Project - Tennessee Gas Pipeline

Welcome
2015 Natural Gas Pipeline Company of
America LLC
Customer Meeting
Park Hyatt Hotel
Chicago, IL
August 19, 2015
Corporate Overview and
Gas Pipeline Group Growth Projects and Opportunities
Tom Martin
President, Natural Gas Pipeline Group
August 19, 2015
Unparalleled Asset Footprint
Largest Energy Infrastructure Company in North America
 3rd largest energy company in N. America
with an enterprise value of ~$120 billion
 $22 billion of currently identified organic
growth projects
 Largest natural gas network in N. America
— Own an interest in/ operate ~69,000 miles
of natural gas pipeline
— Connected to every important U.S. natural
gas resource play, including: Eagle Ford,
Marcellus, Utica, Bakken, Uinta,
Haynesville, Fayetteville and Barnett
 Largest independent transporter of
petroleum products in N. America
— Transport ~2.4 MMBbl/d(a)
 Largest transporter of CO2 in N. America
— Transport ~1.4 Bcf/d of CO2(a)
 Largest independent terminal operator in
N. America(b)
— Own an interest in or operate ~165 liquids/
dry bulk terminals
— ~142 MMBbls domestic liquids capacity
— Handle ~83 MMtons of dry bulk products(a)
— Strong Jones Act shipping position
 Only Oilsands pipe serving West Coast
— Transports ~300 MBbl/d to Vancouver/
Washington State; proposed expansion
takes capacity to 890 MBbl/d
__________________________
(a) 2015 budgeted volumes.
(b) Excludes terminals contributed to Watco.
4
Weathering the Storm
Weathering the High Seas(a)
Well-positioned Assets, Stable Cash Flow

Low commodity price sensitivity
— 2015 budgeted EBDA is ~87% fee-based,
~96% fee-based or hedged
— $1/Bbl change in oil price = $10 million
DCF impact; 10¢/MMBtu change in natural
gas price = $3 million DCF impact
 Existing backlog largely insulated from oil
price fluctuation due to long-term customer
contracts and association with high-demand,
multi-year projects
— In sustained low price environment, the
rate at which we add to our backlog may
slow
— Capital cost savings are possible
 Significant demand creation expected with
lower-priced petroleum feedstocks
 Acquisition opportunities




Oil last closed above $90/Bbl on 10/6/2014
Oil significantly lower today, down over 50%
Safe harbor: KMI has demonstrated strong
relative stock performance since 10/6/2014
KMI is one of only nine companies in the
S&P 500 with the following investment
traits(b):
— >$70 billion market cap
— >3% current dividend yield
— >5% projected annual dividend growth
KMI Stock Perf. Since Oil was Last $90(a)
10%
6%
0%
-10%
-20%
-30%
-12%
-22%
-31%
-39%
-40%
-50%
-53%
-60%
S&P 500 S&P 500 Alerian EPX E&P WTI Oil
KMI
__________________________
Index
Energy
Index
Index
Spot Px.
(a) Source: Bloomberg. Price performance from 10/6/2014 to 8/14/2015.
(b) Sources: Bloomberg, FactSet and Wall Street research. As of 8/14/2015.
Includes companies which meet the following criteria: in S&P 500, market cap >$70 billion, LQA dividend yield >~3%, 2015-2017 projected annual dividend growth >~5%.
5
5-year Project Backlog(a)
$22 Billion of Currently Identified Organic Growth Projects
Tremendous footprint provides $22B of currently identified growth projects over next 5 years
5-year Growth Capex Backlog ($B)
2H 2015
2016
2017
2018+
Total
Natural Gas Pipelines
$0.7
$0.7
$2.7
$5.3
$9.4
Products Pipelines
0.2
0.1
0.8
0.5
1.6
Terminals
0.4
0.6
1.3
0.2
2.5
CO2 – S&T(b)
0.3
0.1
0.1
0.3
0.8
CO2 – EOR(b) Oil Production
0.3
0.5
0.4
1.1
2.3
5.4
5.4
$12.8
$22.0
Kinder Morgan Canada
Total
$1.9
$2.0
$5.3
~90% of backlog is for
fee-based pipelines,
terminals and
associated facilities
Not included in backlog:
– TGP Northeast “supply path”
– Marcellus/ Utica liquids pipeline solution (UMTP)
– Further LNG export opportunities
– Potential acquisitions
__________________________
(a) Highly-visible backlog consists of current projects for which commercial contracts have been either secured, or are at an advanced stage of negotiation. Total capital expenditures for each
project, shown in year of expected in-service; projects in-service prior to 6/30/2015 excluded. Includes KM's proportionate share of non-wholly owned projects. Includes estimated
capitalized corporate overhead of $1,086 million.
(b) S&T = CO2 Sales & Transportation. EOR = Enhanced Oil Recovery.
6
Hiland Acquisition:
Strategic Acquisition of Premier Midstream Position in the Bakken
Tioga, ND
Williston, ND
Hiland Asset Overview: 86%(a) fee-based, crude oil gathering and transportation, and
gas gathering and processing

