redman
Redman
Redman
Valve Sales, Inc
Natco
QB Johnson
JW Williams
12” ESD valve & 10” ESD Valve
8” Suction Control, 3” Suction Control, 2” Recycle Control, Back Pressure Control
Office Trailer
3” Vent Valve
Welding Procedures
Pipe for Welder Testing
T&M work to install compressors
Misc. Pipe Valves & Fittings (#1)
12”, 0.375, Grade B 3-R 45 EL
Misc. Pipe Valves & Fittings (#2)
20” Fittings
Block & Check Valves
Pipeline Relief Valve
Dehy Firetube Replacement
Noise Survey
Tank Containment
Fittings
Trash Service
Welder Qualification Tests
Crane Work
Fittings
Fittings
Fittings
Fittings
Fittings
Fittings
Fittings
Fittings
Fittings
Fittings
New produced water tanks
Insulate dehy piping
Temperature Controller
10” Meter skid
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
ValveSystems
General Modular
ValveSystems
Davis & Davis
ValveSystems
ValveSystems
ValveSystems
QB Johnson
Rexel Ryall
Redman
Redman
ValveSystems
Winn-Marion
Redman
Winn-Marion
ValveSystems
Rexel Ryall
Moylan Construction
Metropolitan Aerial Surveys
QB Johnson
John Rheinheimer
QB Johnson
ValveSystems
J&B Pipe Insulation
Fuel Pressure Control Valve
8 x 20’ Office/Control Room
Gas Flow Control Valve for Amine Plant
Moisture Analyzer for Tri-County
Expansion project block valves
Fuel Gas Scrubber PSV
Suction control valves for south header
Level controller & dump valve for fuel scrubber
Mid Point Inlet Separator
Dehy MCC
Old Hot Tap Replacement Fittings
Fittings for 10-12 receiver kicker
Level Controller
Tri-County I/P’s
Compressor 700 materials
I/P Brackets
Trim for Fuel Control Valve
Lights for Tri-County
Dehy removal at Tri-County
C-100 install at Tri-County
Harvest Ridge Aerial Photo
Dehy Charcoal Filter
Level switches for Tri-County
Temp Gauge for Tri-County dehy
48” x 10’-0” TEG Carryover Scrubber
Instrument gas regulator and relief
Tri-County Insulating - Amine & Expansion
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Mike Fann & Assoc.
Redman
ValveSystems
Mann & Associates
ValveSystems
ValveSystems
Link Field Services
Timbercon, Inc.
GarrettCom, Inc.
Parrish Sales Inc.
Rexal/Ryall
QB Johnson
JW Williams
Redman
Redman
Redman
Redman
Redman
Redman
Kleinfleder
JW Williams
ValveSystems
Redman
ValveSystems
Rexel Ryall
Noise Survey
Shutdown Items
Blow Case Level switches
Blow Case Gas Valves
Glycol temp gauge
Devon Pig Trap Block Valves
C-800 Check Valve
C-800 Compressor
Tri-County Fiber Cable
Fiber Connectors
Dialers
Thermocouple Board
85 MM Dehydrator Package
85 MM Filter Separator
Fittings
Fittings
Fittings
Fittings
Fittings
Fittiings
Geotechnical Work
TXU 12” Meter Tube
TXU Flow Control Valve
52” Sight Glass
4” 600# discharge block valve
AB items for JB-1
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County
Tri-County - Expansion
Rexel Ryall
Standard Automation
Peterson Company
Allied Electronics
Winn-Marion
Gopher Electronics
Applied Control Equipment
Rosemount Inc.
Redman
ValveSystems
Apex Instruments
Redman
Redman
Redman
Red Man
Clearwater
Redman
Redman
Pioneer
Tulsa Valve
Pioneer
Rexal/Ryall
AB PKTX DH+ Card
Wonderware Software
24 volt Rectifier
12 volt batteries
Totalflow Chips
SD Relays for Compressors
I/P’s for Station
Pressure Transmitters
Bastard Hill Fittings & Tri-County Fittings
Tri-County PSV’s
Instrument gas regulator and relief
Instrument Gas filter/dryer
Materials for C-100 Install
Materials for C-100 Install
C-100 Suction Pipe
Pipe for Welder Testing
TEG Anti-foam
Well I1 Tie-In
3” Pipe
3” & 6” Pipe
3” Pig Valve
10” Pipe
2 HP MCC Bucket
Tri-County - Well Tie-In
Tri-County C-800 Install
QB Johnson
Redman
Sisco
Redman
Redman
Link Field Services
Bell Supply Company
JD Fields
Pioneer Pipe
J D Fields
J D Fields
JD Fields
JD Fields
JD Fields
Link Field Services
JD Fields
Bell Supply Company
Mastec
Moylan Construction
Bell Supply Company
Moylan Construction
Link Field Services
Kleinfleder
QB Johnson
ValveSystems
JW Williams
ValveSystems
Hanover
Link Field Services
46 MMSCFD-266 GPM Treater
Line Marker/C.P. Test Stations
Inventory 90’s & 45’s
Pig Signals for various projects
Pig Signals for various projects
Walsh-Dido 8” Construction
Walsh-Dido 8” - X-Ray Inspection
Walsh/Dido 8” L/R - Valves and Fittings
Pipeline PSV
4” .188wt pipe
4” .188wt pipe
4” .188wt pipe
6.625 .188 wall pipe
4” .188wt pipe
2 Loads 4” x .188 wt
X-Ray Inspection
Walsh/Copeland 10” Receiver
Walsh/Copeland 10” Install
West Lake Discharge Line Install
West Lake Fittings
Pipeline PSV
West Lake Compressor Station Install
West Lake X-Ray
West Lake Geoptechnical
West Lake Inlet Separator
West Lake Control Valves
Fuel Meter
ESD & Block Valves
40 MMCFD Dehy
West Lake PSV’s
West Lake tank and containment ring
Shutdown Items
Tri-County CO2
Various
Various
Various
Various
Walsh Dido - 8”
Walsh Dido - 8”
Walsh Dido - 8”
Walsh Dido - 8”
Walsh Dido - 8”
Walsh Ranch
Walsh Ranch
Walsh Ranch
Walsh Ranch
Walsh Ranch
Walsh Ranch
Walsh/Copeland
Walsh/Copeland
Walsh/Copeland 10”
Walsh/Copeland 10”
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
West Lake
X-ray for 10/5/04 shutdown
EXHIBIT C
FORM OF WARRANT AGREEMENT
WARRANT AGREEMENT
, 2005
dated as of
by and between
XTO ENERGY INC.
and
Certain Holders
THIS WARRANT AGREEMENT is dated as of April 1, 2005, by and between XTO ENERGY INC., a Delaware corporation (the “Company”), and these
persons and entities listed on Schedule A hereto (individually, a “Holder,” and, collectively, the “Holders”).
W I T N E S S E T H:
WHEREAS, the Company and Antero Resources Corporation (“Antero”) have entered into an Agreement and Plan of Merger dated as of January
(the “Acquisition Agreement”);
, 2005
WHEREAS, in partial consideration for the merger of Antero into a subsidiary of the Company under the Acquisition Agreement, the Company has agreed
to issue warrants to Holders to purchase shares of the Company’s common stock, par value $0.01 per share (the “Common Stock”);
NOW, THEREFORE, in consideration of the premises and the mutual agreements herein set forth and for other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
Section 1. Grant. The Company hereby grants to Holders the right to purchase (the “Warrants”), at any time and from time to time until 5:00 p.m., Fort
Worth, Texas time, on [April 1, 2010] (the “Exercise Period”), up to 1,500,000 shares (the “Shares”) of Common Stock (subject to adjustment as provided in
Section 8 hereof) at an exercise price of $36.00 per Share (subject to adjustment as provided in Section 8 hereof), all subject to the terms and conditions of this
Agreement. The number of Warrants granted to each Holder is set forth opposite such Holder’s name on Schedule A [to be added at Closing].
Section 2. Warrant Certificates. The warrant certificates (the “Warrant Certificates”) delivered and to be delivered pursuant to this Agreement shall be
substantially in the form set forth in Schedule A attached hereto and made a part hereof, with such appropriate insertions and other variations as required or
permitted by this Agreement. The Warrant Certificates shall further evidence the Warrants granted hereby.
Section 3. Exercise of Warrants; Method of Exercise.
(a) Cash Exercise. The purchase rights represented by the Warrant Certificates are exercisable at the option of the Holder (as defined herein) thereof, in
whole or in part (but not for fewer than 1,000 Shares), at any time and from time to time during the Exercise Period. Upon surrender of a Warrant Certificate with
the annexed Form of Election to Purchase duly executed, together with payment to the Company of the Common Stock Exercise Price (as hereinafter defined) by
federal wire transfer of immediately available funds for the Shares purchased, at the Company’s principal offices in Fort Worth, Texas (currently located at 810
Houston Street, Fort Worth, Texas 76102), the registered Holder of the Warrant Certificate shall be entitled to receive a certificate or certificates for the Shares so
purchased. In the case of the purchase of less than all the Shares purchasable under any Warrant Certificate, the Company, at its expense, shall cancel such
Warrant Certificate upon the surrender thereof and shall execute and deliver a
22
new Warrant Certificate of like tenor for the balance of the Shares purchasable thereunder. The Holder shall identify the aggregate number of Shares for which
the Warrant is exercised on the Form of Election to Purchase.
(b) Option for Net Exercise. In lieu of paying the Exercise Price in cash as provided in Section 3(a), the Holder may, by delivering a written request for net
exercise along with Holder’s duly executed Election to Purchase, elect to execute a net exercise of the Warrants to be exercised. For purposes hereof, a “net
exercise” means the Holder’s direction to the Company to retain from the Shares to be issued upon exercise of the Warrant a number of Shares having a fair
market value equal to the Exercise Price for all the Shares as to which the Warrant is being exercised such that the Holder pays no cash upon exercise of the
Warrant but receives a reduced number of Shares (such reduced number of Shares referred to herein as the “Net Shares”). For purposes of such net exercise, the
market value of the Shares will be the average of the daily closing price for the Common Stock on its principal trading exchange or market for the 10 trading
days next preceding the date the Election to Purchase and request for net exercise are received by the Company. A trading day shall be a day on which the
exchange or market on which the Common Stock is traded is open for trading. In the case of a net exercise, the Holder shall be entitled to receive a certificate or
certificates for the Net Shares so purchased. In the case of the purchase of less than all the Shares purchasable under any Warrant Certificate, the Company, at its
expense, shall cancel such Warrant Certificate upon the surrender thereof and shall execute and deliver a new Warrant Certificate of like tenor for the balance of
the Shares purchasable thereunder. The Holder shall identify the aggregate number of Shares for which the Warrant is exercised on the Form of Election to
Purchase.
