August 2016 Update - Southwestern Energy

August 2016 Update
A Strong Bridge Forward
NYSE: SWN
Southwestern Energy Company
General Information
Southwestern Energy Company is a leading natural gas and oil company with operations
predominantly in the United States, engaged in exploration, development and production
activities, including related natural gas gathering and marketing.
Investor Contacts
Craig Owen
Bill Way
Michael Hancock
Senior Vice President & Chief Financial Officer
Phone: (832) 796-2808
Fax: (832) 796-4820
craig_owen@swn.com
President & Chief Executive Officer
Phone: (832) 796-4791
Fax: (832) 796-4820
Director, Investor Relations
Phone: (832) 796-7367
Fax: (832) 796-4820
michael_hancock@swn.com
1
Forward-Looking Statements
This presentation includes forward-looking statements. Forward-looking statements relate to future events and anticipated results of operations,
business strategies, and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by
terminology such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,”
“guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words. Statements may be
forward looking even in the absence of these particular words. Where, in any forward-looking statement, the company expresses an expectation
or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can
be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of
risks and other matters including, but not limited to, changes in commodity prices; changes in expected levels of natural gas and oil reserves or
production; operating hazards, drilling risks, unsuccessful exploratory activities; limited access to capital or significantly higher cost of capital
related to illiquidity or uncertainty in the domestic or international financial markets; international monetary conditions; unexpected cost
increases; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or
future litigation; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other
laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking
statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings
with the Securities and Exchange Commission. Unless legally required, Southwestern Energy Company undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Cautionary Note to U.S. Investors –The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and
possible reserves. We use the term "resource" in this presentation that the SEC’s guidelines prohibit us from including in filings with the
SEC. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC.
Copies are available from the SEC and from the SWN website.
This presentation contains non-GAAP financial measures, such as adjusted net income, adjusted EBITDA and net cash flow, including certain
key statistics and estimates. Please see the Appendix for definitions and reconciliations of the non-GAAP financial measures that are based on
reconcilable historical information.
The contents of this presentation are current as of August 1, 2016.
2
Delivering on Commitments
Strong
Liquidity
Position
Strengthened
Balance Sheet
Driving
Margins
Higher
•
Credit facility / term loan maturity extended to 2020
•
Over $1.9 billion liquidity available until December 2020
•
Net cash flow(1) exceeded capital investments for the first six months of 2016
•
Significantly improved credit metrics resulting from financial strengthening efforts
•
Reduced or extended debt due prior to 2020 by approximately $1.8 billion
(approximately $1.2 billion repaid and approximately $600 million extended)
•
Signed agreement to divest West Virginia acreage for approximately $450 million,
subject to customary closing conditions
•
Aggressive attack on cost structure has resulted in significant savings
•
Executed production enhancement initiatives yielding positive results
•
Achieved all-in cash operating costs(2) of $1.23/Mcfe in the first six months of 2016
(1)
Net cash flow is operating cash flow before changes in operating assets and liabilities and one-time severance payments. Net cash flow is a non-GAAP financial measures. See
explanation and reconciliation on page 33.
(2)
Cash operating costs for 2016 include lease operating expenses ($0.88/Mcfe), general and administrative expenses ($0.20/Mcfe), taxes other than income taxes ($0.09/Mcfe) and net interest
expense ($0.06/Mcfe).
3
SWN Creating Enduring Value
Premiere,
Diversified
Natural Gas
Asset
Disciplined
Capital
Allocation &
Investment
Practices
Safety and
Environmental
•
Large, core position in both of the highest quality Appalachian areas
•
Vast upstream and midstream assets in Fayetteville generating substantial cash flow
•
High degree of operational control and flexibility
•
Threshold criterion: projected return must be at least $1.30 for each $1.00
invested at current prices (defined as 1.3 PVI)
Projects chosen based primarily on ranking of projected return
•
•
Health, Safety & Environmental metrics improved for 4th year in a row for SWN
and its contractors
•
Company on track to achieve fresh water neutral status by watershed by the end
of 2016
Active methane emissions abatement programs
•
Strategy built on the Formula – The Right People doing the Right Things, wisely investing the cash
flow from the underlying Assets will create Value+
4
Strengthening our Balance Sheet
Execution of a 3-part plan to enhance capital structure
Add Duration & Preserve
Operational Flexibility
1•
Amend and extend
bank facilities
Reduce Leverage & Improve Liquidity
2•
Monetize non-core assets
3•
Equity offering
–
Maturities extended
from 2018 to 2020
–
Maintain producing
assets and acreage
with highest strategic
value
–
$750 million utilized for
debt reduction
–
No reduction to
credit facility
commitments
–
Actively pursuing
asset dispositions
–
$500 million earmarked
for increased drilling and
completion activity
5
Pro-forma Model
Cash Balance and Debt Maturities
2,500
Before recent
transactions
$MMs
2,000
1,500
1,000
As of April 1, 2016
500
0
Cash
16
Bonds
17
18
Revolver ‐ Drawn
19
20
21
22
Unsecured Term Loan
23
24
25
Revolver ‐ Capacity
2,500
2,000
As of June 30, 2016
1,500
• Approximately $1.2 billion
deleveraging and significant
improvement to near-term
maturity profile
$MMs
Pro-forma for
recent transactions(4)
1,000
500
• Significant cash balance
anchors liquidity position
0
Cash
16
(1)
Bonds
(1)
(2)
(3)
(4)
17
18
Revolver ‐ Drawn
19
20
21
22
(2)
Unsecured Term Loan
23
24
Revolver ‐ Capacity
25
(3)
2018 bond maturities paid down using proceeds from equity offering.
