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

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

4

__________________________

(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

5

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 500Index

S&P 500Energy

AlerianIndex

EPX E&PIndex

WTI OilSpot 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

6

__________________________

(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

7

__________________________

(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

8

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%

Jan'01 Jan'03 Jan'05 Jan'07 Jan'09 Jan'11 Jan'13 Jan'15

% of Total Generation

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

Coal Natural Gas

(c)

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

10

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

11

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

12

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 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

Current Status:

— PAs executed

— FERC applications filed

Major Milestones:

— FERC certificate anticipated

Oct/Nov 2015

16

__________________________

(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

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

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

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

22

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

23

23

NGPL Facility Map

24

• 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

25

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

28

29

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

NGPL Maintenance Program

30

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

31

112

111

102

169

168

167

139

154

184

156

158

159

801

155

812

802

388

304

303

343

346 301

300

341

103

193

104

194

105

106

196 107

195

108 198 109

199

110

116

113

201

311

310

309

308

305

306

342

307

206

803

For illustration purposes not to scale

205

204

203

302

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?

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

34

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

3Amarillo #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

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

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

39

40

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

NGPL 2015/2016 Contact List 41

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

41

42

Gas-Electric Coordination Update Richard Williams

Director – Central Region Transportation/Storage Services

August 19, 2015

43

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

44

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

45

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

47

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

52

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 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

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

56

Midcontinent Production Increasing

0

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 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

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

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

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

LNG Activities

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

Else email CMEP@kindermorgan.com for further details 62

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