Welcome 2015 Natural Gas Pipeline Company of America LLC Customer - - PowerPoint PPT Presentation

Welcome

2015 Natural Gas Pipeline Company of America LLC Customer Meeting

Park Hyatt Hotel Chicago, IL August 19, 2015

August 19, 2015

Corporate Overview and Gas Pipeline Group Growth Projects and Opportunities

Tom Martin President, Natural Gas Pipeline Group

 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

• f 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

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__________________________ (a) 2015 budgeted volumes. (b) Excludes terminals contributed to Watco.

Unparalleled Asset Footprint

Largest Energy Infrastructure Company in North America

Weathering the Storm

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 Weathering the High Seas(a)



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

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KMI Stock Perf. Since Oil was Last $90(a)

• 12%

6%

• 22%
• 31%
• 39%
• 53%
• 60%
• 50%
• 40%
• 30%
• 20%
• 10%

0% 10%

S&P 500 Index S&P 500 Energy Alerian Index EPX E&P Index WTI Oil Spot Px.

KMI

__________________________ (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-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 Kinder Morgan Canada 5.4 5.4 Total $1.9 $2.0 $5.3 $12.8 $22.0 Not included in backlog: – TGP Northeast “supply path” – Marcellus/ Utica liquids pipeline solution (UMTP) – Further LNG export opportunities – Potential acquisitions

5-year Project Backlog(a)

$22 Billion of Currently Identified Organic Growth Projects

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__________________________ (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.

Tremendous footprint provides $22B of currently identified growth projects over next 5 years

~90% of backlog is for fee-based pipelines, terminals and associated facilities

Hiland Acquisition:

Strategic Acquisition of Premier Midstream Position in the Bakken

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 Strategic Acquisition: Establishes premier midstream platform in the core of the Bakken, one of the most prolific oil producing basins in North America



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

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__________________________ (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. Tioga, ND Watford City, ND Williston, ND Baker, MT Double H Pipeline Douglas, WY Guernsey, WY Legend(b): Hiland dedication area Gas pipeline Crude pipeline

Natural Gas Megatrend

Strong Natural Gas Footprint & Market Opportunity Set

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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

__________________________ (a) Source: Wood Mackenzie Spring 2015 Long-Term View. (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.

Natural Gas Segment Asset Footprint

Power Generation +5.7/ 8.6 Bcf/d(b) Industrial (petchem) +3.5/ 4.7 Bcf/d(b) LNG Export +7.9/ 11.0 Bcf/d(b) Exports to Mexico +1.7/ 2.9 Bcf/d(b)

 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

Real- time, Long-term Benefits of Footprint

10% 15% 20% 25% 30% 35% 40% 45% 50% 55%

Monthly Share of U.S. Power Generation by Fuel, 2001-15

Coal Natural Gas

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

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Market Growth

TGP Northeast Energy Direct (NED) Project - Market Path

Existing TGP Flow NED Additional Flow



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



Major Milestone:

— FERC certificate application filing 4Q 2015

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Market Growth

TGP Northeast Energy Direct (NED) Project - Supply Path

Marcellus

Existing TGP Flow NED Additional Flow



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:

— Execution of anchor shipper PAs — FERC certificate application filing 4Q 2015

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Gas Transportation for LNG Export

Kinder Morgan Transportation Commitments

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  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 12

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

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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

• n 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

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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  Current Status: — PAs executed — FERC applications filed  Major Milestones: — FERC certificate anticipated

Oct/Nov 2015

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__________________________ (a) Includes the cost ($112 MM) and capacity (436 MDth/d) for the component of the EEC expansion serving Elba Liquefaction. SNG EEC FGT Transco SNG / EEC Expansion

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

• wns 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

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 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

LNG Export - Potential Opportunity

Liquefaction at Gulf LNG

Exports to Mexico

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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

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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

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NGPL Pipeline Operations Review

Danny Ivy VP - Gas Control, Kinder Morgan

August 19, 2015

Pipeline Management

• Operations Review

─ 2014-2015 Weather Review ─ 2015 Transport & Storage Review ─ NGPL Storage Data Summary ─ Maintenance Update

• Winter 2015/2016
• Contact Lists

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NGPL Facility Map

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• 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

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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

Chicago O’Hare HDDs

HDD's % of Normal HDD's % of Normal November 936 126% 819 111% December 1015 88% 1283 111% January 1317 103% 1521 119% February 1405 135% 1329 127% March 910 108% 1025 122% 5583 110% 5977 118% 2014-2015 2013-2014

26

NGPL Storage Data Review

27 Withdrawal Injection

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

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• 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
• utages are also posted on the 20th of each month

NGPL Maintenance Program

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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

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For illustration purposes not to scale

NGPL Impacted Projects

8 5 1 6 8

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?

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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

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NGPL Amarillo Constraints

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Remediation Multiple pig runs At capacity through 801 Make piggable

35

26-inch 36-inch out of service 36-inch 26-inch 36-inch out of service

CS 104 CS 193

CS 193 CS 104 Kansas

712 MAOP Amarillo #3 remediation 6-10 to 6/13 Amarillo #3 remediation 8-6 to 8-7 Amarillo #3 remediation August

2015 FMJ

High Impact Integrity Work Amarillo #3

NGPL 2015 Remaining Maintenance Projects

2 1 3

24” Remediation 156-158

• Expected in November

3

Amarillo #3 36” potential remediation 108-109

• Expected in November

1

AM #3 36” anomaly repair digs

• 103-104 ongoing
• 191-103 expected late August
• 104-105 expected in September
• 105-106 expected in October

2 Summary with Possible Impacts Gulf Coast and Amarillo Systems

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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