Section 4. Issuance of Certificates. Upon the exercise of Warrants, the issuance of certificates for the Shares and/or other securities, properties or rights
underlying such Warrants shall be made forthwith (and in any event within five (5) business days thereafter) without charge to the Holder thereof including,
without limitation, any tax or other governmental charge imposed in respect of the issuance thereof (other than state or federal income taxes), and such
certificates shall (subject to the provisions of Section 5 hereof) be issued in the name of, or in such names as may be directed by, the Holder thereof; provided,
however, that the Company shall not be required to pay any tax or other governmental charge that may be payable in respect of any transfer involved in the
issuance and delivery of any such certificates in a name other than that of the Holder thereof and the Company shall not be required to issue or deliver such
certificates unless or until the person or persons requesting the issuance thereof shall have paid to the Company the amount of such tax or other governmental
charge or shall have established to the satisfaction of the Company that such tax or charge has been paid or that no tax or other governmental charge is payable.
The Warrant Certificates and the certificates representing the Shares shall be executed on behalf of the Company by the manual or facsimile signature of
the Chairman or Vice Chairman of the Board of Directors or President or any Vice President of the Company under its corporate seal reproduced thereon and by
the manual or facsimile signature of the then-serving Treasurer or any Assistant Treasurer or Secretary or any Assistant Secretary of the Company. Warrant
Certificates shall be dated the date of execution by the Company upon initial issuance, division, exchange, substitution or transfer. Certificates representing the
Shares issuable upon exercise of
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Warrants shall be dated the date on which the exercise is perfected by the Holder as provided in Section 3 hereof (the “Exercise Date”) and any interest-bearing
securities so issued shall accrue interest from the Exercise Date.
Section 5. Transfers of Warrants.
Section 5.1. Investment Intent with respect to Warrants. The Warrants have not been registered under the Securities Act of 1933, as amended (the
“Securities Act”), or state securities laws. The Holder of a Warrant Certificate, by its acceptance thereof, represents and warrants that the Warrants are being
acquired as an investment and not with a view to the distribution thereof other than in compliance with applicable federal and state securities laws, and
understands and acknowledges that each Warrant Certificate shall bear a restrictive legend substantially as set forth below:
“THE WARRANTS REPRESENTED BY THIS CERTIFICATE AND THE OTHER SECURITIES ISSUABLE UPON EXERCISE THEREOF MAY
NOT BE OFFERED OR SOLD EXCEPT PURSUANT TO (i) AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933,
AS AMENDED, (ii) TO THE EXTENT APPLICABLE, RULE 144 UNDER SUCH ACT (OR ANY SIMILAR RULE UNDER SUCH ACT RELATING TO
THE DISPOSITION OF SECURITIES) OR (iii) AN OPINION OF COUNSEL, IF SUCH OPINION SHALL BE REASONABLY SATISFACTORY TO
COUNSEL FOR THE ISSUER, THAT AN EXEMPTION FROM REGISTRATION UNDER SUCH ACT IS AVAILABLE.
Section 5.2. Restrictions on Transferability of Warrants. Subject to compliance with all applicable federal and state securities laws, the Warrants may be
freely transferred by such Holder and its successors and assigns.
Section 6. Transfers of Shares.
Section 6.1. Investment Intent with respect to Shares. The Holder of a Warrant Certificate, by its acceptance thereof, represents and warrants that the
Shares issuable upon exercise of Warrants shall be acquired as an investment and not with a view to the distribution thereof other than in compliance with
applicable federal and state securities laws, and understands and acknowledges that each certificate representing Warrant Stock shall bear a restrictive legend
substantially as set forth below:
“THE COMMON STOCK REPRESENTED BY THIS CERTIFICATE MAY NOT BE OFFERED OR SOLD EXCEPT PURSUANT TO (i) AN
EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933, AS AMENDED, (ii) TO THE EXTENT APPLICABLE, RULE 144
UNDER SUCH ACT (OR ANY SIMILAR RULE UNDER SUCH ACT RELATING TO THE DISPOSITION OF SECURITIES) OR (iii) AN OPINION OF
COUNSEL, IF SUCH OPINION SHALL BE REASONABLY SATISFACTORY TO COUNSEL FOR THE ISSUER, THAT AN EXEMPTION FROM
REGISTRATION UNDER SUCH ACT IS AVAILABLE.
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provided, however, that no such legend shall be included on the certificate representing any Warrant Stock if such Shares are freely tradeable under Rule 144 as a
result of a net exercise pursuant to Section 3(b) hereof.
Section 6.2. Transferability of Shares. Subject to compliance with all applicable federal and state securities laws, Shares may be freely transferred by each
Holder and its successors and assigns.
Section 7. Exercise Price.
Section 7.1. Initial Exercise Price and Adjusted Exercise Price. The initial exercise price of each Warrant shall be $36.00 (the “Initial Exercise Price”). The
adjusted exercise price for Common Stock shall be the price that shall result from time to time from any and all adjustments of the initial exercise price in
accordance with the provisions of Section 8 hereof (the “Adjusted Exercise Price”).
Section 7.2. Common Stock Exercise Price. The term “Common Stock Exercise Price” herein shall mean the Initial Exercise Price or, if the Initial Exercise
Price has been adjusted pursuant to the terms of Section 8 hereof, the Adjusted Exercise Price.
Section 8. Adjustments to Exercise Price and Number of Securities.
Section 8.1. Computation of Adjusted Exercise Price. Except as hereinafter provided, in case the Company shall issue or sell, or any Company subsidiary
shall sell, any shares of Common Stock at any time after the date hereof (other than the issuances or sales referred to in Section 8.3 or 8.7 hereof), including
shares held in the treasury of the Company or by any Company subsidiary (but excluding (i) shares issued upon the exercise of any options, rights or warrants
and shares issued upon the direct or indirect conversion or exchange of securities and (ii) shares issued pursuant to employee or director benefit plans approved
by a majority of the entire Board of Directors of the Company or any Company subsidiary, as the case may be), for consideration per share less than the Market
Price per share of Common Stock on the date immediately prior to the issuance or sale of such shares, or without consideration, then forthwith upon such
issuance or sale, the Common Stock Exercise Price shall (until another such issuance or sale or other event giving rise to an adjustment to the Common Stock
Exercise Price pursuant to this Section 8) be adjusted (calculated to the nearest full cent) by multiplying the Common Stock Exercise Price in effect immediately
prior to such issuance or sale by the quotient derived by dividing (a) an amount equal to the sum of (1) the total number of shares of Common Stock outstanding
immediately prior to such issuance or sale plus (2) the number of shares of Common Stock that the aggregate consideration received by the Company in
connection with such issuance or sale would purchase at such Market Price, by (b) the total number of shares of Common Stock outstanding immediately after
such issuance or sale; provided, however, that in no event shall the Common Stock Exercise Price be adjusted pursuant to this computation to an amount in
excess of the Common Stock Exercise Price in effect immediately prior to such computation, except in the case of a combination of outstanding shares of
Common Stock as provided by Section 8.3 hereof.
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As used herein, the “Market Price” of Common Stock at any date shall be deemed to be the last reported sale price (expressed as a dollar value per share)
or, in case no such reported sale takes place on such day, the average of the last reported sale prices for the last three (3) trading days, in either case as officially
reported by the principal securities exchange on which the Common Stock is listed or admitted to trading or, if not so listed or admitted, by the National
Association of Securities Dealers Automated Quotation System (“NASDAQ”) National Market System (“NASDAQ/NMS”) or, if not approved for quotation on
the NASDAQ/NMS, the average of the closing bid and asked prices as furnished by the National Association of Securities Dealers, Inc. (the “NASD”) through
NASDAQ or a similar organization if NASDAQ is no longer reporting such information or, if such security is not quoted on NASDAQ, as determined
reasonably and in good faith by resolution of the Board of Directors of the Company, based on the best information available to it.
For the purposes of any computation to be made in accordance with this Section 8.1, the following provisions shall be applicable:
(i) in case of the issuance or sale of shares of Common Stock for consideration part or all of which shall be cash, the amount of the cash
consideration therefore shall be deemed to be the amount of cash received by the Company for such shares (or, if shares of Common Stock are offered by
the Company for subscription, the subscription price, or, if shares of Common Stock shall be sold to underwriters or dealers for public offering without a
subscription offering, the initial public offering price) before deducting therefrom any compensation paid or discount allowed in the sale, underwriting or
purchase thereof by underwriters or dealers or others performing similar services or any expenses incurred in connection therewith;
(ii) in case of the issuance or sale of shares of Common Stock for consideration part or all of which shall be other than cash, the amount of the
consideration therefore other than cash shall be deemed to be the value of such consideration as determined in good faith by the Board of Directors of the
Company and shall include any amounts payable to security holders or any affiliates thereof, including without limitation, pursuant to any employment
agreement, royalty, consulting agreement, covenant not to compete, earned or contingent payment right or similar arrangement, agreement or
understanding, whether oral or written, all such amounts being valued for the purposes hereof at the aggregate amount payable thereunder, whether such
payments are absolute or contingent, and irrespective of the period or uncertainty of payment, the rate of interest, if any, or the contingent nature thereof;
provided, however, that if any Holder does not agree with such valuation, a mutually acceptable independent appraiser shall make such valuation, the cost
of which shall be borne 50% by the Company and 50% by the Holders;
(iii) shares of Common Stock issuable by way of dividend or other distribution on any stock of the Company other than the Common Stock shall be
deemed to have been issued immediately after the opening of business on the day following the record date for the determination of stockholders entitled
to receive such dividend or other distribution and shall be deemed to have been issued without consideration;
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(iv) The reclassification of securities of the Company (other than shares of Common Stock) into securities including shares of Common Stock shall
be deemed to involve the issuance of such shares of Common Stock for consideration other than cash immediately prior to the close of business on the date
fixed for the determination of security holders entitled to receive such shares, and the value of the consideration allocable to such shares of Common Stock
shall be determined as provided in subsection (ii) of this Section 8.1; and
(v) the number of shares of Common Stock at any one time outstanding shall include the aggregate number of shares issued or issuable (subject to
readjustment upon the actual issuance thereof), upon the exercise of options, rights and warrants and upon the conversion or exchange of convertible or
exchangeable securities, but shall exclude the aggregate number of shares held by Company subsidiaries for the Company’s benefit.