Crude oil gathering ~59%(a)
— 1,225 miles of pipelines in North Dakota and Montana
— Deliver to the basin’s major takeaway pipelines and to rail

Double H Pipeline crude oil transportation ~27%(a)
— 485-mile pipeline from ND to Guernsey, WY
— Interconnects with Pony Express for delivery to Cushing, Oklahoma

Gas gathering and processing ~14%(a)
— 1,800 miles of gathering pipelines in North Dakota and Montana
— 240 MMcf/d of processing capacity and 30 MBbl/d of fractionation capacity, upon
completion of 2015 expansion
Watford City, ND
Baker, MT
Double H
Pipeline
Strategic Acquisition: Establishes premier midstream platform in the core of the
Bakken, one of the most prolific oil producing basins in North America
Douglas, WY
Legend(b):
Guernsey, WY
Hiland dedication area
Gas pipeline
Crude pipeline

Systems overlay some of the most attractive and economically viable “tier-one” areas of
the Bakken, including McKenzie, Williams and Mountrail counties

Double H crude oil pipeline provides key takeaway capacity with take-or-pay contracts

Long-term acreage dedications with some of the Bakken’s largest, most successful
producers

Scale and footprint well-positioned to support additional infrastructure opportunities in
and around the Bakken
__________________________
(a) Percentage of estimated 2015 EBITDA.
(b) Many gas and crude pipes overlap as they share right of way. Map excludes smaller Mid-con gas gathering assets.
7
Natural Gas Megatrend
Strong Natural Gas Footprint & Market Opportunity Set
U.S. Natural Gas Projected
Supply & Demand(a)
(Bcf/d)
Demand
2015 2020 2025
LNG net exports
-0.2
7.6 10.8
Mexican net exports
2.6
4.3
5.5
Power
24.4 30.1 33.0
Industrial
21.3 24.8 26.0
Other
28.5 31.8 34.5
Total U.S. demand
76.6 98.6 109.8
Supply
Marcellus/ Utica
18.7 35.8 42.3
All other
57.9 62.8 67.5
Total U.S. supply
76.6 98.6 109.8
Real- time, Long-term
Benefits of Footprint
Natural Gas Segment Asset Footprint
Power
Generation
+5.7/ 8.6 Bcf/d(b)
Monthly Share of U.S. Power
(c)
Generation by Fuel, 2001-15
% of Total
Generation
55%
Coal
Natural Gas
 KMI owns/ operates ~69,000
miles of natural gas pipeline(d)
- Move ~33% of total U.S natural
gas demand
 $9.4 billion natural gas project
backlog
 Significant recent demand for
long-term natural gas capacity
- 8.7 Bcf/d of new/ pending
contracts secured over past 1.5
years (~10% of estimated 2015
total U.S. demand)
- 17-year average contract term
50%
45%
40%
35%
30%
25%
20%
15%
10%
Jan'01 Jan'03 Jan'05 Jan'07 Jan'09 Jan'11 Jan'13 Jan'15
Exports to
Mexico
+1.7/ 2.9 Bcf/d(b)
Industrial
(petchem)
+3.5/ 4.7 Bcf/d(b)
LNG Export
__________________________
(a) Source: Wood Mackenzie Spring 2015 Long-Term View.
+7.9/ 11.0 Bcf/d(b)
(b) Projected 5-year/ 10-year increase.
(c) Source: U.S. Energy Information Administration, July 2015 Monthly Energy Review, Table 7.2a Electricity Net Generation: Total (All Sectors)
(d) Includes KM operated and non-operated JV pipelines.
8
Supply Push
TGP - Broad Run Flexibility and Expansion
 Capacity: 790 MDth/d
 Capital: $818 MM
 Estimated In-service:
— 11/2015 - Flexibility (590 MDth/d)
— 11/2017 - Expansion (200 MDth/d)
 Project Scope:
— Piping/compression modifications to 7 existing stations
to accommodate bi-directional flow
— Horsepower at 3 greenfield stations
 Commercial Benefit:
— Moves gas north-to-south from a receipt point in West
Virginia to delivery points in Mississippi and Louisiana
 Avg. Contract Term: 15 years
 Current Status:
— Pipeline and compression modifications are underway
— FERC application for Expansion filed January 2015
 Major Milestones:
— FERC certificate for Expansion expected 1Q2016
— Begin construction March 2016
9
Market Growth
TGP Northeast Energy Direct (NED) Project - Market Path
 Capacity: 600 - 1,300 MDth/d
 Capital: $3.3 - 3.8 Billion
 Estimated In-service: 11/2018
 Project Scope:
— 188 miles of 30” mainline
— Laterals to serve specific LDCs
— Up to 300,600 HP based on final scope
 Commercial Benefit:
— Supply growing New England LDC market
— Provide reliable firm supply for gas-fired power
