[X]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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80-0682103
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Title of each class
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Name of each exchange on which registered
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Class P Common Stock
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New York Stock Exchange
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Warrants to Purchase Class P Common Stock
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New York Stock Exchange
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KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
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C
O
2
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KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS (continued)
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•
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the timing and extent of changes in price trends and overall demand for NGL, refined petroleum products, oil, CO
2
, natural gas, electricity, coal, steel and other bulk materials and chemicals and certain agricultural products in North America;
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•
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economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;
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•
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changes in our tariff rates required by the FERC, the CPUC, Canada’s NEB or another regulatory agency;
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•
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our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities;
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•
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our ability to safely operate and maintain our existing assets and to access or construct new pipeline, gas processing and NGL fractionation capacity;
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•
|
our ability to attract and retain key management and operations personnel;
|
•
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difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;
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•
|
shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;
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•
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changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains and the Alberta, Canada oil sands;
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•
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changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;
|
•
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interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;
|
•
|
the uncertainty inherent in estimating future oil, natural gas, and CO
2
production or reserves that we may experience;
|
•
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the ability to complete expansion projects and construction of our vessels on time and on budget;
|
•
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the timing and success of our business development efforts, including our ability to renew long-term customer contracts;
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•
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changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;
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•
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changes in tax law;
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•
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our ability to offer and sell debt securities, or obtain debt financing in sufficient amounts and on acceptable terms to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;
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•
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our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;
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•
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our ability to obtain insurance coverage without significant levels of self-retention of risk;
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•
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acts of nature, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;
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•
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possible changes in our and our subsidiaries credit ratings;
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•
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capital and credit markets conditions, inflation and fluctuations in interest rates;
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•
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the political and economic stability of the oil producing nations of the world;
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•
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national, international, regional and local economic, competitive and regulatory conditions and developments;
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•
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our ability to achieve cost savings and revenue growth;
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•
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foreign exchange fluctuations;
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•
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the extent of our success in developing and producing CO
2
and oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities;
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•
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engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and workovers, and in drilling new wells; and
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•
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unfavorable results of litigation and the outcome of contingencies referred to in Note 16 “Litigation, Environmental and Other” to our consolidated financial statements.
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•
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For information about our 2014 debt offerings and retirements, see Note 8 “Debt” to our consolidated financial statements. For information about our 2014 equity offerings, see Note 10 “Stockholders’ Equity—Non-Controlling Interests—Contributions” to our consolidated financial statements.
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•
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We expect to declare dividends of $2.00 per share for 2015, a 15% increase over our 2014 declared dividend of $1.74 per share. Growth in 2015 cash dividends is expected to be driven by continued high demand for North American energy infrastructure, including the transportation and storage of natural gas, NGL, crude oil and refined products. Additionally, growth is expected to be driven by contributions from our expansion projects across our business units.
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•
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focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America;
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•
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increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
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•
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leverage economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow; and
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•
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maintain a strong balance sheet and return value to our stockholders.
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•
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Natural Gas Pipelines—(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas and crude oil gathering systems and natural gas processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;
|
•
|
CO
2
—(i) the production, transportation and marketing of CO
2
to oil fields that use CO
2
as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
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•
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Terminals—(i) the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;
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•
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Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
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•
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Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; and
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•
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Other—primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.