Section 8.2. Options, Rights, Warrants and Convertible and Exchangeable Securities. In case the Company shall at any time after the date hereof (except
pursuant to an employee or director benefit plan approved by a majority of the Company’s entire Board of Directors) issue options, rights or warrants to purchase
or subscribe for, or exercisable for, shares of Common Stock, or issue any securities convertible into or exchangeable for shares of Common Stock, for
consideration per share less than the Market Price for Common Stock immediately prior to the issuance of such options, rights, warrants or convertible or
exchangeable securities, or without consideration, the Common Stock Exercise Price in effect immediately prior to the issuance of such options, rights, warrants
or convertible or exchangeable securities, as the case may be, shall be reduced to a price determined by making a computation in accordance with the provisions
of Section 8.1 hereof; provided, however, that:
(a) the aggregate maximum number of shares of Common Stock, as the case may be, issuable under such options, rights or warrants shall be deemed to be
issued and outstanding at the time such options, rights or warrants were issued, and for consideration equal to the minimum purchase or subscription price per
share provided for in such options, rights or warrants at the time of issuance, plus the consideration (determined in the same manner as consideration received on
the issue or sale of shares in accordance with the terms of the Warrants), if any, received by the Company for such options, rights or warrants;
(b) the aggregate maximum number of shares of Common Stock issuable upon conversion or exchange of such convertible or exchangeable securities shall
be deemed to be issued and outstanding at the time of issuance of such securities, and for consideration equal to the consideration (determined in the same
manner as consideration received on the issue or sale of shares of Common Stock in accordance with the terms of the Warrants) received by the Company for
such securities, plus the minimum consideration, if any, receivable by the Company upon the conversion or exchange thereof; and
(c) if any change shall occur in the purchase or subscription price per share provided for in any of such options, rights or warrants or in the conversion or
exchange price per share of such securities, such options, rights, warrants or conversion or exchange rights, as the case may
27
be, shall be deemed to have expired or terminated on the date when such price change became effective in respect of shares not theretofore issued pursuant to the
exercise or conversion or exchange thereof, and the Company shall be deemed to have issued upon such date new options, rights, warrants or convertible or
exchangeable securities at the new purchase, subscription, conversion or exchange price in respect of the number of shares issuable upon the exercise of such
options, rights or warrants or the conversion or exchange of such convertible or exchangeable securities.
Section 8.3. Subdivision and Combination. In case the Company shall at any time (i) declare a dividend on the Common Stock payable in shares of its
capital stock (including Common Stock), (ii) subdivide or combine the outstanding shares of Common Stock, or (iii) issue any class of its capital stock in a
reclassification of the Common Stock (including any such reclassification in connection with a consolidation or merger in which the Company is the continuing
corporation), then the Common Stock Exercise Price in effect immediately prior to the record date for such dividend or the effective date of such subdivision,
combination or reclassification shall forthwith be proportionately adjusted so that the holder of any Warrant exercised after such date shall be entitled to receive
the aggregate number and kind of capital stock that, if such Warrant had been exercised immediately prior to such date, such holder would have owned upon
such exercise and been entitled to receive by virtue of such dividend, division, subdivision, combination or reclassification.
Section 8.4. Adjustment in Number of Securities. Upon each adjustment of the Common Stock Exercise Price pursuant to the provisions of this Section 8,
the number of shares of Common Stock issuable upon exercise at the adjusted Common Stock Exercise Price of each Warrant shall be adjusted to the nearest full
share by multiplying a number equal to the Common Stock Exercise Price in effect immediately prior to such adjustment by the number of shares of Common
Stock issuable upon exercise of Warrants immediately prior to such adjustment and dividing the product so obtained by the adjusted Common Stock Exercise
Price.
Section 8.5. Common Stock. If any class, classes and/or series of capital stock is issued in exchange for Common Stock upon conversion thereof or in lieu
thereof in connection with any change in par or stated value, recapitalization, reorganization or other transaction, such class, classes and/or series of capital stock
shall thereafter be the Common Stock referred to herein.
Section 8.6. Merger or Consolidation. In case of any consolidation, merger or similar business combination of the Company with or into another
corporation or other entity (other than a consolidation or merger in which the Company is the continuing corporation and that does not result in any
reclassification or change of the outstanding Common Stock or other securities issuable upon exercise of Warrants) or in case of any sale or conveyance to
another person, corporation or other entity of all or substantially of the assets and the property of the Company, then, as a condition of such consolidation,
merger, combination, sale or conveyance, the Company, or such successor or purchasing corporation, as the case may be, shall execute and deliver to the Holder
of each Warrant then outstanding a supplemental warrant agreement providing that such Holder shall have the right thereafter to receive, upon exercise of such
Warrant (until the expiration of such Warrant) the kind and amount of securities, rights and
28
property receivable upon such consolidation, merger, combination, sale or conveyance by a holder of the number of Shares issuable upon exercise of such
Warrant immediately prior to such consolidation, merger, sale or transfer. In determining the kind and amount of securities, rights and property receivable upon
consummation of consolidation, merger, combination, sale or conveyance, if the holders of Common Stock (or other securities issuable upon exercise of
warrants) have the right to elect the kind or amount of consideration receivable, then the Holder of each Warrant shall have the right to make a similar election
upon exercise of the Warrant with respect to the number of shares or other securities or property which such Holder will receive upon exercise of the Warrant.
Such supplemental warrant agreement shall provide for adjustments that shall be identical to the adjustments provided in this Section 8. The above provision of
this subsection shall similarly apply to successive consolidations, mergers, conveyances and sales.
Section 8.7. No Adjustment of Exercise Price in Certain Cases. No adjustment of the Common Stock Exercise Price shall be made:
(a) upon the issuance or sale of the Warrants, upon exercise of the Warrants or the issuance of the shares of Common Stock issuable upon the exercise of
the Warrants; or
(b) if the amount of said adjustment shall be less than one cent ($0.01) per share; provided, however, that in such case any adjustment that would otherwise
be required then to be made shall be carried forward and shall be made at the time of and together with the next subsequent adjustment that, together with any
adjustment so carried forward, shall amount to at least one cent ($0.01) per share.
Section 8.8. Certificate of Adjustment. After each adjustment of the Common Stock Exercise Price or the number of Shares purchasable upon exercise of
Warrants pursuant to this Section 8, the Company will promptly prepare a certificate signed by the Chairman or President, and by the Treasurer or an Assistant
Treasurer or the Secretary or an Assistant Secretary, of the Company setting forth: (i) the Common Stock Exercise Price, as so adjusted; (ii) the number of Shares
purchasable upon exercise of each Warrant after such adjustment; and (iii) a brief statement of the facts accounting for such adjustment. The Company will
promptly file such certificate with its records and cause a brief summary thereof to be sent by first class mail to each Holder at his last address as it shall appear
on the registry books of the Company. No failure to mail such summary nor any defect therein or in the mailing thereof shall affect the validity thereof.
Section 8.9. Validity of Warrant Certificate. Irrespective of any adjustments or changes in the Common Stock Exercise Price or the number of Shares
purchasable upon exercise of Warrants, Warrant Certificates theretofore and thereafter issued shall continue to express the Common Stock Exercise Price per
share and the number of Shares purchasable thereunder as of the date such Warrant Certificates were originally issued; provided, however, that the Holders shall
be entitled to exercise Warrants represented by such Warrant Certificates after giving effect to each such adjustment and change, and such Warrant Certificate
shall be deemed to incorporate each such adjustment and change as if new Warrant Certificates reflecting each such adjustment and change had been issued to
the Holders.
29
Section 8.10. Dividends and Other Distributions. In the event that the Company shall at any time prior to the exercise of all Warrants declare a dividend
(other than a dividend consisting solely of shares of Common Stock and other than a regularly scheduled dividend with respect to any calendar year declared
within such calendar year or the following calendar year that does not exceed one hundred percent (100%) of net earnings (after taxes) for such calendar year) or
otherwise distribute to all its stockholders any assets (including shares of any subsidiary), property, rights, evidences of indebtedness, securities (other than shares
of Common Stock) then, forthwith upon such declaration, the Common Stock Exercise Price (until another such declaration or other event causing price
adjustments to the Common Stock Exercise Price pursuant to this Section 8), shall be adjusted (calculated to the nearest $0.0001) by multiplying the Common
Stock Exercise Price in effect immediately prior to the record date for such dividend or other distribution by the quotient derived by dividing (i) the difference
between (a) the product of the number of shares of Common Stock outstanding immediately prior to such declaration multiplied by the Market Price for
Common Stock immediately prior to such declaration and (b) the aggregate fair market value amount of such dividend or distribution so declared by (ii) the
product of the number of shares of Common Stock outstanding immediately prior to such declaration multiplied by the Market Price for Common Stock
immediately prior to such declaration. Such adjustments shall be made on the record date for determination of stockholders entitled to receive such dividend or
distribution.
Section 9. Exchange and Replacement of Warrant Certificates. Each Warrant Certificate is exchangeable, without expense, upon the surrender thereof by
the Holder at the principal executive office of the Company, for one or more new Warrant Certificates of like tenor and date representing in the aggregate the
right to purchase the same number of Shares in such denominations as shall be designated by the Holder at the time of such surrender.
Upon receipt by the Company of evidence reasonably satisfactory to it of the loss, theft, destruction or mutilation of any Warrant Certificate, and, in case
of loss, theft or destruction, of indemnity or security reasonably satisfactory to it, and reimbursement to the Company of all reasonable expenses incidental
thereto, and upon surrender and cancellation of such Warrant Certificates, if mutilated, the Company will make and deliver a new Warrant Certificate of like
tenor in lieu thereof.
Section 10. Elimination of Fractional Interests. The Company shall not be required to issue certificates representing fractions of shares of Common Stock
upon the exercise of Warrants, nor shall it be required to issue scrip or pay cash in lieu of such fractional interests, it being the intent of the parties that all
fractional interests shall be eliminated by rounding any fraction up to the nearest whole number of shares of Common Stock or other securities, properties or
rights.
Section 11. Reservation and Listing of Securities. The Company shall at all times reserve and keep available out of its authorized capital stock, solely for
the purpose of issuance of Common Stock issuable upon exercise of Warrants, such number of shares of Common Stock as shall be issuable upon exercise
thereof. The Company covenants and agrees that, upon exercise of the Warrants and payment of the Common Stock Exercise Price, all Shares of
30
Common Stock and other securities issuable upon such exercise when issued shall be duly and validly issued, fully paid, non-assessable and not subject to the
preemptive rights of any security holder of the Company. As long as Warrants shall be outstanding, the Company shall use reasonable efforts to cause the
Common Stock issuable upon the exercise of Warrants to be listed (subject to official notice of issuance) on all securities exchanges on which the Common Stock
may then be listed and/or quoted on NASDAQ/NMS.