generation market
 Avg. Contract Term: 19.8 years
 Current Status:
— Executed PA’s with New England LDCs – over
560 MDth/d
— Pursuing additional markets: State of Maine,
LDCs, electric power
— Actively participating in state legislative and
regulatory activities
Existing TGP Flow
NED Additional Flow
 Major Milestone:
— FERC certificate application filing 4Q 2015
10
Market Growth
TGP Northeast Energy Direct (NED) Project - Supply Path
 Capacity: 700 - 1,200 MDth/d
 Capital: $1.6 - 2.0 Billion
 Estimated In-service: 11/2018
 Project Scope:
— 135 miles of 30” pipe
— 34 miles of 36” loop
— 32,000 HP at 2 compressor stations
 Commercial Benefit:
— Provide Marcellus producers with additional
access to liquid point serving New England market
— Provide Market Path subscribers with direct
access to Marcellus supplies
 Current Status:
— Securing shipper commitments
— Preparatory work for FERC certificate application
 Major Milestones:
Marcellus
— Execution of anchor shipper PAs
— FERC certificate application filing 4Q 2015
Existing TGP Flow
NED Additional Flow
11
Gas Transportation for LNG Export
Kinder Morgan Transportation Commitments
12
Gas Transportation for LNG Export
TGP - Lone Star
 Capacity: 300 MDth/d
 Capital: $134 MM
 Estimated In-service: July 2019
 Project Scope:
— 2 greenfield compressor stations
 Commercial Benefit:
— Provide supply to Corpus Christi LNG
liquefaction project
 Avg. Contract Term: 20 years
12
 Current Status:
— PA fully executed
— LNG project achieved FID in May 2015
— Preparatory work for FERC certification
application
 Major Milestone:
— FERC certificate application filing
4Q 2016
13
Gas Transportation for LNG Export
TGP - Cameron LNG
 Capacity: 900 MDth/d
 Capital: $160 MM
 Estimated In-service: 2Q - 4Q 2018
 Project Scope:
— Compressor station modifications to
accommodate bi-directional flow
— 18,000 HP of new compression
— New pipeline laterals for enhanced
supply access to the Perryville Hub
 Commercial Benefit:
— Supply from multiple basins for LNG
export
 Avg. Contract Term: 21 years
 Current Status:
— PAs executed
— All shipper conditions precedent have
been cleared
— LNG facility under construction
 Major Milestone:
— FERC certificate application filing
4Q 2015
14
Gas Transportation for LNG Export
Midstream - SK Freeport LNG
 Capacity: 440 MDth/d
 Capital: $169 MM
 Estimated In-Service: 3Q 2019
 Project Scope:
— New 30” lateral from Tejas mainline
to Stratton Ridge
— Additional upstream compression
on existing mainlines
 Commercial Benefit:
— Deliver gas to Freeport LNG
terminal (Train 3)
— Capture additional 3rd party
markets
 Current Status:
— Executed FTA
— FERC and DOE Approval
November 2014
— Financing and Final Investment
Decision completed April 2015
15
Transport for LNG Export and Market Growth
SNG / Elba Express Expansion
 Capacity: 853 MDth/d(a)
 Capital: $309 MM(a)
 Estimated In-service: 6/2016 - 2017
 Project Scope:
— Compression on SNG and EEC
— Additional pipeline and other facilities
 Commercial Benefit:
— Additional, seamless transport on SNG
from Marcellus/Utica shale to market for
power generators and other customers
— Access for Shell to supply for Elba
Liquefaction facility
 Avg. Contract Term: 19 years
SNG
EEC
FGT
Transco
SNG / EEC Expansion
 Current Status:
— PAs executed
— FERC applications filed
 Major Milestones:
— FERC certificate anticipated
Oct/Nov 2015
__________________________
(a) Includes the cost ($112 MM) and capacity (436 MDth/d) for the component of the EEC expansion serving Elba
Liquefaction.
16
LNG Export
Liquefaction at Elba Island
 Capacity:
— 430 MMcf/d natural gas receipt capacity
— LNG output capacity equivalent to 350 MMcf/d
 Capital (100% KM, $MM): $2.1 Billion
 Estimated In-service: Late 2017 - mid 2018
 Project Scope:
— Facilities for liquefaction (10 modular units)
— Ship loading facilities; boil-off gas compression
 Avg. Contract Term: 20 years
 Current Status:
— In July 2015 KMI reached agreement to acquire
—
—
—
—
Shell’s 49% interest in the project (KMI now
owns 100%)