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Kinder Morgan 2014 Remaining Maintenance Projects Summary with Possible Impacts Gulf Coast and Amarillo Systems 2 1

7 SCC digs on Permian #1 Expected RTS date: 10-31-2013 AM #2 anomaly repair digs Expected RTS 10-24-2013

2 1

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Winter 2015-2016

• Meet market working inventory target of 116.0 MM Dth
• n/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

NGPL 2015/2016 Contact List

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Gas Control Emer 800-733-2490 24 hr 713-369-9400

#GC-NGPL@kindermorgan.com

Trennis Curry 713-369-9378 Cell 713-819-4577 Bill Weidlein 713-369-9131 Cell 713-204-6432 Danny Ivy 713-369-9311 Cell 713-829-2761 Ray Miller 713-369-9330 Cell 713-206-8338 Transport and Stor Services TSS Hotline 24 hr 713-369-9683 Richard Williams 713-369-9283 Cell 713-819-1748 Gene Nowak 713-369-9329 Cell 713-252-9759 Account Services Dave Weeks 630-725-3030 Cell 630-399-1193 Donette Bisett 713-369-9316 Cell 713-724-6445 Jim Brett 630-725-3040 Cell 630-437-0103 Field Operations Gary Countryman 815-272-9102 Cell 815-302-9879 Dee Bennett- N. Region 815-272-9104 Cell 815-693-0517 Bob Montgomery - W. Region/MEP 806-379-2041 Ext 225 Cell 806-679-0320 Ken Grubb 713-369-8763 Cell 281-702-1210 Gary Buchler 713-369-8463 Cell 713-824-3904 Houston TX Office 713-369-9000 1001 Louisiana St Houston, TX 77002 Downers Grove IL Office 630-725-3000 3250 Lacey Rd Suite 700 Downers Grove, IL 60515

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Gas-Electric Coordination Update

Richard Williams Director – Central Region Transportation/Storage Services

August 19, 2015

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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

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New Cycle Timelines

All times CCT Current Effective 4/1/2016 All times CCT Current Effective 4/1/2016 Timely Timely day-ahead Nom Deadline 11:30 AM 1:00 PM ID2 ID2 Nom Deadline 5:00 PM 2:30 PM Confirmations 3:30 PM 4:30 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 1/2 9/24 Process Time (Nom to Sch) 5 hours 4 hours Process Time (Nom to Sch) 4 hours 3 hours Evening Evening Day-ahead Nom Deadline 6:00 PM 6:00 PM ID3 ID3 Nom Deadline n/a 7:00 PM Confirmations 9:00 PM 8:30 PM Confirmations n/a 9:30 PM Schedule Issued 10:00 PM 9:00 PM Schedule Issued n/a 10:00 PM Start of Gas Flow 9:00 AM 9:00 AM Start of Gas Flow n/a 10:00 PM 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 n/a EPSQ n/a 13/24 Process Time (Nom to Sch) 4 hours 3 hours Process Time (Nom to Sch) n/a 3 hours ID1 ID1 Nom Deadline 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 EPSQ 1/3 5/24 Process Time (Nom to Sch) 4 hours 3 hours

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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.

46

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

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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

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New Portal View

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New Portal – Training Videos

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Questions?

Business Development

August 19, 2015

Jim Lelio, Director Frank Strong, Director

REX completed the expansion of their Moultrie meter on August 1, 2015

⁻

.635 Bcf/d of meter capacity expanded to 1.75 Bcf/d

REX-NGPL Moultrie Update

New Moultrie Meter Site

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REX Pipeline Expansion Summary

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

Seneca Lateral Expansion - January 2015 In-Service

Antero – 600,000 Dth/d

East-to-West Reversal – August 2015 In-service 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 TOTAL (Bcf/d) MarkWest Seneca 0.68 Dominion East 0.22 Eureka Hunter 0.30 Rice Midstream 0.17 1.37 > 1.37

• Oct. 2015

ETC Ohio River 1.00 Eureka Hunter 0.23 Rice Midstream 0.25 1.5 > 2.85

• Mar. 2016

EQT 0.75 Rice Midstream 0.40 1.15 > 4.00

• Nov. 2016

Dominion Trans. 0.30 EQT Expansion 0.48 ETC Rover 0.40 1.18 > 5.18

* RBN Energy Blog - 06/28/2015

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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

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• 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)

Gulf Coast Expansion Summary

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Midcontinent Production Increasing

1 2 3 4 5 6 7 8 9 10 11 12 13 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

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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

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CS 112

Presidio Project San Elizario Project

WAHA Area CS 169 CS 168 CS 167 CS 139 Install new HP

HP and add Fuel Injection

Fuel Injection Gas Cooling

• Volume: Up to 300 MMcf/d
• Receipt Points:

 Amarillo System (REX)  Segment 10  JAL

• Delivery Points:

 EPNG or other pipelines  Waha Header

• Anticipated in Service:

Q1 or Q2 2017

NGPL MidCon-to-Permian Expansion

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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

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• 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

• n 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

LNG Activities

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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
• f 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

• Else email CMEP@kindermorgan.com for further details

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Interconnects Update

Interconnecting Capacity Actual/Projected Company County/State R/D (MMcf/d) In-Service Silver Tusk Operating Co. LLC Marion, TX R 4 3/23/2015 Grain Processing 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 Enable Oklahoma Intrastate Grady, OK R 200 2/29/2016 SiEnergy LP Fort Bend, TX D 35 3/1/2016 Midwest Generation (NRG) Will, IL D 324 7/1/2016 2,594/2,741

63

Dave Devine Jim Brett

August 19, 2015

Concluding Remarks