The Company represents and warrants that (a) the Company has been duly incorporated and is validly existing as a corporation in good standing under the
laws of Delaware and has all requisite power, authority and legal right to enter into this Agreement; (b) this Agreement has been duly executed and delivered by
the Company and constitutes a valid and legally binding agreement of the Company, enforceable against the Company in accordance with its terms, subject to (i)
bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium and other similar laws now or hereafter in effect relating to or affecting creditors’
rights generally and (ii) general principles of equity (regardless of whether considered in a proceeding at law or in equity); (c) the Warrants have been duly
authorized, validly issued and are fully paid and non-assessable and are not subject to any preemptive rights; (d) the issuance of the Warrants does not violate or
conflict with or result in a breach or default under (i) any material agreement or instrument by which the Company is bound or (ii) any judgment, decree, rule or
regulation applicable to the Company; and (e) as of October 29, 2004, the Company had 260,333,598 shares of Common Stock issued and outstanding.
Section 12. Notices to Warrant Holders. Nothing contained in this Agreement shall be construed as conferring upon the Holders of Warrants the right to
vote or to consent or to receive notice as a stockholder in respect of any meetings of stockholders for the election of directors or any other matter or as having any
rights whatsoever as a stockholder of the Company. If, however, at any time prior to the earlier of the expiration of the Warrants or their exercise, any of the
following events shall occur:
(a) the Company shall take a record of the holders of shares of Common Stock for the purpose of entitling them to receive a dividend or distribution
payable otherwise than in cash, or a cash dividend or distribution payable otherwise than out of current or retained earnings, as indicated by the accounting
treatment of such dividend or distribution on the books of the Company; or
(b) the Company shall offer to all the holders of shares of Common Stock any additional shares of capital stock of the Company or securities convertible
into or exchangeable for shares of capital stock of the Company, or any option, right or warrant to subscribe therefor; or
(c) a dissolution, liquidation or winding up of the Company (other than in connection with a consolidation or merger) or a sale of all or substantially all of
its property, assets and business as an entirety or a capital reorganization, merger or share exchange involving the Company shall be proposed;
31
Then, in any one or more of said events, the Company shall give notice of such event to each Holder of Warrants at least fifteen (15) days prior to the date
fixed as a record date or the date of closing the transfer books for the determination of the stockholders entitled to such dividend, distribution or offer. Such
notice shall specify record date or the date of closing the transfer books, as the case may be. Failure to give such notice or any defect therein shall not affect the
validity of any action taken in connection with such dividend, distribution, offer, dissolution, liquidation, winding up or sale.
Section 13. Notices. All notices, requests, consents and other communications hereunder shall be in writing and shall be deemed to have been duly made
and given:
(a) when mailed by certified mail or overnight delivery service:
(i) if to any Holder, to the address of such person as shown on the books of the Company; or
(ii) if to the Company, to the Company’s General Counsel at the Company’s address set forth in Section 3 hereof or to such other address as the
Company may designate by notice to the Holders; or
(b) when sent by facsimile transmission (with telephonic confirmation of receipt), if to the Company, to the Company’s General Counsel at 817/870-1671
(confirming telephone number 817/870-2800) or to such other facsimile and confirming telephone numbers as the Company may designate by notice to the
Holders.
Section 14. Successors. All the covenants and provisions of this Agreement shall be binding upon and inure to the benefit of the Company and Holders and
their respective successors and assigns hereunder to the extent set forth herein.
Section 15. Termination. Except for the covenant of the Company contained herein that all Shares shall be validly issued, fully paid and non-assessable,
this Agreement, and all provisions hereof, shall terminate at 5:00 p.m., Fort Worth, Texas time on [April 1, 2010].
Section 16. Governing Law; Submission to Jurisdiction. This Agreement and each Warrant Certificate issued hereunder shall be deemed to be a contract
made under the laws of the State of Delaware and for all purposes shall be in accordance with the laws of such State without giving effect to the rules of such
State governing conflicts of laws.
Section 17. Entire Agreement; Modification or Amendment. This Agreement contains the entire understanding between the parties hereto with respect to
the subject matter hereof and may not be modified or amended except by a writing duly signed by the party against whom enforcement of the modification or
amendment is sought.
Section 18. Severability. If any provision of this Agreement shall be held to be invalid or unenforceable, such invalidity or unenforceability shall not affect
any other provision of this Agreement.
32
Section 19. Captions. The caption headings of the Sections of this Agreement are for convenience of reference only, are not intended as, nor should they be
construed as, a part of this Agreement and shall be given no substantive effect.
Section 20. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed an original and all of which
taken together shall constitute one and the same instrument.
[The remainder of this page has intentionally been left blank]
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IN WITNESS WHEREOF, the parties hereto have caused this Warrant Agreement to be duly executed as of the day and year first above written.
XTO ENERGY INC.
By:
Vaughn O. Vennerberg II,
Executive Vice President-Administration
Attest:
By:
Frank G. McDonald,
Assistant Secretary
SHAREHOLDERS
[Signature Blocks to come]
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SCHEDULE A
(FORM OF WARRANT CERTIFICATE)
THE WARRANTS REPRESENTED BY THIS CERTIFICATE AND THE OTHER SECURITIES ISSUABLE UPON EXERCISE THEREOF MAY
NOT BE OFFERED OR SOLD EXCEPT PURSUANT TO (i) AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933,
AS AMENDED, (ii) TO THE EXTENT APPLICABLE, RULE 144 UNDER SUCH ACT (OR ANY SIMILAR RULE UNDER SUCH ACT RELATING TO
THE DISPOSITION OF SECURITIES) OR (iii) AN OPINION OF COUNSEL, IF SUCH OPINION SHALL BE REASONABLY SATISFACTORY TO
COUNSEL FOR THE ISSUER, THAT AN EXEMPTION FROM REGISTRATION UNDER SUCH ACT IS AVAILABLE.
EXERCISABLE ON OR BEFORE
5:00 P.M., FORT WORTH, TEXAS TIME, [APRIL 1, 2010].
WARRANTS
WARRANT NO. 00
This Warrant Certificate certifies that
, or its registered assigns (“Holder”), is the holder of Warrants to purchase, in whole or in part, at any
time from the date of this Warrant Certificate until 5:00 p.m. Fort Worth, Texas time on [April 1, 2010] (the “Expiration Date”),
(
) fully paid
and non-assessable shares of Common Stock, par value $0.01 per share (the “Common Stock”), of XTO ENERGY INC., a Delaware corporation (the
“Company”), at the initial exercise price, subject to adjustment in certain events (the “Common Stock Exercise Price”), of $36.00 per share, upon surrender of
this Warrant Certificate and payment of the Common Stock Exercise Price at an office or agency of the Company, but subject to the conditions set forth herein
and in the Warrant Agreement of even date herewith between the Company and Holder (the “Warrant Agreement”). Each Warrant initially entitles the Holder to
purchase one (1) share of Common Stock. Payment of the Common Stock Exercise Price shall be made by federal wire transfer of immediately available funds
payable to the order of the Company or by net exercise as provided in the Warrant Agreement.
No Warrant may be exercised after 5:00 p.m., Fort Worth, Texas time, on the Expiration Date, at which time all Warrants evidenced hereby, unless
exercised prior thereto, shall thereafter be void.
The Warrants evidenced by this Warrant Certificate are issued pursuant to the Warrant Agreement, which is hereby incorporated by reference in, and made
a part of, this instrument and which is hereby referred to for a description of the rights, limitation of rights, obligations, duties and immunities thereunder of the
Company and the Holder.
1
The Warrant Agreement provides that, upon the occurrence of certain events and subject to certain conditions, the Common Stock Exercise Price and the
number and/or kind of securities issuable upon exercise of Warrants may be adjusted. In such event, at the written request of the Holder and in exchange for the
old Warrant Certificate, the Company will issue a new Warrant Certificate evidencing the adjustment in the Common Stock Exercise Price and the number
and/or kind of securities issuable upon the exercise of Warrants; provided, however, that the failure of the Company to issue any such new Warrant Certificate
shall not in any way adversely change, alter or otherwise impair the rights of the Holder pursuant to the Warrant Agreement.
Upon due presentment for registration of assignment of this Warrant Certificate at an office or agency of the Company, and subject to the limitations
provided herein and in the Warrant Agreement, a new Warrant Certificate or Warrant Certificates of like tenor and evidencing in the aggregate a like number of
Warrants shall be issued to the assignee(s) in exchange for this Warrant Certificate without charge except for taxes or other governmental charges that are
imposed in connection with such transfer.
Notwithstanding any notation of ownership or other writing hereon made by anyone, the Company may deem and treat the Holder as the absolute owner(s)
of this Warrant Certificate for the purpose of any exercise of Warrants or of any distribution to the Holder and for all other purposes, and the Company shall not
be affected by any notice to the contrary.
All terms used in this Warrant Certificate that are defined in the Warrant Agreement shall have the meanings respectively ascribed to them in the Warrant
Agreement.
[The remainder of this page is intentionally left blank]
2
IN WITNESS WHEREOF, the Company has caused this Warrant Certificate to be duly executed under its corporate seal.
Dated as of
,
.
XTO ENERGY INC.
By:
Printed Name:
Title:
Attest:
By:
Printed Name:
Title:
3
FORM OF ELECTION TO PURCHASE
The undersigned hereby irrevocably elects to exercise the right, represented by this Warrant Certificate, to purchase
(
) shares of
,
Common Stock pursuant to the method of payment indicated below, all in accordance with the terms of that certain Warrant Agreement dated as of
2005, by and between XTO ENERGY INC. and
. The undersigned requests that a certificate for such securities be registered to the following person
at the following address:
Printed Name:
SSN or TIN:
Address:
and that such certificate be delivered to the following person at the following address:
Printed Name:
Address:
Method of Payment:
�
Cash payment in immediately available funds
�
Net exercise
Date:
Signature:
(Signature must conform in all respects to name of Holder as it appears on
the face of the Warrant Certificate)
Holder’s Social Security Number or Taxpayer Identification Number:
4
FORM OF ASSIGNMENT
(To be executed by the Holder to transfer the Warrant Certificate)
FOR VALUE RECEIVED,
hereby sells, assigns and transfers to the following person at the following address:
Printed Name:
SSN or TIN:
Address:
Warrants represented by this Warrant Certificate, together with all right, title and interest therein, and does hereby irrevocably constitute and appoint
attorney to transfer this Warrant Certificate on the books of XTO ENERGY INC., with full power of substitution.