DOE FTA export authorization received;
non-FTA application filed
FERC applications filed
FEED complete
Shell has committed to entire capacity of facility,
as well as Elba Express expansion
 Major Milestones:
— Execution of EPC contract
— FERC certificate anticipated Oct/Nov 2015
17
LNG Export - Potential Opportunity
Liquefaction at Gulf LNG
 Capacity: Up to 10 MTPA (~1.39 Bcf/d)
— Two liquefaction trains, each 5 MTPA
 Capital (KM Share): $2.5 - 4 Billion
 Estimated In-Service: 2020
 Project Scope:
— Developing facilities to export LNG at
existing import facility
— Seawall to be expanded and existing dock
and tanks utilized
 Current Status:
— DOE FTA export authorization received;
non-FTA application pending
— FERC pre-filing completed
— FERC certificate application filed June
2015
— Negotiating with customers
 Major Milestone:
— FERC certificate anticipated June 2016
18
Exports to Mexico
19
Mexican Natural Gas Demand Growth
TGP - South System Flexibility
 Capacity: 500 MDth/d
 Capital: $205 MM
 In-service:
— 150 MDth/d placed in service 1/2015
— 350 MDth/d in service late 2015 and 2016
 Project Scope:
— Station modifications at 7 stations to
accommodate bi-directional flow
— Horsepower replacement at 1 station
 Commercial Benefit:
— Provides over 900 miles of north-to-south
capacity on the TGP system from Tennessee to
south Texas
— Expands transportation service to Mexico
 Avg. Contract Term: 20 years
 Current Status:
— PA executed for 500 MDth/d (MexGas)
— 150 MDth/d in service
— Compression work ongoing
— Further engineering work underway
20
Mexican Natural Gas Demand Growth
EPNG - Upstream of Sierrita
 Capacity: Phase II, 350 MDth/d
 Capital: Phase II, $526 MM
 Estimated In-service: October 2020
 Project Scope:
— Phase II:
- New Franconia compressor station – 10,300 HP
- 100 mile, 36” Havasu Loop
- Reverse Casa Grande ‘A’ and ‘C’ and Cimarron
compressor stations
 Commercial Benefit:
— Additional capacity to serve continued growth in
Mexican demand along the Sierrita pipeline
 Contract Term: 15 years
 Current Status:
— Phase I capacity in service
21
NGPL Pipeline Operations Review
Danny Ivy
VP - Gas Control, Kinder Morgan
August 19, 2015
22
Pipeline Management
23
 Operations Review
─
─
─
─
2014-2015 Weather Review
2015 Transport & Storage Review
NGPL Storage Data Summary
Maintenance Update
 Winter 2015/2016
 Contact Lists
23
NGPL Facility Map
• Miles of pipe
~9,200 miles
• Flow meters
~700
• Total HP
~1,000,000
•Total compressor stations 50
•Total storage fields
12
• Winter peak day delivery
5.2 BCF
• Storage working capacity
288 BCF
• Mainline linepack
12.3 BCF
24
Winter 2014/2015 Conditions
 2014-2015 was 10 % colder than normal
─ Highest monthly system throughput since 2010 in February (5.2
Bcf/d)
─ 3.6 Bcf/d to the market
─ February 18, 2015 throughput was 6.1 Bcf/d ( 4.6 Bcf/d to the
market)
 Met strategic goals:
─
─
─
─
Facility modification in Iowa accomplished
Station 113 enhancements completed
Storage enhancements completed at Sayre
Market storage targets met
─ Working inventory hit 116.68 MM Dth on Oct 28, 2014
─ 10 Bcf higher than 2013
 No pressure or deliverability issues
25
Chicago O’Hare HDDs
November
December
January
February
March
2014-2015
HDD's
% of Normal
936
126%
1015
88%
1317
103%
1405
135%
910
108%
5583
110%
2013-2014
HDD's
% of Normal
819
111%
1283
111%
1521
119%
1329
127%
1025
122%
5977
118%
26
NGPL Storage Data Review
Injection
Withdrawal
27
Summer 2015 Transport
 2015 Transport Summary
 Power Generation markets are up 23% from 2014
─ Direct connect power is approx. 13,600 MW or 2.4 MM Dth/d
 Amarillo transports near max from Midcontinent
─ Managing around integrity remediation
─ Capacity available north of Trailblazer
 Gulf Coast utilization higher and less variable
─ REX Moultrie receipts remain strong
─ No restrictions on East Texas receipts
 Utilization of the Louisiana system remains at modest levels
 Arkansas receipts averaging approximately 200,000 MMbtu/d
 South Texas from Eagle Ford higher than 2014
28
NGPL Maintenance Program