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Ownership
Interest %
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|
Miles
of
Pipeline
|
|
Design (Bcf/d) [Storage (Bcf)] Capacity
|
|
Supply and Market Region
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Natural Gas Pipelines
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||||||||
TGP
|
100
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11,900
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|
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9.00
[97]
|
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South Texas and Gulf of Mexico to northeast and southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations
|
EPNG/Mojave pipeline system
|
100
|
|
10,700
|
|
|
5.65
[44]
|
|
Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian, and Anadarko basins
|
NGPL
|
20
|
|
9,200
|
|
|
6.20
[288]
|
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Chicago and other Midwest markets and all central U.S. supply basins
|
SNG
|
100
|
|
6,900
|
|
|
3.90
[68]
|
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Texas, Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama
|
Florida Gas Transmission (Citrus)
|
50
|
|
5,300
|
|
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3.60
|
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Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico
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CIG
|
100
|
|
4,300
|
|
|
5.20
[43]
|
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Colorado and Wyoming; Rocky Mountains and the Anadarko Basin
|
WIC
|
100
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850
|
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3.90
|
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Wyoming, Colorado, and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins
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Ruby pipeline
|
50
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|
680
|
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1.50
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Wyoming to Oregon; Rocky Mountain basins
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MEP
|
50
|
|
510
|
|
|
1.80
|
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Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines
|
CPG
|
100
|
|
410
|
|
|
1.20
|
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Colorado and Kansas, natural gas basins in the Central Rocky Mountain area
|
TransColorado
Gas
|
100
|
|
310
|
|
|
1.00
|
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Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins
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WYCO
|
50
|
|
224
|
|
|
1.20
[7]
|
|
Northeast Colorado; connects with High Plains
|
Elba Express
|
100
|
|
200
|
|
|
0.95
|
|
Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina) and CGT (Georgia).
|
FEP
|
50
|
|
185
|
|
|
2.00
|
|
Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission, and ANR Pipeline Company
|
KM Louisiana
|
100
|
|
135
|
|
|
3.20
|
|
sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines
|
Sierrita pipeline
|
35
|
|
60
|
|
|
0.20
|
|
near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via a new international border crossing with a new natural gas pipeline in Mexico
|
Young Gas Storage
|
48
|
|
17
|
|
|
[6]
|
|
Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities.
|
Keystone Gas Storage
|
100
|
|
12
|
|
|
[9]
|
|
located in the Permian Basin and near the WAHA natural gas trading hub in West Texas.
|
Gulf LNG Holdings
|
50
|
|
5
|
|
|
[7]
|
|
near Pascagoula, Mississippi; connects to four interstate pipelines and natural gas processing plant
|
Bear Creek Storage
|
100
|
|
—
|
|
|
[59]
|
|
50% SNG and 50% TGP
|
|
Ownership
Interest %
|
|
Miles
of
Pipeline
|
|
Design (Bcf/d) [Storage (Bcf)] Capacity
|
|
Supply and Market Region
|
|
SLNG
|
100
|
|
—
|
|
|
[12]
|
|
Georgia; connects to Elba Express, SNG and CGT
|
ELC
|
51
|
|
—
|
|
|
|
|
not in service until 2017 - 2018
|
|
|
|
|
|
|
|
|
|
Midstream group
|
|
|
|
|
|
|
||
KM Texas and
Tejas pipelines(a)
|
100
|
|
5,800