Unsecured term loan balance expected to be reduced to ~$300 million upon anticipated closing of announced WV acreage sale.
Revolver capacities excludes impact of letters of credit ($169 million outstanding at June 30, 2016).
Includes transactions referenced on slides 3 and 5.
6
Focus on Premier Quality Assets
Reserves & Production
2015 Reserves – 6,215 Bcfe
2015 Production – 976 Bcfe
2016 Estimated production – 865 - 875 Bcfe
PA
Northeast Appalachia
2015 Reserves – 2,319 Bcf (37%)
2015 Production – 360 Bcf (37%)
Net acres – 270,335 (12/31/15)
WV
Southwest Appalachia
2015 Reserves – 611 Bcfe (10%)
2015 Production – 143 Bcfe (15%)
Net acres – 425,098 (12/31/15)(1)
Fayetteville Shale
2015 Reserves – 3,281 Bcf (53%)
2015 Production – 465 Bcf (48%)
Net acres – 957,641 (12/31/15)(2)
(1)
(2)
Includes acreage from pending West Virginia asset
sale.
Includes 202,156 net acres that have previously been
reported as a component of our divested conventional
Arkoma acreage.
AR
Forward-Looking Statement
7
High Quality and Flexible Portfolio
Total Resource by Area for Various
Assumed Gas Prices
70
60
Tcfe
50
40
30
20
57%
Expected
2016
Production
Split
43%
10
0
$3.00
$3.50
$4.00
Fayetteville
>$4.00
Appalachia
Gross Drilling Locations Remaining for
Various Assumed Gas Prices
$3.00
$3.50
$4.00
>$4.00
Appalachia
Fayetteville
Fayetteville
500
2,100
2,100
4,300
NE Appalachia
400
550
600
650
SW Appalachia
1,750
2,300
4,350
4,750
SWN Total
2,650
4,950
7,050
9,700
Forward-Looking Statement
8
Southwest Appalachia
Gas in Place Map
SWN acreage shown in yellow
Bcf/Section
50 Bcf
100 Bcf
150 Bcf
200 Bcf
250 Bcf
300 Bcf
• Core Position in Premier Play
(1)
–
370,000 net acres with stacked pays from
the Marcellus, Utica and Devonian(1)
–
Gross operated production of 636 MMcfe/d
(394 MMcfe/d net) as of June 30, 2016(1)
–
315 producing operated horizontal wells as
of December 31, 2015(1)
–
Total well costs among best in industry
–
Created additional value from 40%
improved well performance
•
Geosteered in zone 94% of time (formerly 46% to 74%)
•
Tighter stage spacing and increased proppant pounds per
foot to 2,000 lbs (48% increase)
•
Managed reservoir drawdown increasing condensate
recovery over 10%
Acreage, production and well counts adjusted for pending West Virginia acreage
sale.
9
Well-Positioned in Rapidly Developing Play
Acreage is low-risk opportunity in the
heart of world-class play
1
ID
2
1
3
10
9
3
6
7
9
4
8
5
10
7
6
Well Name
Lateral
Length
(feet)
IP
(Mmcfed/
1000’ Lateral)
% Liquids
MARCELLUS
2
4
5
Operator
8
1
2
SWN
SWN
5,141
7,723
2.0
1.2
70%
65%
3
4
SWN
EQT
5,142
3,153
2.7
2.3
40%
0%
5
6
NBL
AR
8,741
9,426
1.2
2.2
19%
20%
7
8
AR
CNX
11,753
7,949
1.8
0.9
26%
0%
9
10
SWN
SWN
Alice Edge 206H
3,972
7,305
2.0
1.3
41%
65%
1
CNX
Gaut 4IH
5,840
10.4
UTICA
0%
2
3
RRC
RICE
Sportsman’s Club 11H
Bigfoot 9H
5,420
6,957
10.9
6.0
0%
0%
4
5
EQT
CVX
Scotts Run 591340
Conner 6H
3,221
6,451
22.6
3.9
0%
0%
6
7
GST
SGY
Blake U-7H
Pribble 6H
6,617
3,605
5.6
8.3
0%
0%
8
9
MHR
CNX
S. Winland 1300U
GH 9
5,289
6,141
8.8
10.1
0%
0%
10
AR
Rymer 4HD
6,620
3.0
0%
Rayle Coal 1H
Robert Shorts 5H
Gladys Briggs 8H
Haught 512716
SHR1 Pad (6 wells)
Carr Unit 2H
Hornet Unit 1H
PHL13 Pad (6 wells)
Ridgetop Land Ventures 201H
Marcellus
Utica
Source: Public data and company presentations
10
Northeast Appalachia
SWN Acreage
•
270,000 net acres and 423 producing operated horizontal wells in Northeast Appalachia
as of December 31, 2015
•
Proved reserves of 2.3 Tcf as of December 31, 2015 with a 3-Year F&D of $0.42/Mcf(1)
•
Gross operated production of 1,157 MMcf/d (958 MMcf/d net) as of June 30, 2016
•
Low cost integrated firm transportation portfolio with industry leading delivery point,
volume and term optionality
•
We plan to drill approximately 37 to 40 wells and complete approximately 35 to 38 wells
in the second half of 2016
(1) Excludes price revisions, acquisitions and the impact of capitalizing interest and portions of G&A in accordance with full cost accounting ($/Mcf).