Integrity IMP
SCC
General maintenance
HP replacement program
Updated 12 Month Rolling Maintenance Plan is
posted on EBB around the 20th of each month
- A detailed listing/description of the next month’s
outages are also posted on the 20th of each month
29
2015 NGPL Maintenance Program
TYPE
2015
JOB COUNT
2014
JOB COUNT
2013
JOB COUNT
Integrity
193
170
186
O&M
286
285
286
System Total
479
455
472
Market Area and Storage
113
120
144
Amarillo projects
214
163
169
GC projects
152
172
159
Posted
62
61
117
Posted (with an impact)
28
25
51
Not posted (no impact)
417
394
355
30
NGPL Impacted Projects
116
205
5
113
199
110
196
108
201
109
198
204
107
106
203
195
206
105
194
8
6
311
310
104
193
103
309
102
159
158
112
308
184
111
154
156
307
169
801
812
168
306
167
803
802
155
305
388
139
304
303
302
343
342
346
301
300
8
341
For illustration purposes not to scale
1
31
Question
 It seems like we are experiencing more
scheduling restrictions in the Midcontinent,
seeing more events and postings that are
causing interruptible service to be interrupted, in
addition a few force majeures, why?
32
Answer
 Recent causes for limiting interruptible
service
─ Utilization of the Midcontinent segments are at continuous
high level, at or near capacity which limits flexibility to
perform maintenance and/or repairs without interruption.
─ Anomaly remediation following inspection of the pipe
─ 103 to 104 area
─ Managing the speed of an internal tool during a pig run
─ M&M line (Segments 3 & 4)
─ Installing/modifying pig launchers and receivers
─ 108-109 area
─ Crosshaul at capacity
33
NGPL Amarillo Constraints
Make piggable
Remediation
Multiple pig
runs
At capacity
through 801
34
High Impact Integrity Work Amarillo #3
CS 104
Kansas
CS 104
CS 193
26-inch
36-inch out of service
2015 FMJ
712 MAOP
Amarillo #3 remediation 6-10 to 6/13
Amarillo #3 remediation 8-6 to 8-7
Amarillo #3 remediation August
36-inch
26-inch
36-inch out of service
CS 193
35
NGPL 2015
Remaining Maintenance Projects
3
Summary with Possible
Impacts Gulf Coast and
Amarillo Systems
1
2
1
2
3
AM #3 36” anomaly repair digs
• 103-104 ongoing
• 191-103 expected late August
• 104-105 expected in September
• 105-106 expected in October
24” Remediation 156-158
• Expected in November
Amarillo #3 36” potential
remediation 108-109
• Expected in November
36
Action Item - Facilities
Station 206A Installation
 Install new 22,000 HP unit, replacing 5 existing units at
Stations 310 and 311
 System benefits
–
–
–
–
Replace ~15,000 HP with new HP
Add incremental 7,000 HP
Increased system flexibility and reliability
Increased ability to optimize Loudon storage withdrawals
 Status
– Work underway
– In-service late Fall 2015
37
Kinder Morgan 2014 Remaining Maintenance Projects
Summary with Possible Impacts
Gulf Coast and Amarillo Systems
1
1
2
AM #2 anomaly repair digs
Expected RTS 10-24-2013
7 SCC digs on Permian #1
Expected RTS date: 10-31-2013
2
39
Winter 2015-2016
 Meet market working inventory target of 116.0 MM Dth
on/around Nov 1
 Plan is to complete maintenance projects by early
November
 Expected changes in pipeline flows:
- REX receipts will increase on Gulf
- Cheniere Sabine will begin making LNG in fall 2015
- Deliveries to Mexico markets will continue
- Traditional supply basins:
- TX-OK will remain strong
- Midcontinent will remain at capacity
- South Texas will continue to increase
40
NGPL 2015/2016 Contact List
41
Gas Control
Transport and Stor Services