Date:
Signature:
(Signature must conform in all respects to name of Holder as it appears on
the face of the Warrant Certificate)
5
EXHIBIT D
LIST OF OFFICERS TO SIGN
NON-COMPETITION AGREEMENTS
Paul M. Rady Chairman and CEO
3 years
Glen C. Warren, Jr. President and CFO
3 years
Terrell A. Dobkins VP-Production
2 years
Brian A. Kuhn VP-Land
2 years
Steven M. Woodward VP-Business Development
2 years
Bryan G. Hassler VP-Gas Gathering, Marketing and Transportation
2 years
Robert E. Mueller Chief Geologist
2 years
1
EXHIBIT E
FORM OF REGISTRATION RIGHTS AGREEMENT
REGISTRATION RIGHTS AGREEMENT
, 2005, (this “Agreement”), is entered into by and among XTO Energy Inc., a Delaware
This Registration Rights Agreement, dated as of
corporation (“Issuer”), and the securityholders of Antero Resources Corporation, a Delaware corporation (“Antero”), named on the signature pages hereto (each
a “Holder” and collectively, the “Holders”).
RECITALS
(g) WHEREAS, Issuer is a party to that certain Agreement and Plan of Merger, dated as of January
, 2005 (the “Merger Agreement”), that provides,
among other things, that (i) XTO Barnett Inc., a Delaware corporation and a wholly-owned subsidiary of Issuer (“Merger Subsidiary”), will be merged with and
into Antero with Antero continuing as the surviving corporation (the “Surviving Corporation”), and (ii) immediately after the merger, Issuer will own all of the
issued and outstanding capital stock of the Surviving Corporation.
(h) WHEREAS, subject to the terms and conditions of the Merger Agreement, at the Closing (as defined therein), the Holders shall receive or become
entitled to receive shares of common stock, $0.01 par value, of Issuer (the “Common Stock”).
(i) WHEREAS, as a condition precedent to the consummation of the transactions contemplated by the Merger Agreement, Issuer has agreed to grant the
Holders certain registration rights, as set forth herein, with respect to the Registrable Securities (as defined herein).
AGREEMENT
NOW, THEREFORE, in consideration of the premises, and the mutual representations, warranties, covenants, and agreements hereinafter set forth, the
parties hereto agree as follows:
ARTICLE 11 Definitions.
11.1 All capitalized terms used but not defined herein shall have the meaning ascribed to such term in the Merger Agreement.
11.2 “Registrable Securities” means (i) all of the Common Stock issued to a Holder as consideration pursuant to the Merger Agreement, plus
(ii) all of the Common Stock issued to a Holder upon exercise of a Warrant received as consideration pursuant to the Merger Agreement, plus (iii) other
securities of Issuer issued in respect of such Common Stock, by way of a stock split, stock dividend, recapitalization, merger or consolidation, or
otherwise, but exclusive of (iv) any securities described in clause (i), (ii) or (iii) above sold in a public offering registered under the Securities Act of
1933, as amended (the “Act”) or which may be sold by such Holder pursuant to Rule 144(k) promulgated under the Act.
2
11.3 “Registration Expenses” means all expenses incident to Issuer’s performance of or compliance with this Agreement, including all
registration, filing, listing and NASD fees, all fees and expenses of complying with securities or blue sky laws, all word processing, duplicating and
printing expenses, messenger and delivery expenses, the fees and expenses of counsel for Issuer and of its independent public accountants, including the
expenses of any special audits or “cold comfort” letters required by or incident to such performance and compliance and any fees and disbursements of
underwriters customarily paid by issuers of securities, but excluding underwriting discounts and commissions, transfer taxes, if any, and the fees and
expenses of any counsel retained by the Holders.
ARTICLE 12 Shelf Registration Statement for Holders.
12.1 Shelf Registration. Pursuant to Section 5.6 of the Merger Agreement, Issuer has prepared and filed with the Securities and Exchange
Commission (the “SEC”) a “shelf” registration statement on Form S-3 under the Securities Act for an offering to be made on a continuous basis
pursuant to Rule 415 of the Securities Act covering all of the Registrable Securities (the “Shelf Registration Statement”). The permitted method of
distribution of Registrable Securities under the Shelf Registration Statement shall be consistent with the plan of distribution attached hereto as Annex
A, and include sales complying with Rule 144(f), customary block trades and one underwritten offering of Registrable Securities under the Shelf
Registration Statement in accordance with Section 2(b). Issuer shall use its commercially reasonable best efforts to cause the Shelf Registration
Statement to become effective as soon as practicable following the closing of the Merger and to remain effective for a period of two (2) years from the
date of effectiveness (subject to any “black-out” periods pursuant to Section 4) (the “Shelf Registration”). The Shelf Registration Statement may include
securities other than the Registrable Securities, including shares of Common Stock for sale by the Issuer or securities holders other than the Holders.
The Shelf Registration Statement when declared effective (including the documents incorporated therein by reference) will comply as to form with all
applicable requirements of the Securities Act and the Exchange Act and will not contain an untrue statement of a material fact or omit to state a
material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made,
not misleading.
12.2 Underwriting.
(a) If Issuer shall at any time receive a notice of offering from any Holder or Holders holding a minimum of 15% of the Registrable
Securities then outstanding (but in no event less than 1,725,000 shares) requesting an underwritten public offering of Registrable Securities under the Shelf
Registration Statement that has anticipated aggregate proceeds at the time of the request (net of underwriting discounts, commissions and expenses) in excess of
$30,000,000, Issuer shall, subject to the terms and conditions hereof, be obligated to use its commercially reasonable best efforts to facilitate such proposed
underwritten public offering pursuant to the terms of this Agreement.
(b) Following receipt of the notice referred to in subsection 2(b)(i), Issuer shall promptly give a notice of offering to all Holders (other than
the requesting Holders),
3
which shall set forth the right of such Holders to include any or all shares of Registrable Securities held by such Holders in the proposed offering, subject to the
terms of this Agreement. Subject to subsection 2(b)(iv), Issuer shall use its commercially reasonable best efforts to facilitate the inclusion in the proposed
underwritten public offering of the number of shares of Registrable Securities specified in written requests from such Holders that are received by Issuer within
fifteen (15) days after Issuer provides its notice of offering to all Holders.
(c) Any underwritten public offering of Registrable Securities under the Shelf Registration Statement shall be broadly distributed. If at any
time any of the Holders of Registrable Securities covered by the Shelf Registration Statement desire to sell Registrable Securities in an underwritten offering in
accordance with the limitations of this subsection 2(b), the investment banker or investment bankers that will mange the offering will be nationally recognized
underwriters selected by Issuer.
(d) If all the shares of Registrable Securities requested to be included in the underwritten public offering pursuant to this Section 2(b) cannot
be so included as a result of any reasonable limit established by the underwriters on the aggregate number of shares of Registrable Securities included in such
underwriting, the number of shares of Registrable Securities that may be so included shall be allocated among Holders pro rata on the basis of the number of
shares of Registrable Securities held by such Holders; provided, however, that such allocation shall not operate to reduce the aggregate number of shares of
Registrable Securities that may be so included in such underwriting. If any Holder does not request inclusion of the maximum number of shares of Registrable
Securities allocated to it pursuant to the above-described procedure, the remaining portion of its allocation shall be reallocated among those requesting Holders
whose allocation did not satisfy their request pro rata on the basis of the number of shares of Registrable Securities held by such Holders, and this procedure shall
be repeated until all of the Registrable Securities which may be included in the underwriting have been so allocated.
(e) Holders holding a majority of the Registrable Securities exercising a demand right for an underwritten public offering under this
subsection 2(b) may withdraw the exercise of such right on behalf of all such exercising Holders as a result of a material adverse change in the earnings,
condition, financial or otherwise, or prospects of Issuer, or a material adverse change in the market for equity securities generally by giving written notice to
Issuer prior to the date the purchase agreement of such underwritten public offering is signed, and such withdrawn demand registration right shall not be deemed
to be the demand right provided under Section 2(b); provided, however, that Issuer shall not be required to deliver a notice of offering with respect to a renewed
or new demand for any underwritten public offering pursuant to subsection 2(b) or take any other action with respect to any such renewed or new demand for a
period of ninety (90) days following any such notice of withdrawal.
ARTICLE 13 Registration Procedures. In connection with its obligations contained in Section 2 hereof, Issuer will, subject to the terms and conditions
of this Agreement:
13.1 prepare and file with the SEC such amendments and supplements to the Shelf Registration Statement and any prospectus used in
connection therewith as may be necessary to keep such registration statement effective and to comply with the
4
provisions of the Act with respect to the disposition of all securities covered by such registration statement until the earlier of such time as all of such
Registrable Securities have been disposed of by the Holder or Holders thereof set forth in such registration statement or the expiration of a period of
two (2) years after such registration statement becomes effective. Notwithstanding anything else to the contrary contained herein, Issuer shall not be
required to disclose in any amendment or supplement to a registration statement or otherwise (i) any confidential information concerning any matter
that is the subject of a notice given under Section 3(f)(i) or Section 4 hereof as to which Issuer has a bona fide interest in withholding disclosure, or (ii)
historical financial statements or pro forma financial information required by Regulation S-X of the SEC in connection with a business acquisition or
disposition prior to the date when such information would otherwise be required to be filed with SEC (including extensions pursuant to Item 9.01(a)(4)
of Form 8-K);
13.2 furnish to each Holder of Registrable Securities covered by the Shelf Registration Statement such number of conformed copies of such
registration statement and of each such amendment and supplement thereto (in each case including all exhibits), such number of copies of the
prospectus contained in such registration statement (including each preliminary prospectus and any summary prospectus) and any other prospectus
filed under Rule 424 under the Act, in conformity with the requirements of the Act, and such other documents as such Holder may reasonably request;
13.3 use its commercially reasonable best efforts to register or qualify, prior to the effective date of such registration, all Registrable
Securities and other securities covered by the Shelf Registration Statement under such securities or blue sky laws of such jurisdictions as each Holder
thereof shall reasonably request, to keep such registration or qualification in effect for so long as such registration statement remains in effect, and take
any other action which may be reasonably necessary or advisable to enable such Holder to consummate the disposition in such jurisdictions of the
securities owned by such Holder, except that Issuer shall not for any such purpose be required to:
(a) qualify generally to do business as a foreign corporation in any jurisdiction wherein it would not but for the requirements of this Section
3(c) be obligated to be so qualified,
(b) subject itself to taxation in any such jurisdiction, or
(c) consent to general service of process in any such jurisdiction;
13.4 use its commercially reasonable best efforts to cause, prior to the effective date of the Shelf Registration Statement, all Registrable
Securities covered by such registration statement to be registered with or approved by such other governmental agencies or authorities as may be
necessary to enable the Holder or Holders thereof to consummate the disposition of such Registrable Securities;
13.5 furnish, at the request of any Holder of Registrable Securities exercising its rights pursuant to Section 2(b), on the date that such
Registrable Securities
5
are delivered to the underwriters for sale in connection with a sale pursuant to this Agreement, if such securities are being sold through underwriters,
(i) a copy of any opinion of counsel to Issuer addressed to the underwriters or Issuer and (ii) a copy of any letters from the independent accountants of
Issuer, addressed to the underwriters or Issuer;
13.6 (a) immediately notify each Holder of Registrable Securities covered by the Shelf Registration Statement, at any time when a
prospectus relating thereto is required to be delivered under the Act, of the happening of any event or the existence of any condition as a result of which
the prospectus included in such registration statement, as then in effect, includes an untrue statement of a material fact or omits to state any material
fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances under which they were
made, or, if in the opinion of counsel for Issuer, it is necessary to supplement or amend such prospectus to comply with law and, after such notice,
(b) at the request of any such Holder, except for periods (not to exceed 90 days per calendar year in the aggregate) described in Section 4 or
the time period for filing with the SEC information referred to in Section 3(a) hereof has not expired, promptly prepare and furnish to such Holders a supplement
or amendment to such prospectus, or otherwise update such prospectus through the filing of a Current Report on Form 8-K or otherwise, so that such prospectus
will not contain an untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein
not misleading;;
13.7 use its commercially reasonable best efforts to list or admit all Registrable Securities covered by such registration statement on any
securities exchange on which any of the Registrable Securities are then listed or any other trading market on which any of the Registrable Securities are
then admitted for trading;
13.8 pay all Registration Expenses relating to any such registration; and
13.9 promptly incorporate in a prospectus supplement or post-effective amendment to the Shelf Registration Statement such information as
may be necessary to effect the sale of Registrable Securities in an underwritten offering pursuant to Section 2(b) hereof; and make all required filings of
such prospectus supplement or post-effective amendment as soon as reasonably practicable after being notified of the matters to be incorporated in
such prospectus supplement or post-effective amendment.