11
Fayetteville
SWN Acreage
•
958,000 net acres and 3,724 producing operated horizontal wells as of December 31, 2015
•
Proved reserves of 3.3 Tcf as of December 31, 2015 with a 3-Year F&D of $0.74/Mcf(1)
•
Gross operated production was 1,546 MMcf/d (1,005 MMcf/d net) as of June 30, 2016
•
Extensive high quality cash flow generating asset with large production base, low operating
costs and access to premium gas markets
•
We plan to drill approximately 7 to 10 wells and complete approximately 36 to 39 wells in
the second half of 2016
(1) Excludes price revisions, acquisitions and the impact of capitalizing interest and portions of G&A in accordance with full cost accounting ($/Mcf).
12
2016 Capital Investments
$MM
• Fully-funded capital program of
low-risk drilling and completion
opportunities
$1,043MM
$1,200
$1,000
$750MM(2)
$800
$25
$668(2)
• Dynamic portfolio allowing
flexibility to align activity with
price movements
$245
$600
$5
$80
$400
$175
$375(1)
$200
$220
$0
Equity Offering
(1)
(2)
(3)
Funding
(1)
2016 Well Count Summary
NE App SW App
Fay
7-10
Total
Drill
37-40
11-15
Complete
41-44
20-24
39-42 100-110
Wells to Sales
38-42
30-33
52-55 120-130
Ending DUC
31-35
22-25
2-5
55-65
55-65
Capital Investments
Net Cash Flow
(3)
SW Appalachia
Fayetteville
Capitalized Interest & Expense
E&P Services & Corporate
NE Appalachia
Midstream
$500MM of proceeds from July 2016 equity offering earmarked to accelerate drilling and completion activity, with approximately $375MM expected to be invested in 2016.
Assumes midpoint of guidance issued in July 2016.
Net cash flow is net cash flow before changes in operating assets and liabilities and one-time cash severance payments. It also excludes current taxes associated with any future
asset sales. Net cash flow is a non-GAAP financial measure. See explanation and reconciliation on page 33.
Forward-Looking Statement
13
Northeast Appalachia Takeaway
1.6
1.4
1.2
Transport Renewal Options
Bcf/d
1.0
0.8
Constitution
0.6
0.4
(project not in service)
Firm Transportation Capacity
0.2
0.0
Firm Sales
Sales Locations
Year
SWN Firm Reservation
Total Firm
Annual
Firm Sales Rate per
Transport
Rate per
Takeaway WAVG Rate
(MMbtu/d) MMbtu
(MMbtu/d)
MMbtu
(MMbtu/d) per MMbtu
2016
1,235,000
$0.31
65,000
$0.00
1,300,000
$0.29
M3
2017
1,191,000
$0.28
40,000
$0.00
1,231,000
$0.27
Dominion
2018
1,230,000
$0.31
35,000
$0.00
1,265,000
$0.30
2019
1,314,000
$0.34
35,000
$0.00
1,349,000
$0.33
120%
100%
80%
10%
34%
5%
7%
34%
32%
5%
28%
60%
40%
40%
49%
49%
46%
Other
20%
0%
Gulf
16%
12%
12%
21%
2016
2017
2018
2019
Forward-Looking Statement
•
•
•
•
No transportation fees associated with Firm Sales.
Assumes Constitution in service in late 2018.
Ability to release capacity or buy third party production to fill excess transportation capacity.
Sales location percentages are based on fully utilized transportation and firm sales volumes.
14
Southwest Appalachia Takeaway
0.90
0.80
0.70
Bcf/d
0.60
Columbia Gas Transmission MXP (project not in service)
0.50
0.40
0.30
ET Rover (project not in service)
0.20
0.10
Firm Transportation Capacity
Firm Sales
0.00
Sales Locations
Year
120%
100%
80%
60%
20%
20%
12%
6%
25%
46%
6%
34%
M2
42%
Total Firm
Annual
Takeaway WAVG Rate
(MMbtu/d) per MMbtu
2016
80,000
$0.20
159,000
$0.00
239,000
$0.07
2017
96,000
$0.23
150,000
$0.00
246,000
$0.09
2018
362,000
$0.64
73,000
$0.00
435,000
$0.53
2019
779,000
$0.61
47,000
$0.00
826,000
$0.57
TCO
40%
20%
Nymex
SWN Firm Reservation
Firm Sales Rate per
Transport
Rate per
(MMbtu/d) MMbtu
(MMbtu/d)
MMbtu
34%
34%
57%
60%
4%
0%
2016
2017
2018
Forward-Looking Statement
2019
Gulf
•
•
•
•
No transportation fees associated with Firm Sales.