|
|
|
6.20
[120]
|
|
Texas Gulf Coast.
|
Mier-Monterrey
pipeline
|
100
|
|
95
|
|
|
0.65
|
|
Starr County, Texas to Monterrey, Mexico; connects to Pemex NG Transportation system and a 1,000-megawatt power plant
|
KM North Texas
pipeline
|
100
|
|
80
|
|
|
0.33
|
|
interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
|
Copano Oklahoma
|
|
|
|
|
|
|
||
Southern Dome
|
70
|
|
—
|
|
|
0.03
|
|
propane refrigeration plant in the southern portion of Oklahoma county
|
Copano Oklahoma System
|
100
|
|
3,500
|
|
|
0.38
|
|
Hunton Dewatering, Woodford Shale, and Mississippi Lime
|
Copano South Texas
|
|
|
|
|
|
|
||
Webb/Duval gas gathering system
|
63
|
|
145
|
|
|
0.15
|
|
South Texas
|
Copano South Texas System
|
100
|
|
1,255
|
|
|
1.88
|
|
Eagle Ford shale formation, Woodbine and Eaglebine (Texas)
|
EagleHawk
|
25
|
|
860
|
|
|
1.00
|
|
South Texas, Eagle Ford shale formation
|
KM Altamont
|
100
|
|
790
|
|
|
0.08
|
|
Utah, Uinta Basin
|
Red Cedar
|
49
|
|
750
|
|
|
0.70
|
|
La Plata County, Colorado, Ignacio Blanco Field
|
Copano Rocky Mountain
|
|
|
|
|
|
|
||
Fort Union
|
37
|
|
310
|
|
|
1.25
|
|
Powder River Basin (Wyoming)
|
Bighorn
|
51
|
|
290
|
|
|
0.60
|
|
Powder River Basin (Wyoming)
|
KinderHawk
|
100
|
|
500
|
|
|
2.00
|
|
Northwest Louisiana, Haynesville and Bossier shale formations
|
Copano North Texas
|
100
|
|
400
|
|
|
0.14
|
|
North Barnett Shale Combo
|
Endeavor
|
40
|
|
100
|
|
|
0.12
|
|
East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale horizontal well developments
|
Camino Real - Gas
|
100
|
|
70
|
|
|
0.15
|
|
South Texas, Eagle Ford shale formation
|
KM Treating
|
100
|
|
—
|
|
|
—
|
|
Odessa, Texas, other locations in Tyler and Victoria, Texas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(MBbl/d)
|
|
|
|
Copano Liquids
|
|
|
|
|
|
|
|
|
Liberty Pipeline
|
50
|
|
87
|
|
|
170
|
|
Houston Central complex to the Texas Gulf Coast
|
Copano Liquids Assets
|
100
|
|
313
|
|
|
115
|
|
Houston Central complex to the Texas Gulf Coast
|
Camino Real - Oil
|
100
|
|
70
|
|
|
110
|
|
South Texas, Eagle Ford shale formation
|
|
|
|
KM Gross
|
||
|
Working
|
|
Developed
|
||
|
Interest %
|
|
Acres
|
||
SACROC
|
97
|
|
|
49,156
|
|
Yates
|
50
|
|
|
9,576
|
|
Goldsmith Landreth San Andres(a)
|
99
|
|
|
6,166
|
|
Katz Strawn
|
99
|
|
|
7,194
|
|
Sharon Ridge
|
14
|
|
|
2,619
|
|
H.T. Boyd(b)
|
21
|
|
|
n/a
|
|
MidCross
|
13
|
|
|
320
|
|
Reinecke(c)
|
—
|
|
|
80
|
|
(a)
|
Acquired June 1, 2013
|
(b)
|
Net profits interest
|
(c)
|
Working interest less than 1 percent.
|
|
Productive Wells(a)
|
|
Service Wells(b)
|
|
Drilling Wells(c)
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Crude Oil
|
2,164
|
|
|
1,381
|
|
|
1,152
|
|
|
903
|
|
|
2
|
|
|
2
|
|
Natural Gas
|
5
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Wells
|
2,169
|
|
|
1,383
|
|
|
1,152
|
|
|
903
|
|
|
2
|
|
|
2
|
|
(a)
|
Includes active wells and wells temporarily shut-in. As of December 31, 2014, we did not operate any productive wells with multiple completions.
|
(b)
|
Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery.
|
(c)
|
Consists of development wells in the process of being drilled as of December 31, 2014. A development well is a well drilled in an already discovered oil field.
|
|
Year Ended December 31,
|
|||||||
|
2014
|
|
2013
|
|
2012
|
|||
Productive
|
|
|
|
|
|
|||
Development
|
83
|
|
|
51
|
|
|
59
|
|
Exploratory
|
26
|
|
|
4
|
|
|
—
|
|
Total Productive
|
109
|
|
|
55
|
|
|
59
|
|
Dry Exploratory
|
1
|
|
|
—
|
|
|
—
|
|
Total Wells
|
110
|
|
|
55
|
|
|
59
|
|
|
Gross
|
|
Net
|
||
Developed Acres
|
75,111
|
|
|
71,919
|
|
Undeveloped Acres
|
17,603
|
|
|
15,369
|
|
Total
|
92,714
|
|
|
87,288
|
|
|
Ownership
|
|
|
|
|
Interest %
|
|
Source
|
|
Snyder gasoline plant(a)
|
22
|
|
|
The SACROC unit and neighboring CO
2
projects, specifically the Sharon Ridge and Cogdell units
|
Diamond M gas plant
|
51
|
|
|
Snyder gasoline plant
|
North Snyder plant
|
100
|
|
|
Snyder gasoline plant
|
(a)
|
This is a working interest, in addition, we have a 28% net profits interest. The average net to us does not include the value associated with the net profits interest.