Account Services
Field Operations
Emer 800-733-2490
TSS Hotline
Dave Weeks
Gary Countryman
24 hr 713-369-9400
24 hr 713-369-9683
630-725-3030
815-272-9102
Cell 630-399-1193
Cell 815-302-9879
#GC-NGPL@kindermorgan.com
Trennis Curry
713-369-9378
Richard Williams
Donette Bisett
Dee Bennett- N. Region
Cell 713-819-4577
713-369-9283
713-369-9316
815-272-9104
Cell 713-819-1748
Cell 713-724-6445
Cell 815-693-0517
713-369-9131
Gene Nowak
Jim Brett
Bob Montgomery - W. Region/MEP
Cell 713-204-6432
713-369-9329
630-725-3040
806-379-2041 Ext 225
Cell 713-252-9759
Cell 630-437-0103
Cell 806-679-0320
Bill Weidlein
Danny Ivy
713-369-9311
Ken Grubb
Cell 713-829-2761
713-369-8763
Cell 281-702-1210
Ray Miller
713-369-9330
Gary Buchler
Cell 713-206-8338
713-369-8463
Houston TX Office
Downers Grove IL Office
713-369-9000
630-725-3000
1001 Louisiana St
3250 Lacey Rd
Houston, TX 77002
Suite 700
Cell 713-824-3904
Downers Grove, IL 60515
41
Gas-Electric Coordination Update
Richard Williams
Director – Central Region Transportation/Storage Services
August 19, 2015
42
FERC 809 - Update
 FERC’s Goal: Change regulations for the scheduling of transportation services on
interstate natural gas pipelines to better coordinate the scheduling practices of the
gas and electric industries and to provide scheduling flexibility to all shippers
 Order 809 highlights:
− Effective April 1, 2016
− Start of Gas Day to remain at 9:00 a.m. CCT
− Timely nomination deadline moved to 1:00 pm CCT
− Intra-day nomination cycles from 2 cycles to 3 cycles
− Capacity release open bidding for next day business happens prior to Timely
nomination deadline
− Capacity released will be recallable for the ID3 cycle
 KM Pipelines Action Plan:
− Currently working on coding changes in DART
− Primary testing to occur October – December
− Further testing will be done up to implementation date
− Full staffing end of March and beginning of April to assist customers
− Re-structure of daytime and evening work schedules to accommodate new
cycle timelines
43
New Cycle Timelines
All times CCT
Timely day-ahead Nom Deadline
Confirmations
Current
Effective 4/1/2016
11:30 AM
1:00 PM
3:30 PM
4:30 PM
All times CCT
Current
Effective 4/1/2016
ID2 Nom Deadline
5:00 PM
2:30 PM
Confirmations
8:00 PM
5:00 PM
Schedule Issued
4:30 PM
5:00 PM
Schedule Issued
9:00 PM
5:30 PM
Start of Gas Flow
9:00 AM
9:00 AM
Start of Gas Flow
9:00 PM
6:00 PM
Hours of Flow Left
24 hours
24 hours
Hours of Flow Left
12 hours
15 hours
IT Bump Rights
n/a
n/a
IT Bump Rights
no bump
bumpable
EPSQ
n/a
n/a
EPSQ
Process Time (Nom to Sch)
5 hours
4 hours
Process Time (Nom to Sch)
Evening Day-ahead Nom Deadline
6:00 PM
6:00 PM
Confirmations
9:00 PM
8:30 PM
Schedule Issued
10:00 PM
9:00 PM
Start of Gas Flow
9:00 AM
9:00 AM
Timely
ID2
Evening
1/2
9/24
4 hours
3 hours
ID3 Nom Deadline
n/a
7:00 PM
Confirmations
n/a
9:30 PM
Schedule Issued
n/a
10:00 PM
Start of Gas Flow
n/a
10:00 PM
ID3
Hours of Flow Left
24 hours
24 hours
Hours of Flow Left
n/a
11 hours
IT Bump Rights
bumpable
bumpable
IT Bump Rights
n/a
no bump
EPSQ
n/a
13/24
Process Time (Nom to Sch)
n/a
3 hours
EPSQ
Process Time (Nom to Sch)
ID1 Nom Deadline
n/a
n/a
4 hours
3 hours
10:00 AM
10:00 AM
Confirmations
1:00 PM
12:30 PM
Schedule Issued
2:00 PM
1:00 PM
Start of Gas Flow
5:00 PM
2:00 PM
Hours of Flow Left
16 hours
19 hours
IT Bump Rights
bumpable
bumpable
1/3
5/24
4 hours
3 hours
ID1
EPSQ
Process Time (Nom to Sch)
44
FERC NOPR - NAESB 3.0