Assumes SWN Rover and Columbia Capacity in service in late 2017 and late 2018, respectively.
Ability to release capacity or buy third party production to fill any excess transportation capacity.
Sales location percentages are based on fully utilized transportation and firm sales volumes.
15
Fayetteville Takeaway
2.5
2.0
1.5
1.0
Firm Transportation Capacity
0.5
0.0
Sales Locations
120%
Year
SWN Firm Reservation
Firm Sales Rate per
Transport
Rate per
(MMbtu/d) MMbtu
(MMbtu/d)
MMbtu
Total Firm
Annual
Transport WAVG Rate
(MMbtu/d) per MMbtu
2016
2,000,000
$0.26
0
$0.00
2,000,000
$0.26
2017
2,000,000
$0.26
0
$0.00
2,000,000
$0.26
2018
2,000,000
$0.26
0
$0.00
2,000,000
$0.26
2019
1,625,000
$0.26
0
$0.00
1,625,000
$0.26
100%
100%
100%
100%
100%
80%
60%
Gulf Coast
40%
20%
0%
2016
2017
2018
2019
•
Sales location percentages are based on fully utilized transportation and firm sales volumes.
Forward-Looking Statement
16
Improving Basis Differentials
Basis Locations
3.00
2.50
Estimated Weighted Average Sales Differential
(excluding transportation)
2016
2017
2018
2.00
1.50
2019
1.00
Fayetteville
($0.07)
($0.07)
($0.07)
($0.05)
0.50
Northeast
Appalachia
($0.53)
($0.45)
($0.32)
($0.20)
Southwest
Appalachia
($0.58)
($0.56)
($0.24)
($0.18)
0.00
(0.50)
(1.00)
(1.50)
*Basis information shown above is based on market quotes as of June 2016.
Forward-Looking Statement
17
Hedging
90
80
Volumes Hedged, Bcf
70
Full Year 2016
% Hedged
19%
Volumes
149 Bcf
Average Floor Price
$2.52
Full Year 2017
Volumes
228 Bcf
Average Floor Price
$3.01
Swaps
2 way Collars
Puts
Total
91 Bcf
15 Bcf
43 Bcf
149 Bcf
Swaps
2 way Collars
3 way Collars
Total
163 Bcf
47 Bcf
18 Bcf
228 Bcf
56
57
57
58
$2.25 x $2.75 x
$3.56
$2.25 x $2.75 x
$3.56
$2.25 x $2.75 x
$3.56
$2.25 x $2.75 x
$3.56
$2.90 x $3.33
$2.90 x $3.33
$2.90 x $3.33
$2.90 x $3.33
$3.07
$3.07
$3.07
$3.07
Q1 17
Q2 17
Q3 17
Q4 17
60
52
50
50
41
40
$2.47
$2.81 x $3.38
$2.56
30
20
$2.59
$2.35
10
5
$2.34
$2.60
$2.34
Q1 16
Q2 16
Q3 16
Puts
Swaps
Q4 16
2 Way Costless Collars
3 Way Costless Collars
• Targeting hedges on over 50% of production in 2017 utilizing a combination of swaps and
options, providing cash flow protection while retaining exposure to improved commodity prices.
Forward-Looking Statement
18
Our Path Forward
2015 Actual
2016 Original Guidance
2016 Revised Guidance
$2.66 Gas
$48.80 Oil
$2.35 Gas
$35.00 Oil
$2.45 Gas
$45.00 Oil
976
815 ‐ 835 865 ‐ 875
$71MM
$(180) ‐ $(160)MM
$(10) ‐ $10MM
Adj. EBITDA(2)(5)
$1,440MM
$450 ‐ $500MM
$675 ‐ $700MM
Net Cash Flow
$1,468MM
$450 ‐ $500MM
$655 ‐ $680MM
CapEx(4)
$1,828MM
$360 ‐ $400MM
$725 ‐ $775MM
Production (Bcfe)
Adj. Net Income (Loss) Attr to Common Stock(2)
(1)
(2)
(3)
(4)
(5)
Includes amounts associated with assets divested in 2015.
Adjusted net income (loss) and adjusted EBITDA are non-GAAP financial measures. See explanation and reconciliation on pages 34 and 35.
Net cash flow is net cash flow before changes in operating assets and liabilities and one-time cash severance payments. It also excludes current taxes associated with any
future asset sales. Net cash flow is a non-GAAP financial measure. See explanation and reconciliation on page 33.
Excludes acquisition capital for transactions announced in 4Q 2014.
Forward-Looking Statement
The impact of preferred dividends is excluded from adjusted EBITDA and net cash flow.