|
|
Ownership
Interest %
|
|
Recoverable
CO
2
(Bcf)
|
|
Compression
Capacity (Bcf/d)
|
|
Location
|
|||
Recoverable CO
2
|
|
|
|
|
|
|
|
|||
McElmo Dome unit(a)
|
45
|
|
|
5,900
|
|
|
1.4
|
|
|
Colorado
|
St. Johns CO
2
source field and related assets(b)
|
100
|
|
|
1,660
|
|
|
0.3
|
|
|
Apache County, Arizona, and Catron County, New Mexico
|
Doe Canyon Deep unit(a)
|
87
|
|
|
832
|
|
|
0.2
|
|
|
Colorado
|
Bravo Dome unit
|
11
|
|
|
702
|
|
|
0.3
|
|
|
New Mexico
|
(a)
|
We also operate.
|
(b)
|
Compression installation planned for the fourth quarter of 2018.
|
|
Ownership Interest %
|
|
Miles of Pipeline
|
|
Transport Capacity(Bcf/d)
|
|
Supply and Market Region
|
|||
CO
2
pipelines
|
|
|
|
|
|
|
|
|||
Cortez pipeline
|
50
|
|
|
565
|
|
|
1.2
|
|
|
McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub
|
Central Basin pipeline
|
100
|
|
|
323
|
|
|
0.7
|
|
|
Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines
|
Bravo pipeline(a)
|
13
|
|
|
218
|
|
|
0.4
|
|
|
Bravo Dome to the Denver City, Texas hub
|
Canyon Reef Carriers pipeline
|
98
|
|
|
162
|
|
|
0.3
|
|
|
McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units
|
Centerline CO
2
pipeline
|
100
|
|
|
112
|
|
|
0.3
|
|
|
between Denver City, Texas and Snyder, Texas
|
Eastern Shelf CO
2
pipeline
|
100
|
|
|
91
|
|
|
0.1
|
|
|
between Snyder, Texas and Knox City, Texas
|
Pecos pipeline
|
69
|
|
|
25
|
|
|
0.1
|
|
|
McCamey, Texas, to Iraan, Texas, delivers to the Yates unit
|
Goldsmith Landreth
|
99
|
|
|
3
|
|
|
0.2
|
|
|
Goldsmith Landreth San Andres field in the Permian Basin of West Texas
|
|
|
|
|
|
(MBbl/d)
|
|
|
|||
Crude oil pipeline
|
|
|
|
|
|
|
|
|||
Wink pipeline
|
100
|
|
|
453
|
|
|
145
|
|
|
West Texas to Western Refining’s refinery in El Paso, Texas
|
(a)
|
We do not operate Bravo pipeline.
|
|
Number
|
|
Capacity
(MMBbl)
|
||
Liquids terminals
|
39
|
|
|
78.0
|
|
Bulk terminals
|
78
|
|
|
n/a
|
|
Materials Services locations
|
8
|
|
|
n/a
|
|
Jones Act qualified tankers
|
7
|
|
|
2.3
|
|
|
Ownership Interest %
|
|
Miles of Pipeline
|
|
Number of Terminals (a) or locations
|
|
Terminal Capacity(MMBbl)
|
|
Supply and Market Region
|
||||
Plantation pipeline
|
51
|
|
|
3,182
|
|
|
|
|
|
|
Louisiana to Washington D.C.
|
||
West Coast Products Pipelines(b)
|
|
|
|
|
|
|
|
|
|||||
Pacific (SFPP)
|
100
|
|
|
2,823
|
|
|
13
|
|
|
15.3
|
|
|
six western states
|
Calnev
|
100
|
|
|
570
|
|
|
2
|
|
|
2.1
|
|
|
Colton, CA to Las Vegas, NV; Mojave region
|
West Coast Terminals
|
100
|
|
|
43
|
|
|
6
|
|
|
9.2
|
|
|
Seattle, Portland, San Francisco and Los Angeles areas
|
Cochin pipeline
|
100
|
|
|
1,877
|
|
|
5
|
|
|
1.1
|
|
|
three provinces in Canada and seven states in the U.S.