Issuer may require each Holder of Registrable Securities as to which any registration is being effected to furnish Issuer with such information and undertakings
as it may reasonably request regarding such Holder and the distribution of such securities as Issuer may from time to time reasonably request in writing.
13.10 Each Holder of Registrable Securities agrees by acquisition of such Registrable Securities as follows:
(a) that upon receipt of any notice from Issuer of the happening of any event of the kind described in Section 3(f), such Holder will
forthwith discontinue such Holder’s disposition of Registrable Securities pursuant to the registration statement relating to such
6
Registrable Securities until such Holder’s receipt of the copies of the supplemented or amended prospectus contemplated by Section 3(f) and, if so directed by
Issuer, will deliver to Issuer all copies, other than permanent file copies, then in such Holder’s possession of the prospectus relating to such Registrable Securities
current at the time of receipt of such notice, and
(b) that it will immediately notify Issuer, at any time when a prospectus relating to the registration of such Registrable Securities is required
to be delivered under the Act, of the happening of any event as a result of which information previously furnished by such Holder to Issuer in writing for
inclusion in such prospectus contains an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make
the statements therein not misleading in the light of the circumstances under which they were made.
ARTICLE 14 Black-Out Periods for Holders. No Holder shall offer to sell or sell any shares of Registrable Securities pursuant to the Shelf Registration
Statement, and Issuer shall not be required to supplement or amend any Registration Statement or otherwise facilitate the sale of Registrable Securities pursuant
thereto, during the 90-day period (or such lesser number of days until Issuer makes its next required filing under the Exchange Act) immediately following the
receipt by each Holder of a certificate of an authorized officer of Issuer to the effect that the Board of Directors of Issuer has determined in good faith that such
offer, sale, supplement or amendment is likely to (1) interfere with or affect the negotiation or completion of any transaction that is being contemplated by Issuer
(whether or not a final decision has been made to undertake such transaction) at the time the right to delay is exercised, or (2) involve initial or continuing
disclosure obligations that might not be in the best interest of Issuer or its stockholders. Any period described in this Section 4 during which Holders are not able
to sell shares of Registrable Securities pursuant to the Shelf Registration Statement is herein referred to as a “black-out” period. Issuer shall notify each Holder of
the expiration or earlier termination of any “black-out” period (the nature and pendency of which need not be disclosed during such “black-out” period.)
ARTICLE 15 Underwritten Offerings.
15.1 Underwriting Agreement. If any Registrable Securities required to be registered pursuant to Section 2 are to be distributed by or
through one or more underwriters, the Holders of Registrable Securities to be distributed shall become parties to the underwriting agreement between
Issuer and such underwriters. Issuer will use its commercially reasonable best efforts to ensure that no underwriter shall require any Holder of
Registrable Securities to make any representations or warranties to or agreements with Issuer or the underwriters other than representations,
warranties or agreements regarding such Holder and such Holder’s intended method of distribution and any other representation required by law, and,
despite Issuer’s commercially reasonable best efforts, if an underwriter requires any Holder of Registrable Securities to make additional representation
or warranties to or agreements with such underwriter, such Holder may elect not to participate in such underwritten offering (but shall not have any
claims against Issuer as a result of such election).
7
15.2 Selection of Underwriters. The selection of the underwriter or underwriters for the public offering to be made pursuant to a
registration statement filed under Section 2 above shall be made by Issuer.
ARTICLE 16 Indemnification
16.1 Indemnification by Issuer. Issuer will, and hereby does, to the full extent permitted by law indemnify and hold harmless the
participating Holder of any Registrable Securities covered by any registration statement filed pursuant to Section 2, from and against any losses, claims,
damages or liabilities, joint or several (or actions or proceedings, whether commenced or threatened, in respect thereof, whether or not such Holder is a
party thereto, and including reasonable costs of investigation and legal expenses) (collectively, “Claims”), to which such Holder may become subject
under the Act or otherwise, insofar as such Claims arise out of or are based upon any untrue statement or alleged untrue statement of any material fact
contained in any registration statement under which such securities were registered under the Act, any preliminary prospectus, final prospectus or
summary prospectus contained therein, or any amendment or supplement thereto (if used during the period Issuer is required to keep the registration
statement current) or any documents incorporated therein (collectively, “Registration Documents”), or any omission or alleged omission to state therein a
material fact required to be stated therein or necessary to make the statements therein not misleading (in the case of a prospectus or preliminary
prospectus, in light of the circumstances in which they were made), or any violation by Issuer of the Act or any state securities law, or any rule or
regulation promulgated under the Act or any state securities law, or any other law applicable to Issuer relating to any such registration or qualification,
and Issuer will reimburse such Holder for any legal or any other expenses reasonably incurred by them in connection with investigating or defending
any such Claim; provided, however, that Issuer shall not be liable in any such case to the extent that any such Claim or expense arises out of or is based
upon an untrue statement or alleged untrue statement or omission or alleged omission made in any such Registration Document in reliance upon and in
conformity with written information furnished to Issuer for use in the preparation thereof; provided further, that Issuer shall not be liable to any
Holder to the extent that any Claim or expense arises out of the failure by such Holder to send or give a copy of the final prospectus to the Person
claiming an untrue statement or alleged untrue statement or omission or alleged omission at or prior to the written confirmation of the sale of
Registrable Securities to such Person if such statement or omission was corrected in such final prospectus. Such indemnity shall remain in full force and
effect regardless of any investigation made by or on behalf of such Holder and shall survive the transfer of such securities by such Holder.
16.2 Indemnification by the Holders. Issuer may require, as a condition to including any Registrable Securities in any registration statement
filed pursuant to Section 2, that Issuer shall have received an undertaking satisfactory to it from the prospective Holder of such securities, to indemnify
and hold harmless (in the same manner and to the same extent as set forth in this Section 6(b)) Issuer, each director of Issuer, each
8
officer of Issuer and each other person, if any, who controls Issuer within the meaning of either Section 15 of the Act or Section 20 of the Exchange Act
and each underwriter participating in any distribution being made pursuant to such registration statement, with respect to any statement or alleged
statement or omission or alleged omission from such Registration Document, if such statement or alleged statement or omission or alleged omission was
made in reliance upon and in conformity with written information furnished to Issuer through an instrument duly executed by such Holder specifically
stating that it is for use in the preparation of such Registration Document. Notwithstanding the foregoing, in no event shall any Holder be liable to
indemnify Issuer pursuant to this Section 6(b) in an amount in excess of the amount of the net proceeds of the Registrable Securities sold by him or her
in any such offering. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of Issuer of any such
director, officer or controlling person and shall survive the transfer of such securities by such Holder.
16.3 Notices of Claims, etc. Promptly after receipt by an indemnified party of notice of the commencement of any action or proceeding
involving a Claim referred to in the preceding subdivisions of this Section 6, such indemnified party will, if a claim in respect thereof is to be made
against an indemnifying party, give written notice to the latter of the commencement of such action; provided, however, that the failure of any
indemnified party to give notice as provided herein shall not relieve the indemnifying party of its obligations under the preceding subdivisions of this
Section 6, except to the extent that the indemnifying party is actually prejudiced by such failure to give notice. In case any such action is brought against
an indemnified party, unless in such indemnified party’s reasonable judgment a conflict of interest between such indemnified and indemnifying parties
may exist in respect of such claim, the indemnifying party shall be entitled to participate in and to assume the defense thereof, jointly with any other
indemnifying party similarly notified to the extent that it may wish, with counsel reasonably satisfactory to such indemnified party, and after notice
from the indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party shall not be liable to such
indemnified party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof other than reasonable costs
of investigation. No indemnifying party shall consent to entry of any judgment or enter into any settlement of any pending or threatened proceeding in
respect of which an indemnified party is or could have been a party and indemnity could have been sought under Section 6(a) without the consent of the
indemnified party which does not include as an unconditional term thereof the giving by the claimant or plaintiff to such indemnified party of a release
from all liability in respect to such claim or litigation.