19
Driving Performance
• Strong liquidity
• Strengthened balance sheet
• Expanded margins
• Capital discipline
20
Appendix
21
Credit Facility/Term Loan Amendments
Enhance Financial Flexibility
Post-Amendment vs. Previous
Amendment
Post-Amendment
Previous
~$800MM Unsecured Revolvers(1)
~$1.2B Secured Term Loan
$2.0B Unsecured Revolver
Maturity Date
December 2020
December 2018
Borrowing Rates
Libor + 250 bps
Libor + 200 bps
Structure
Minimum Liquidity
$300MM subject to
increase up to $500MM
upon certain conditions
Financial Covenants
Interest Coverage Ratio
2016 – 0.75x
2017 – 1.00x
2018 – 1.25x
2019+ – 1.50x
Redetermination
No borrowing base redeterminations but requires a
1.5x collateral coverage ratio
None
Previously Existing
$750MM Term Loan
Maturity Date – December 2020
Interest rate – Libor + 250 bps
Required to repay term loan with net proceeds
from future asset sales and certain debt and equity
issuances
Maturity Date – November 2018
Interest rate – Libor + 163 bps
Required to repay term loan with all net
proceeds from asset sales, equity or debt
issuances
Debt to total book cap <60%
(certain ceiling test impairments disregarded)
(1) $66MM of our existing unsecured revolving credit facility will remain in place until December 2018.
Note: These are a summary of terms of the bank credit agreements reflective of current conditions. See credit agreements filed as exhibits to the Form 8-K dated June 27, 2016.
22
Proven Track Record
(1)
Production (Bcfe)
Adjusted EBITDA ($MM)
$2,320
976
$1,998
$1,774
768
$1,602
657
500
$1,638
$1,440
1362
$1,383
07
08
09
10
11
12
13
14
15
$6.80
$7.52
$5.35
$4.62
$4.18
$3.44
$3.65
$3.72
$2.37
565
405
675
300
113
07
195
08
09
10
11
12
13
14
15
Price(2)
Proved Reserves (Tcfe)
F&D Cost ($/Mcfe)
(3)
10.7
2.94
2.70
7.0
2.08
6.2
5.9
1.70
4.9
4.0
3.7
1.5
07
1.24
2.2
08
1.34
1.28
0.91
0.62
09
10
11
12
13
14
15
07
08
09
10
11
12
13
14
15
(1) Adjusted EBITDA is a non-GAAP financial measure. See explanation and reconciliation of adjusted EBITDA on page 35.
(2) Average realized gas prices including hedge impact ($/Mcf).
(3) Excludes reserve revisions and the impact from 2014-2015 West Virginia and Pennsylvania acquisitions.
23
Southwest Appalachia
Horizontal Well Performance
Early Well Results Exceeding Expectations
Time Frame
Wells
Placed on
Production
Average
Lateral
Length
Avg Rate
For 1st 30
Days
(Mcfe/d)
(# of wells)
30th-Day
% Gas /
Condensate
/ NGL
Avg Rate
For 1st 60
Days
(Mcfe/d)
(# of wells)
60th-Day
% Gas /
Condensate /
NGL
Average
Completed
Well Cost
($MM) (1)
Average
Drilling
Days
(# of days) (1)
2nd Qtr 2015
10
5,399
6,428 (10)
51 / 13 / 36
6,246 (10)
52 / 11 / 37
$8.7
24.8
3rd Qtr 2015
5
5,899
6,703 (5)
37 / 18 / 45
7,038 (5)
38 / 15 / 47
$6.7
17.8
4th Qtr 2015
19
7,833
6,810 (19)
39 / 20 / 41
7,329 (19)
40 / 19 / 41
$6.5
17.3
1st Qtr 2016
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2nd Qtr 2016
11
5,068
5,746 (1)
27 / 39 / 34
N/A
N/A
N/A
N/A
(1)
Includes only wells drilled and completed by SWN.
Well Count Summary
•
Significant 2015 operational achievements
Dry Marcellus
1,725
–
Materially outperformed offset wells drilled by others
Rich Marcellus
450
–
Drilling days reduced over 30% from Q2 to Q4 while staying in
target interval 94% of the time
Lean Marcellus
500
–
Numerous SWN drilling and completion records
–
Successfully drilled first Utica well
Total Marcellus
2,675
Utica
1,400
Upper Devonian
Total Well Count
675
4,750
24
Southwest Appalachia
Type Curves
SWN Drilled & Completed Rich Gas Condensate
(Normalized to 7,500 ft lateral)
Historical Production
12 BCFe Type Curve
14 BCFe Type Curve
10,500
9,000
Mmcfe/d
7,500
6,000
4,500
3,000
1,500
0
0
50
100
150
200
250
300
350
400
450
500
350
400
450
500
Days Online
SWN Drilled & Completed Lean Gas Condensate
(Normalized to 7,500 ft lateral)
Historical Production
26 BCFe Type Curve
15,000
Mmcfe/d
12,500
10,000
7,500
5,000
2,500
0
0
50
100
150
200
250
300
Days Online
25
Northeast Appalachia
Operating Statistics
Time Frame
30th-Day
Avg Rate
(# of wells)
Average
Lateral
Length (ft)
Average
RE-RE
(Rig Days)
Average
Well Cost
($MM)
1st Qtr 2014
7,009 ( 21)
3,859
10.5
$6.2
2nd Qtr 2014
6,772 ( 23)
4,982
10.3
$6.3
3rd Qtr 2014
6,159 ( 18)
5,288
10.0
$6.3
4th Qtr 2014
6,947 ( 26)
5,333
10.0
$5.9
1st Qtr 2015
7,505 ( 22)
4,713
11.2
$5.8
2nd Qtr 2015
6,594 ( 21)
5,853
8.9
$6.7
3rd Qtr 2015
5,720 ( 19)
5,512
8.4
$5.5
4th Qtr 2015
5,581 ( 38)
5,405
8.1
$4.9
1st Qtr 2016
4,675 ( 3)
5,465
N/A
N/A
2nd Qtr 2016
7,550 ( 5)
7,454
N/A
N/A
25.6
$7.0
16.5
$7.0
$6.2
$5.9
$6.1
$5.6
13.2 12.9
10.2 10.0
10
11
12
13
14
15
10
Days to Drill
-61%
4,982
3,805
11
12
13
14
15
Well Cost ($MM)
-5%
360
5,384
4,752
4,223 4,070
254
Northeast Appalachia has shown tremendous
improvement in costs and well performance
since its first well in 2010
151
54
1
10
11
12
13
14
15
Lateral Length (in ft.)