“NAESB 3.0 NOPR” - Notice of Proposed Rulemaking on the Standards for
Business Practices of Interstate Natural Gas Pipelines (Docket No. RM96-1-038)
issued on July 16, 2015.

Proposed effective date is April 1, 2016

Compliance filings February 1, 2016



Discontinued use of “location common codes system” – commonly referred to as
DRN.
- Pipelines can now use their proprietary codes to replace DRN. NGPL refers to
these as a PIN (Point Identification Number).
Each pipeline will be required to maintain a new downloadable list of all their
locations and associated proprietary codes. In addition pipelines will be required to
track their pipeline interconnections and their corresponding proprietary code.
EDI nomination and confirmation processes that has used the DRN code for
communications will continue to be supported for interim period. Further
communications will occur in the next month to lay out options for EDI customers.
45
FERC NOPR – NAESB 3.0 continued



Capacity Release
− Bidder designation of bidding basis goes away
− Bidder will be required to bid for capacity as posted by
releasing shipper
− ID3 recall
Notices/Offers to purchase release capacity
− Post via “Notices”, Instructions and request template
− Display notice postings of offers to purchase capacity
GRID – OPERATIONAL AVAILABLE CAPACITY
− Addition of “All Quantity” indicator
− For any column that does not have a quantity then must
include a comment/notes as to reason quantity is not
included
46
New Portal Page
 Natural moved to new portal page on July 1, 2015
− Utilizing same format as other Kinder Morgan interstate pipelines
 Highlights:
− Map with key constraint areas reflecting current status
− Operating Capacity
− Total Scheduled Quantity
− Operationally Available Capacity
− Quick access to recent notices & service programs
− Key weather forecasts
− On call assistance information
− Training Videos
 Accessing Training Videos:
− From main page move cursor over “Customer Information” tab at top of page
− Then select “Training Videos”
− 40 “How Do I…” videos.
− Each video is less than 15 minutes
− Covers a range of typical DART activities
− Excellent training tool for new DART users
47
New Portal View
48
48
New Portal – Training Videos
49
49
Questions?
50
Business Development
Jim Lelio, Director
Frank Strong, Director
August 19, 2015
REX-NGPL Moultrie Update
REX completed the expansion of their Moultrie
meter on August 1, 2015
⁻
.635 Bcf/d of meter capacity expanded to 1.75 Bcf/d
New Moultrie
Meter Site
52
REX Pipeline Expansion Summary
Seneca Lateral Expansion - January 2015 In-Service
Antero – 600,000 Dth/d
East-to-West Reversal – August 2015 In-service
Shippers
NGPL Delivery Pt.
Total REX MDQ
Ascent Res. / AEP
450
450
EQT
180
300
Gulfport
175
275
Rice
75
175
TOTAL
880
1,200
Power-Up/Capacity Enhancement Expansion – Q4 2016
In-service
Initial 600,000 Dth/d:
• EQT, Gulfport, EdgeMarc, Jay-Bee
Current Open Season for final 200,000 Dth/d of capacity
53
REX Eastern Receipt Capacity (Clarington)
August 2015
Oct. 2015
Mar ’ 16
Nov. ’16
Receipt Capacity
1.4 Bcf/d
2.8 Bcf/d
4.0 Bcf/d
5.2 Bcf/d
Pipeline Capacity
1.8 Bcf/d
-
-
2.6 Bcf/d
Aug-15
REX Interconnects
MarkWest Seneca
Dominion East
Eureka Hunter
Rice Midstream
TOTAL
(Bcf/d)
0.68
0.22
0.30
0.17
1.37
>
1.37
1.00
0.23
0.25
1.5
>
2.85
0.75
0.40
1.15
>
4.00
0.30
0.48
0.40
1.18
>
5.18
Oct. 2015
ETC Ohio River
Eureka Hunter
Rice Midstream
Mar. 2016
EQT
Rice Midstream
Nov. 2016
Dominion Trans.
EQT Expansion
ETC Rover
* RBN Energy Blog - 06/28/2015
54
Gulf Coast Expansion Drivers
"PRODUCER PUSH“
• REX East-to-West capacity expanding to
between 2.4 - 2.6 Bcf/d
• Alliance shippers seek improved netback
destinations
• Oklahoma producers have shown
increased interest in projects to reach
growth markets
"GULF COAST DEMAND PULL“
• LNG and Industrials are attracting long
term supply via NGPL
• NET Pipeline to Mexico is attracting long
term supply (currently 200/d)
NGPL PROVIDES A CRITICAL LINK:
• Existing southbound shippers extending
contracts ahead of project in-service
dates
• Moultrie receipt point volumes likely to
grow as REX receipt capacity expands
55
Gulf Coast Expansion Summary
Existing Southbound FT Contracts
Executed PA’s for nearly 500
MDth/d
Additional opportunities remain for
future expansion projects
Basic Commercial Terms:
15 – 20 year term
 $.40 - $.45 rate from REX to the Gulf Coast
 flexible start date (ramp up Q1 2017 thru
2019)

56
Midcontinent Production Increasing
13
12
11
10
9
8
7
6
5
4
3
2
1
0
2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Mid-Continent SCOOP and STACK plays: Producers in south central Oklahoma have proven the potential of this oil play.
Associated gas volumes look to increase by 3 Bcf/d of gas by 2020. Volumes will reverse expected declines in the
Mid-Continent region by 2017. Breakeven price is below $70/bbl. Springer shale offers further upside potential.
Source: Wood McKenzie
57
Permian Demand Increasing
 Gas requirements within Mexico are expected to increase to 4.6 –
4.9 Bcf/d by 2020
 Summary of projects CFE has awarded:
− San Elizario Pipeline Project
− Waha area to San Elizario, Texas (Near El Paso, Texas) -- 195 miles of 42”
Pipeline
− 1.220 to 1.475 Bcf/d Capacity
− In Service 1/31/2017
− Presidio Pipeline Project
− Waha area to Presidio, Texas -- 160 miles of 42” Pipeline
− 1.375 Bcf/d Capacity
− In Service 6/30/2017
 Project takeaway capacity to Mexico will increase by 2.6 – 2.8 Bcf/d
with these two pipeline projects
58
NGPL MidCon-to-Permian Expansion
• Volume: Up to 300 MMcf/d
Install new HP
CS 112
HP and add Fuel
Injection
CS 169
Fuel Injection
CS 168
• Receipt Points:
 Amarillo System (REX)
 Segment 10
 JAL
• Delivery Points:
 EPNG or other pipelines
 Waha Header
Gas Cooling
CS 167
CS 139
San Elizario Project
WAHA Area
• Anticipated in Service:
Q1 or Q2 2017
Presidio Project
59
Power Plant Activity