16.4 Other Indemnification. Indemnification similar to that specified in the preceding subdivisions of this Section 6 (with appropriate
modifications) shall be given by Issuer and each Holder of Registrable Securities with respect to any required registration or other qualification of
securities under any Federal or state law or regulation of any governmental authority, other than the Act. If the indemnification provided for in Section
6(a), (b) or (c) is unavailable to an indemnified party or insufficient in respect of any Claims referred to therein, then each indemnifying party, in lieu of
indemnifying such indemnified party thereunder, shall contribute to the amount paid or payable by such indemnified party as a result of such Claims
(i) in such proportion as is appropriate to
9
reflect the relative benefits received by the indemnifying party or parties on the one hand and the indemnified party or parties on the other hand from
the offering of the securities or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate
to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the indemnified party or parties on the other hand in
connection with the statements or omissions that resulted in such Claims, as well as any other relevant equitable considerations; provided, however,
that in no event shall any Person be liable for contribution to the extent that any such Claim arises out of or is based upon an untrue statement or
omission made by such Person seeking contribution.
ARTICLE 17 Transfer of Assignment of Registration Rights. The benefits provided by this Agreement may be transferred or assigned by any Holder
to its partners, investors and affiliated entities in connection with the transfer of Registrable Securities to such partners, investors and affiliated entities, and such
transferees shall be deemed Holders hereunder; provided that (a) Issuer is given written notice prior to any said transfer or assignment, stating the name and
address of each such transferee and identifying the securities with respect to which such registration rights are being transferred or assigned, and (b) each such
transferee assumes in writing responsibility for its portion of the obligations of the Holders under this Agreement; and, provided further, that in the event a
transfer of Registrable Securities is completed without satisfaction of the assumption provisions contained herein, the transferring Holder shall be responsible for
any actions or obligations of such transferee until such assumption provisions are satisfied. Issuer agrees to take whatever action may be required to identify any
Holders which receive Registrable Securities in the Shelf Registration Statement or any prospectus supplement thereto as may be required by the SEC.
ARTICLE 18 Sales Pursuant to Rule 144. Each of the parties hereto acknowledges that the registration benefits provided in this Agreement will not
effect the ability of the Holders to sell Registrable Securities pursuant to Rule 144 rather than pursuant to the Shelf Registration Statement.
ARTICLE 19 Notices. All notices, requests, demands, claims and other communications hereunder shall be in writing. Any notice, request, demand,
claim, or other communication hereunder shall be deemed duly given (a) if personally delivered, when so delivered, (b) if mailed, two (2) business days after
having been sent by registered or certified mail, return receipt requested, postage prepaid and addressed to the intended recipient as set forth below, (c) if given
by telex or telecopier, once such notice or other communication is transmitted to the telex or telecopier number specified below and the appropriate answer back
or telephonic confirmation is received, provided that such notice or other communication is promptly thereafter mailed in accordance with the provisions of
clause (ii) above, or (d) if sent through an overnight delivery service in circumstances in which such service guarantees next day delivery, the day following
being so sent:
10
If to Issuer:
XTO Energy Inc.
810 Houston Street
Attention: Vice President, General Counsel &
Assistant Secretary
Facsimile: (817) 885-2278
If to Holders:
Attention:
Facsimile: (
)
-
In the event that any of the Holders identified in this Agreement transfers Registrable Securities to a new Holder in accordance with Section 7
above, Issuer may provide notice to such Holder through notifying the original Holder identified herein. Any party may give any notice, request, demand, claim
or other communication hereunder using any other means (including ordinary mail or electronic mail), but no such notice, request, demand, claim or other
communication shall be deemed to have been duly given unless and until it actually is received by the individual for whom it is intended. Any party may change
the address to which notices, requests, demands, claims and other communications hereunder are to be delivered by giving the other parties notice in the manner
herein set forth.
ARTICLE 20 Amendments; No Waivers.
20.1 Any provision of this Agreement may be amended or waived if, and only if, such amendment or waiver is in writing and signed, in the
case of an amendment, by all parties hereto, or in the case of a waiver, by the party against whom the waiver is to be effective.
20.2 No waiver by a party of any default, misrepresentation or breach of warranty or covenant hereunder, whether intentional or not, shall
be deemed to extend to any prior or subsequent default, misrepresentation or breach of warranty or covenant hereunder or affect in any way any rights
arising by virtue of any prior or subsequent occurrence. No failure or delay by a party in exercising any right, power or privilege hereunder shall
operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other
right, power or
11
privilege. The rights and remedies herein provided shall be cumulative and not exclusive of any rights or remedies provided by law.
ARTICLE 21 Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors
and permitted assigns, provided that no registration rights will be transferred other than in accordance with Section ARTICLE 17 hereof.
ARTICLE 22 Governing Law. This Agreement shall be construed in accordance with and governed by the internal laws (without reference to choice or
conflict of laws) of the State of Texas.
ARTICLE 23 Counterparts. This Agreement may be signed in any number of counterparts and the signatures delivered by telecopy, each of which shall
be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
ARTICLE 24 Entire Agreement. This Agreement constitutes the entire agreement between the parties with respect to the subject matter hereof and
supersedes all prior agreements, understandings and negotiations, both written and oral, between the parties with respect to the subject matter of this Agreement.
Neither this Agreement nor any provision hereof is intended to confer upon any Person other than the parties hereto any rights or remedies hereunder.
ARTICLE 25 Captions. The captions herein are included for convenience of reference only and shall be ignored in the construction or interpretation
hereof. All references to an Article or Section include all subparts thereof.
ARTICLE 26 Severability. If any provision of this Agreement, or the application thereof to any Person, place or circumstance, shall be held by a court of
competent jurisdiction to be invalid, unenforceable or void, the remainder of this Agreement and such provisions as applied to other Persons, places and
circumstances shall remain in full force and effect only if, after excluding the portion deemed to be unenforceable, the remaining terms shall provide for the
consummation of the transactions contemplated hereby in substantially the same manner as originally set forth at the later of the date this Agreement was
executed or last amended.
ARTICLE 27 Third Party Beneficiaries. No provision of this Agreement shall create any third party beneficiary rights in any Person.
12
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year
first above written.
ISSUER:
XTO ENERGY INC., a Delaware corporation
By:
Name:
Title:
HOLDERS:
By:
Name:
Title:
SIGNATURE PAGE
TO
REGISTRATION RIGHTS AGREEMENT
ANNEX A
PLAN OF DISTRIBUTION
The common shares are being registered to permit public secondary trading of these securities by the holders thereof from time to time after the date of this
prospectus and to facilitate the continued orderly disposition of our common shares held by the selling stockholders identified herein. We will not receive any of
the proceeds from the sale of the common shares by the selling stockholders.
The selling stockholders and their successors-in-interest who acquire their shares after the date of this prospectus and are entitled to the benefits of this
registration statement, may sell the common shares directly to purchasers or through underwriters, broker-dealers or agents. If underwriters are used in a firm
commitment underwriting, we and the selling stockholders will execute an underwriting agreement with those underwriters relating to the common shares that
the selling stockholders will offer. Unless otherwise set forth in a prospectus supplement, the obligations of the underwriters to purchase these common shares
will be subject to conditions. The underwriters, if any, will purchase the common shares on a firm commitment basis and will be obligated to purchase all of
these common shares. The common shares subject to the underwriting agreement will be acquired by the underwriters for their own account and may be resold
by them from time to time in one or more transactions, including negotiated transactions, at a fixed public offering price or at varying prices determined at the
time of sale.
Underwriters may be deemed to have received compensation from us in the form of underwriting discounts or commissions and may also receive
commissions from the purchasers of these common shares for whom they may act as agent. Underwriters may sell these common shares to or through dealers.
These dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers
for whom they may act as agent. Any public offering price and any discounts or concessions allowed or reallowed or paid to dealers may be changed from time
to time.
The selling stockholders may authorize underwriters to solicit offers by institutions to purchase the common shares subject to the underwriting agreement
from the selling stockholders at the public offering price stated in a prospectus supplement pursuant to delayed delivery contracts providing for payment and
delivery on a specified date in the future. If the selling stockholders sell common shares pursuant to these delayed delivery contracts, the prospectus supplement
will state that as well as the conditions to which these delayed delivery contracts will be subject and the commissions payable for that solicitation.
The applicable prospectus supplement will set forth whether or not underwriters may over-allot or effect transactions that stabilize, maintain or otherwise
affect the market price of the common shares at levels above those that might otherwise prevail in the open market, including, for example, by entering
stabilizing bids, effecting syndicate covering transactions or imposing penalty bids. Underwriters are not required to engage in any of these activities, or to
continue such activities if commenced.
1
If dealers are utilized in the sale of common shares, the selling stockholders will sell such common shares to the dealers as principals. The dealers may
then resell such common shares to the public at varying prices to be determined by such dealers at the time of resale. The names of the dealers and the terms of
the transaction will be set forth in a prospectus supplement, if required. The selling stockholders may also sell common shares through agents designated by them
from time to time.
We will name any agent involved in the offer or sale of the common shares and will list commissions payable by the selling stockholders to these agents in
a prospectus supplement, if such a supplement is required. These agents will be acting on a best efforts basis to solicit purchases for the period of its appointment,
unless we state otherwise in any required prospectus supplement. The selling stockholders may sell any of the common shares directly to purchasers. In this case,
the selling stockholders may not engage underwriters or agents in the offer and sale of these common shares. We and the selling stockholders may indemnify
underwriters, dealers or agents who participate in the distribution of securities against certain liabilities, including liabilities under the Securities Act and agree to
contribute to payments which these underwriters, dealers or agents may be required to make.
The common shares may be sold in one or more transactions at fixed prices, at prevailing market prices at the time of sale, at varying prices determined at
the time of sale, or at negotiated prices. Sales may be effected in transactions, which may involve block transactions or crosses:
•
on any national securities exchange or quotation service on which the common shares may be listed or quoted at the time of sale;
•
in the over-the-counter market;
•
in transactions otherwise than on exchanges or quotation services or in the over-the-counter market;
•
through the exercise of purchased or written options; or
•
through any other method permitted under applicable law.
In connection with sales of the common shares or otherwise, the selling stockholders may enter into hedging transactions with broker-dealers, which may
in turn engage in short sales of the common shares in the course of hedging the positions they assume. The selling stockholders may also sell short the common
shares and deliver the common shares to close out short positions, or loan or pledge the common shares to broker-dealers that in turn may sell the common
shares. The aggregate proceeds to the selling stockholders from the sale of the common shares offered by the selling stockholders hereby will be the purchase
price of the common shares less discounts and commissions, if any.