+41%
10
23
11
12
13
14
Production (Bcf)
15
3-Yr F&D of $0.42(1)
(1) Excludes price revisions, acquisitions and the impact of capitalizing interest
and portions of G&A in accordance with full cost accounting.
26
Northeast Appalachia
Well Performance
8,000
Company Operated Drilled Wells
7,000
6,000
Daily Rate, MCFPD
5,000
4,000
3,000
2,000
1,000
0
0
365
730
1095
1460
1825
Days of Production
Bradford County
Lycoming County
Susquehanna County
8 BCF EUR Curve
10 BCF EUR Curve
12 BCF EUR Curve
Wells on‐line <18 Months
Note: Excludes downtime and exploratory wells 27
Fayetteville
Operating Statistics
Time Frame
Wells
Average
Placed on IP Rate
Production (Mcf/d)
30th-Day
Avg Rate
(# of wells)
60th-Day
Avg Rate
(# of wells)
Average
Lateral
Length (ft)
$2.8
$2.8 $2.8
10.9
1st Qtr 2014
105
4,272
2,616 ( 105)
2,205 (105)
5,680
2nd Qtr 2014
148
4,369
2,720 ( 148)
2,112 (148)
5,382
3rd Qtr 2014
106
4,303
2,680 ( 106)
2,174 (106)
5,202
4th Qtr 2014
97
4,840
2,472 ( 97)
1,834 (97)
5,547
1st Qtr 2015
99
4,424
2,412 ( 99)
1,904 (99)
5,875
2nd Qtr 2015
68
4,405
2,564 ( 57)
2,087 (68)
5,836
3rd Qtr 2015
50
3,886
2,106 ( 50)
1,748 (50)
5,407
4th Qtr 2015
43
4,277
2,520 ( 43)
2,105 (43)
5,726
1st Qtr 2016
9
6,586
2,719 ( 9)
2,351 (9)
5,736
2nd Qtr 2016
6
5,872
2,654 ( 5)
2,592 (3)
6,870
$2.6
7.9
6.7
10
11
12
6.2
13
$2.5
7.3
6.8
$2.4
14
15
10
Days to Drill
-33%
11
12
13
14
Well Cost ($MM)
486
486
494
437
4,528 4,836 4,819
10
11
12
5,729
5,356 5,440
13
14
15
15
Lateral Length (in ft.)
+27%
465
350
10
11
12
13
14
Production (Bcf)
+33%
15
With over a decade of development, the
Fayetteville Shale now produces over 2% of
the nation’s natural gas supply, generating
significant cash flow for the company.
3-Yr F&D of $0.74(1)
(1) Excludes price revisions, acquisitions and the impact of capitalizing interest
and portions of G&A in accordance with full cost accounting.
28
Fayetteville
Well Performance
Mcf/d
5,000
4 Bcf Typecurve
3 Bcf Typecurve
4,500
2 Bcf Typecurve
All Wells
4,000
Normalized to 5,300 ft. lateral
3,500
3,000
2,500
2,000
1,500
1,000
500
0
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
Days of Production
Notes: Data as of December 31, 2015. Excludes shut-in wells and wells with mechanical problems (114).
29
Midstream
SWN Marketing
2016 Estimated total volumes marketed (Bcfe)
1,015 - 1,030
2016 Estimated EBITDA ($MM)(1)
$35 - $40
Fayetteville Shale Gathering
Gathered volumes at June 30, 2016 (Bcf/d)
1.7
Gathering lines (Miles)
2,044
Compression equipment (Horsepower)
474,740
2016 Estimated EBITDA ($MM)(1)
$220 - $230
Basis Differentials (including transport)
2016 Estimated discount to NYMEX gas ($/Mcf)
$(0.73) - $(0.83)
2016 Estimated discount to WTI oil ($/Bbl)
$(13.00) - $(15.00)
2016 Estimated NGL price realization (% of WTI)
15% - 20%
Forward-Looking Statement
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation on page 35.