On June 9, 2015, FERC issued an order accepting PJM’s proposal to modify
its forward capacity market, the Reliability Pricing Model (“RPM”), to establish
a new capacity product, the Capacity Performance Resource
− PJM’s proposal is designed to tighten the performance standards
applicable to resources that receive a capacity payment through the RPM
and is intended to address poor resource performance that has been
experienced since implementation of the RPM, especially during the 2014
polar vortex
− Once implemented, PJM’s proposal will impose non-performance charges
when resources fail to perform and bonus payments for over-performance
during PJM emergencies

The issuance of the revised RPM has led to discussions with the gas fired
power plants located in NGPL’s market area for firm transport/storage services

Current Focus is on utilization of existing NGPL services

Longer term, NGPL is committed to working with power plants and their supply
managers on desired and economic service enhancements
60
LNG Activities
 Cheniere Sabine Pass Liquefaction (“SPL”) Update
–
–
NGPL interconnect with SPL is being commissioned presently and LA line enhancements are under
construction for October 1, 2015 in-service to provide service for Trains 1-4 (550 MDth/d Firm sold)
KMLP will provide FTS service for Trains 5 and 6 (600 MDth/d each)
– KMLP will construct compression and interconnect facilities to facilitate flow on a SW path
– Train 5 went FID on July 1, 2015, with anticipated in-service in 2019
– Train 6 has achieved all required construction hurdles, only FID remains
 KMLP - Magnolia LNG Liquefaction Project Update
–
–
–
–

Executed first binding tolling agreement on July 23, 2015 with Port Meridian, indicate they are close
on several others
Magnolia and KMLP FERC filings were linked together as it pertains to environmental impact
DEIS was issued July 17, 2015, final EIS expected in November, FERC certificate by 1Q 2016
Magnolia expects to achieve FID after receipt of FERC certificate, 2Q 2016
Other LNG Projects – Louisiana Region
– Live Oak LNG
– Golden Pass LNG
– Cameron LNG – Trains 4&5
– Lake Charles LNG
61
Chicago Market Expansion Project (CMEP)
Project Scope


Expand NGPL’s Gulf Coast Mainline (GCML) capacity from
the Rockies Express Pipeline (REX) in Moultrie Co., IL to the
Chicago market area
Install a new compressor Station 312 on GCML in lieu of
pipeline looping and associated environmental disturbances
Commercial Update – Phase I




Open Season concluded November 17, 2014
Announced execution of binding agreements with Antero
Resources, Nicor Gas, North Shore Gas and Occidental
Energy on April 14, 2015
 Project subscription included 238 MDth/d of FTS, with an
average term over 11 years
NGPL FERC 7(c) certificate application filed on June 1, 2015,
seeking an order by February 2016 and an expected in
service date of Nov. 1, 2016
 Application and Environmental Reviews ongoing
REX receipt capacity increasing from 635 to 1,750 MDth/d in
August 2015.
Commercial Update – Phase II



Soliciting interest for an additional 200,000 Dth/d expansion
of Sta. 312 with negotiated rates of approx. $.16/dth for a
10-year term
Submit non-binding Open Season Bid Form from Kinder
Morgan Project web site at www.kindermorgan.com
62
Else email CMEP@kindermorgan.com for further details
Interconnects Update
Interconnecting
Company
County/State
R/D
Capacity
(MMcf/d)
Silver Tusk Operating Co. LLC
Marion, TX
R
4
3/23/2015
Muscatine, IA
D
42
7/21/2015
Rockies Express Pipeline
Moultrie, IL
R
1,750
8/18/2015
Sabine Pass Liquefaction
Cameron, LA
D
1,700
8/31/2015
Sabine Pipe Line LLC
Vermilion, LA
R/D
640
9/30/2015
Grady, OK
R
200
2/29/2016
Fort Bend, TX
D
35
3/1/2016
Will, IL
D
324
7/1/2016
Grain Processing
Enable Oklahoma Intrastate
SiEnergy LP
Midwest Generation (NRG)
Actual/Projected
In-Service
2,594/2,741
63
Concluding Remarks
Dave Devine
Jim Brett
August 19, 2015