The selling stockholders reserve the right to accept and, together with their agents from time to time, to reject, in whole or in part, any proposed purchase
of common shares to be made directly or through agents. In order to comply with the securities laws of some states, if applicable, the common shares may be sold
in these jurisdictions only through registered or
2
licensed brokers or dealer. In addition, in some states the common shares may not be sold unless they have been registered or qualified for sale or an exemption
from registration or qualification requirements is available and is complied with. The selling stockholders and any underwriters, broker-dealers or agents that
participate in the sale of the common shares may be “underwriters” within the meaning of Section 2(11) of the Securities Act. Any discounts, commissions,
concessions or profit they earn on any resale of the common shares may be underwriting discounts and commissions under the Securities Act. Any selling
stockholder who is an “underwriter” within the meaning of Section 2(11) of the Securities Act will be subject to the prospectus delivery requirements of the
Securities Act. The selling stockholders have acknowledged their obligations to comply with the provisions of the Exchange Act and the rules thereunder relating
to stock manipulation, particularly Regulation M.
We are not aware of any plans, arrangements or understandings between any of the selling stockholders and any underwriter, broker-dealer or agent
regarding the sale of the common shares by the selling stockholders. We do not assure you that the selling stockholders will sell any or all of the common shares
offered by them pursuant to this prospectus. In addition, we do not assure you that the selling stockholders will not transfer, devise or gift the common shares by
other means not described in this prospectus. Moreover, any securities covered by this prospectus that qualify for sale pursuant to Rule 144 of the Securities Act
may be sold under Rule 144 rather than pursuant to this prospectus.
3
EXHIBIT 2.3
AMENDMENT NO. 1
TO
This Amendment No. 1 (the “Amendment”) to Agreement and Plan of Merger (the “Merger Agreement”) dated January 9, 2005, by and among Antero
Resources Corporation, a Delaware corporation (the “Company”), XTO Energy Inc., a Delaware Corporation (“Parent”), and XTO Barnett Inc., a Delaware
corporation and wholly owned subsidiary of Parent (“Merger Subsidiary”), is entered into as of February 3, 2005. Capitalized terms used in this Amendment
and not otherwise defined have the meanings given them in the Merger Agreement.
Recitals:
WHEREAS, the Company, Parent and Merger Subsidiary are parties to the Merger Agreement pursuant to which Merger Subsidiary will be merged with
and into the Company (the “Merger”) with the Company continuing as the surviving corporation and wholly owned subsidiary of Parent;
WHEREAS, Parent desires to acquire the Pipeline Assets in connection with the Merger for a deemed Pipeline Assets Sale Price of $175,000,000; and
WHEREAS, the Company, Parent and Merger Subsidiary each desire to agree upon the acquisition of the Pipeline Assets by Parent and amend the Merger
Agreement accordingly as set forth below.
Agreement:
NOW THEREFORE, in consideration of the premises and for good and valuable consideration, the adequacy, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
ARTICLE I
PURCHASE OF PIPELINE ASSETS
1.1 Acquisition of Pipeline Assets.
(a) Antero Resources Pipeline, LP shall continue to own the Pipeline Assets and shall remain a Subsidiary of the Company through the Closing of
the Merger, and the Pipeline Assets shall not otherwise be disposed of by the Company or its Subsidiaries. For the purposes of the Merger Agreement, Parent
shall be deemed to have purchased the Pipeline Assets for a Pipeline Assets Sale Price of $175,000,000 (the “Deemed Pipeline Assets Sale Price”) by
consummating the Merger.
1
(b) The Deemed Pipeline Assets Sale Price shall not cause any increase or decrease in the Cash Merger Consideration pursuant to Section 2.10(b)(ii)
and (iii) of the Merger Agreement.
(c) The agreement set forth in this Section 1.1 shall satisfy in all respects (i) the covenants of the Company set forth in Section 4.7 of the Merger
Agreement and (ii) the condition to the obligations of the Company set forth in Section 7.3(c) of the Merger Agreement.
(d) The Company shall have no obligation to use any portion of the Deemed Pipeline Assets Sale Price to repay outstanding Debt.
(e) In accordance with Section 5.5 of the Merger Agreement, Section 3.1(w)(iii) of the Merger Agreement shall be amended by substituting the
words “Gathering Assets (including the Pipeline Assets) and Other Pipeline Assets” in each instance where the words “Other Pipeline Assets” presently appear.
1.2 Transition Services Agreement. The Transition Services Agreement to be executed at Closing between Parent and Antero II in accordance with
Sections 7.2(c) and 7.3(f) of the Merger Agreement, shall also provide for the transition and operation of the Pipeline Assets.
ARTICLE II
GENERAL
2.1 Entire Agreement. Except as expressly modified hereby, the Merger Agreement shall remain in full force and effect as originally executed without
amendment or modification. The Merger Agreement (which term shall be deemed to include the exhibits and schedules hereto and the other certificates,
documents and instruments delivered hereunder) as modified by this Amendment, the other Transaction Documents and the Confidentiality Agreement constitute
the entire agreement of the parties hereto and supersede all prior agreements, letters of intent and understandings, both written and oral, among the parties with
respect to the subject matter of the Merger Agreement as modified by this Amendment, the other Transaction Documents and the Confidentiality Agreement.
There are no representations or warranties, agreements or covenants other than those expressly set forth in the Merger Agreement as modified by this
Amendment, the other Transaction Documents and the Confidentiality Agreement.
2.2 Counterparts. This Amendment may be executed in any number of counterparts, each of which shall be considered an original for all purposes, and
all of which when taken together shall constitute a single counterpart.
2
IN WITNESS WHEREOF, the parties have executed this Amendment as of the date first written above.
THE COMPANY:
By:
/s/ GLEN C. WARREN, JR.
Name: Glen C. Warren, Jr.
Title: President, Chief Financial Officer and
Secretary
PARENT:
XTO ENERGY INC.
By:
/s/ VAUGHN O. VENNERBERG II
Title: Executive Vice President - Administration
MERGER SUBSIDIARY:
XTO BARNETT INC.
By:
/s/ VAUGHN O. VENNERBERG II
Title: President
SIGNATURE PAGE
TO
AMENDMENT NO. 1 TO
AGREEMENT
AND PLAN
OF MERGER
EXHIBIT 12.1
XTO ENERGY INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
2004
2003
2002
2001
2000
(in thousands, except ratios)
Income before income tax, minority interest and cumulative effect of accounting change
Interest expense
Interest portion of rentals
$ 825,620 $ 444,510 $ 286,749 $ 455,357 $ 176,432
94,063
64,321
54,391
56,317
81,759
7,134
8,908
2,575
3,919
5,776
Earnings before provision for taxes and fixed charges
$ 926,817 $ 517,739 $ 343,715 $ 515,593 $ 263,967
Interest expense
Capitalized interest
Interest portion of rentals
Preferred stock dividends
$ 94,063 $ 64,321 $ 54,391 $ 56,317 $ 81,759
2,635
2,240
4,330
6,649
3,488
7,134
8,908
2,575
3,919
5,776
—
—
—
—
1,758
Total Fixed Charges
$ 103,832 $ 75,469 $ 61,296 $ 66,885 $ 92,781
Ratio of Earnings to Fixed Charges
8.9
6.9
5.6
7.7
2.8
EXHIBIT 21.1
SUBSIDIARIES OF XTO ENERGY INC.
Jurisdiction of
Incorporation
Cross Timbers Energy Services, Inc.
Cross Timbers Trading Company
Ringwood Gathering Company
Timberland Gathering & Processing Company, Inc.
XTO Barnett Inc.
WTW Properties, Inc.
Texas
Texas
Delaware
Texas
Delaware
Texas
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
XTO Energy Inc.
Fort Worth, Texas:
We consent to the incorporation by reference in the registration statements (No. 333-122767) on Form S-3, (No. 333-121195) on Form S-4, and (Nos.
333-68775, 333-69977, 333-37668, 333-81849, 333-91460, 333-120540 and 333-55784) on Form S-8 of XTO Energy Inc. of our reports dated March 7, 2005,
with respect to the consolidated balance sheets of XTO Energy Inc. as of December 31, 2004 and 2003, and the related consolidated income statements,
statements of cash flows and statements of stockholders’ equity for each of the years in the three-year period ended December 31, 2004, and all related financial
statement schedules, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004 and the effectiveness of
internal control over financial reporting as of December 31, 2004, which reports appear in the December 31, 2004 annual report on Form 10-K of XTO Energy
Inc.
KPMG LLP
Dallas, Texas
March 7, 2005
EXHIBIT 23.3
[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]
March 7, 2005
XTO Energy Inc.
810 Houston Street
Fort Worth, TX 76102
Re: XTO Energy Inc.
2004 Annual Report on Form 10-K
Gentlemen:
The firm of Miller and Lents, Ltd., consents to the use of its name and to the use of its report dated February 21, 2005, regarding the XTO Energy Inc.
Proved Reserves and Future Net Revenues as of December 31, 2004, in the 2004 Annual Report on Form 10-K.
Miller and Lents, Ltd., has no interests in XTO Energy Inc. or in any affiliated companies or subsidiaries and is not to receive any such interest as payment
for such reports and has no director, officer, or employee otherwise connected with XTO Energy Inc. We are not employed by XTO Energy Inc. on a contingent
basis.
Yours very truly,
MILLER AND LENTS, LTD.
By
/s/
JAMES PEARSON
James Pearson
Chairman
EXHIBIT 31.1
CERTIFICATIONS
I, Bob R. Simpson, Chief Executive Officer of XTO Energy Inc., certify that:
1.
I have reviewed this report on Form 10-K of XTO Energy Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:
5.
a)
Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls
over financial reporting.
Date: March 7, 2005
/S/
BOB R. SIMPSON
Bob R. Simpson
Chief Executive Officer
EXHIBIT 31.2
CERTIFICATIONS
I, Louis G. Baldwin, Chief Financial Officer of XTO Energy Inc., certify that:
1.
I have reviewed this annual report on Form 10-K of XTO Energy Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:
5.
a)
Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls
over financial reporting.
Date: March 7, 2005
/S/
LOUIS G. BALDWIN
Louis G. Baldwin
Chief Financial Officer
EXHIBIT 32.1
Certification of Chief Executive Officer and Chief Financial Officer of XTO Energy Inc.
(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
In connection with the Annual Report of XTO Energy Inc. (the “Company”) on Form 10-K for the period ending December 31, 2004 as filed with the Securities
and Exchange Commission on the date hereof (the “Report”), Bob R. Simpson, Chief Executive Officer of the Company, and Louis G. Baldwin, Chief Financial
Officer of the Company, each hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/S/ BOB R. SIMPSON
Bob R. Simpson
Chief Executive Officer
March 7, 2005
/S/ LOUIS G. BALDWIN
Louis G. Baldwin
Chief Financial Officer
March 7, 2005
_______________________________________________
Created by 10KWizard www.10KWizard.com

FORM 10-K - StockProInfo

Transcription

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