30
U.S. Natural Gas Supply & Demand
29
28
12-Month Rolling Average
27
26
25
TCF
24
23
22
21
20
19
18
17
Jan‐02
Source: EIA
Jan‐03
Jan‐04
Jan‐05
Jan‐06
Jan‐07
Dry Prod
Jan‐08
Jan‐09
Net Import
Jan‐10
Jan‐11
Jan‐12
Jan‐13
Jan‐14
Jan‐15
Jan‐16
Consume
31
Financial and Operational Summary
6 Months Ended June 30,
2016
Year Ended Decem ber 31,
2015
2015
($ in millions, except per share amounts)
Revenues
Adjusted EBITDA(1)
(2)
Adjusted Net Income
Net Cash Flow
(1)
(2)
Adjusted Diluted EPS
Production (Bcfe)
Avg. Realized Gas Price ($/Mcf)
Avg. Realized Oil Price ($/Bbl)
Avg. Realized NGL Price ($/Bbl)
2013
$
1,101
$
1,697
$ 3,133
$ 4,038
$ 3,371
$
266
$
828
$ 1,440
$ 2,320
$ 1,998
$
(66)
$
74
$
$
$
$
261
$
832
$ 1,468
$ 2,270
$ 1,985
$
(0.17)
$
0.20
$
$
$
$
$
$
462
1.40
25.43
5.67
$
$
$
478
2.60
36.08
7.63
Finding Cost ($/Mcfe)(3)
Reserve Replacement (%)
2014
($ in millions, except per share amounts)
(4)
Total Debt/Proved Reserves ($/Mcfe)
Total Debt/Avg. Daily Production ($/Mcfe)
71
0.19
801
2.27
704
2.00
976
$ 2.37
$ 33.25
$ 6.80
768
$ 3.72
$ 79.91
$ 15.72
657
$ 3.65
$ 103.32
$ 43.63
$
$
$
0.61
228%
$ 0.76
$ 1,759
0.78
284%
$ 0.65
$ 3,309
0.62
512%
$ 0.28
$ 1,084
(1) Net cash flow is operating cash flow before changes in operating assets and liabilities and one-time severance payments. Net cash flow and adjusted EBITDA are non-GAAP
financial measures. See explanation and reconciliation on pages 33 and 35, respectively.
(2) Adjusted net income is a non-GAAP financial measures. See explanation and reconciliation on pages 34.
(3) Excludes price revisions, acquisitions and the impact of capitalizing interest and portions of G&A in accordance with full cost accounting.
(4) Excludes price revisions and acquisitions.
Forward-Looking Statement
32
Explanation and Reconciliation of Non-GAAP
Financial Measures: Net Cash Flow
We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However,
management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful
comparisons between current results and the results of our peers and of prior periods. One such non-GAAP financial measure is net cash flow.
Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to
internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate
to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not
relate to the period in which the operating activities occurred. These adjusted amounts are not a measure of financial performance under GAAP.
Cash flow from operating activities:
Net cash provided by operating activities
Add back (deduct):
Change in operating assets and liabilities
Restructuring charges
Net cash flow
3 Months Ended June 30,
6 Months Ended June 30,
2016
2015
($ in millions)
2016
2015
($ in millions)
12 Months Ended December 31,
2015
2014
($ in millions)
2013
$73
$399
$165
$940
$1,580
$2,335
$1,909
17
24
(60)
$339
50
46
(108)
$832
(112)
$1,468
(65)
$2,270
76
$1,985
$114
$261
2016 Guidance
Original
Revised
$2.35 Gas
$2.45 Gas
$35.00 Oil
$45.00 Oil
Cash flow from operating activities:
Net cash provided by operating activities
$405 - $450
Add back (deduct):
One-time cash severance payments
45 - 50
Change in operating assets and liabilities
Net cash flow
$450 - $500
$609 - $634
46
$655 - $680
Forward-Looking Statement
33
Explanation and Reconciliation of Non-GAAP
Financial Measures: Adjusted Net Income
Additional non-GAAP financial measures we may present from time to time are adjusted net income and adjusted diluted earnings per share attributable to Southwestern Energy
stockholders, both of which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the Company’s
performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii)
charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted
amounts are not a measure of financial performance under GAAP.
Net income (loss) attributable to common stock
Add back (deduct):
Participating securities - mandatory convertible preferred stock
Impairment of natural gas and oil properties
Loss on certain derivatives
Adjustments due to inventory valuation
Gain on sale of assets
Transaction costs
Restructuring costs
Adjustments due to discrete tax items (1)
Tax impact on adjustments
Adjusted net income
3 Months Ended June 30,
2016
2015
($ in millions) (per share) (3)
($ in millions) (per share)
$
(620) $
(1.61)
$
(815) $
(2.13)
$
$
- $
470
108
1
(2)
11
216
(218)
(34) $
1.22
0.28
0.00
(0.01)
0.03
0.56
(0.56)
(0.09)
$
$
$
$
2016 Guidance
Original
$2.35 Gas
$35.00 Oil
Revised
$2.45 Gas
$45.00 Oil
$(223) - $(197)
$
4.02
0.13
(0.72)
0.00
(1.32)
(0.02)
$
$
- $
1,504
129
4
(2)
75
647
(644)
(66) $
3.91
0.34
0.01
(0.00)
0.19
1.68
(1.67)
(0.17)
$
$
(13) $
1,535
71
(277)
52
(532)
74 $
(0.03)
4.05
0.19
(0.73)
0.14
(1.41)
0.20
12 Months Ended December 31,
2015
2014
2013
($ in millions) (per share)
($ in millions) (per share)
($ in millions) (per share)
$
(4,662) $
(12.25)
$
924 $
2.62
$
704 $
2.00
Net income (loss) attributable to common stock
Add back (deduct):
Participating securities - mandatory convertible preferred stock
Impairment of natural gas and oil properties
(Gain) Loss on certain derivatives
Adjustments due to inventory valuation
Gain on sale of assets
Transaction costs
Restructuring costs
Adjustments due to discrete tax items (1,2)
Tax impact on adjustments
Adjusted net income
Net income (loss) attributable to common stock
Add back (deduct):
Impairment of natural gas and oil properties (4)
Restructuring charges
Gain on sale of assets
Loss on certain derivative contracts
Adjustments due to inventory valuation
Adjustments due to discrete tax items
Tax impact on adjustments
Adjusted net income (loss) attributable to common stock
- $
1,535
50
(277)
1
(503)
(9) $
6 Months Ended June 30,
2016
2015
($ in millions) (per share) (3)
($ in millions) (per share)
$
(1,779) $
(4.63)
$
(762) $
(2.01)
60 - 70
(23) - (27)
$(180) - $(160)
(13) $
6,950
155
32
(283)
54
2
483
(2,647)
71 $
(1)
$(1,655) - $(1,625)
$
1,504
75
(2)
129
4
568 - 579
(644)
$(10) - $10
(2)
(3)
(4)
(0.03)
18.26
0.41
0.08
(0.74)
0.14
0.01
1.27
(6.96)
0.19
$
$
- $
(130)
5
(46)
48
801 $
(0.37)
0.01
(0.13)
0.14
2.27
$
$
- $
(21)
13
8
704 $
(0.06)
0.04
0.02
2.00
2016 and 2015 primarily relates to the exclusion of certain
discrete tax adjustments due to an increase to the valuation
allowance against the Company’s deferred tax assets. The
company expects its 2016 effective income tax rate to be
38.0% before the impact of any valuation allowance.
2014 primarily relates to the exclusion of certain discrete tax
adjustments due to a redetermination of deferred state tax
liabilities to reflect updated state apportionment factors.
Do not include 98.9 million shares of common stock issued
in July 2016.
Does not include any forecasted impairments.
Forward-Looking Statement
34
Explanation and Reconciliation of Non-GAAP
Financial Measures: Adjusted EBITDA
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Adjusted EBITDA is defined as EBITDA less gains and/or losses
on derivatives (net of settlement). Southwestern has included information concerning EBITDA and Adjusted EBITDA because they are used by certain investors as a measure of
the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA and Adjusted EBITDA should not
be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally
accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA and Adjusted EBITDA, as defined above, may not be comparable to similarly
titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below
reconciles historical Adjusted EBITDA with historical net income.
6 Months Ended June 30,
(2)
(1)
2016
2015(1)
($ in millions)
($1,725)
($710)
Net income (loss)
Add back (deduct):
Net interest expense
Provision (benefit) for income taxes
Depreciation, depletion and amortization (1)
Gain on sale of assets
Write-down of inventory
Restructuring charges
31
0
1,754
(2)
4
75
(Gain) Loss on derivatives excluding derivatives, settled
Adjusted EBITDA
52
(444)
2,136
(277)
-
12 Months Ended December 31,
2015(1)
2014
2013
($4,556)
$924
$704
56
(2,005)
8,041
(283)
32
-
59
525
942
-
42
486
787
-
2012(1)
2011
($ in millions)
($707)
$638
35
(443)
2,751
-
24
413
705
-
2010
2009(1)
2008
$604
($37)
$568
26
392
590
-
19
(16)
1,402
-
29
351
414
-
129
71
155
(130)
(21)
2
(6)
(10)
15
-
$266
$828
$1,440
$2,320
$1,998
$1,638
$1,774
$1,602
$1,383
$1,362
The table below reconciles forecasted Adjusted EBITDA with forecasted net income for 2016, including current hedges in place:
2016 Guidance
Original
Revised
$2.35 Gas
$2.45 Gas
$35.00 Oil
$45.00 Oil
Net income (loss) attributable to common stock
Add back:
Mandatory convertible preferred stock dividends
Net income (loss) attributable to SWN
Add back:
Provision for income taxes
Impairment of natural gas and oil properties
Depreciation, depletion and amortization
Gain on sale of assets
Loss on derivatives
Interest expense
Write-down on inventory
Restructuring charges
Adjusted EBITDA
(2)
$(223) - $(197)
$(1,655) - $(1,625)
108 - 108
$(115) - $(89)
108 - 108
$(1,547) - $(1,517)
(1)
(2)
(70) - (54)
520 - 530
53 - 58
60 - 70
$450 - $500
1,504
440 - 450
(2)
129
60 - 65
4
75
$675 - $700
Includes impact from full cost ceiling test
impairment of our natural gas and oil
properties.
Does not include any forecasted impairments.
Forward-Looking Statement
35