|
KM Crude & Condensate pipeline
|
100
|
|
|
252
|
|
|
2
|
|
|
1.2
|
|
|
Eagle Ford shale field in South Texas (Dewitt County) to the Houston ship channel refining complex
|
Central Florida pipeline
|
100
|
|
|
206
|
|
|
2
|
|
|
2.5
|
|
|
Tampa to Orlando
|
Double Eagle pipeline
|
50
|
|
|
194
|
|
|
|
|
0.4
|
|
|
Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County
|
|
Parkway
|
50
|
|
|
140
|
|
|
|
|
|
|
interconnect at Collins with Plantation and Plantation markets
|
||
Cypress pipeline
|
50
|
|
|
104
|
|
|
|
|
|
|
Mont Belvieu, Texas to Lake Charles, Louisiana
|
||
Southeast Terminals
|
100
|
|
|
|
|
28
|
|
|
9.1
|
|
|
from Mississippi through Virginia, including Tennessee
|
|
Kinder Morgan Assessment Protocol (KMAP)
|
100
|
|
|
|
|
|
|
|
|
pipeline integrity analysis protocol for KM and outside customers
|
|||
Transmix Operations
|
100
|
|
|
|
|
6
|
|
|
1.5
|
|
|
Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; St. Louis, Missouri; and Greensboro, North Carolina
|
(a)
|
The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
|
(b)
|
Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities.
|
•
|
Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas;
|
•
|
Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and
|
•
|
Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage).
|
|
Price Range
|
|
Declared Cash
Dividends(a)
|
||||||||
|
Low
|
|
High
|
|
|||||||
2014
|
|
|
|
|
|
||||||
First Quarter
|
$
|
30.81
|
|
|
$
|
36.45
|
|
|
$
|
0.42
|
|
Second Quarter
|
32.10
|
|
|
36.50
|
|
|
0.43
|
|
|||
Third Quarter
|
35.20
|
|
|
42.49
|
|
|
0.44
|
|
|||
Fourth Quarter
|
33.25
|
|
|
43.18
|
|
|
0.45
|
|
|||
2013
|
|
|
|
|
|
||||||
First Quarter
|
$
|
35.74
|
|
|
$
|
38.80
|
|
|
$
|
0.38
|
|
Second Quarter
|
35.52
|
|
|
41.49
|
|
|
0.40
|
|
|||
Third Quarter
|
34.54
|
|
|
40.45
|
|
|
0.41
|
|
|||
Fourth Quarter
|
32.30
|
|
|
36.68
|
|
|
0.41
|
|
|||
2012
|
|
|
|
|
|
||||||
First Quarter
|
$
|
31.76
|
|
|
$
|
39.25
|
|
|
$
|
0.32
|
|
Second Quarter
|
30.51
|
|
|
40.25
|
|
|
0.35
|
|
|||
Third Quarter
|
32.03
|
|
|
36.63
|
|
|
0.36
|
|
|||
Fourth Quarter
|
31.93
|
|
|
36.50
|
|
|
0.37
|
|
(a)
|
Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends are paid on or about the 16th day of each February, May, August and November.
|
Our Purchases of Our Class P Shares and Warrants
|
||||||||||||||
Period
|
|
Total number of securities purchased
|
|
Average price paid per security
|
|
Total number of securities purchased as part of publicly announced plans
|
|
Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs(a)
|
||||||
October 1 to October 31, 2014
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
2,452,606
|
|
November 1 to November 30, 2014
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
2,452,606
|
|
December 1 to December 31, 2014
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
2,452,606
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
$
|
2,452,606
|
|
(a)
|
Remaining amount available under a $100 million share and warrant repurchase program approved by our board of directors on March 4, 2014.
|
Five-Year Review
Kinder Morgan, Inc. and Subsidiaries
|
|||||||||||||||||||
|
As of or for the Year Ended December 31,
|
||||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
(In millions, except per share and ratio data)
|
||||||||||||||||||
Income and Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
16,226
|
|
|
$
|
14,070
|
|
|
$
|
9,973
|
|
|
$
|
7,943
|
|
|
$
|
7,852
|
|
Operating income
|
4,448
|
|
|
3,990
|
|
|
2,593
|
|
|
1,423
|
|
|
1,133
|
|
|||||
Earnings (loss) from equity investments
|
406
|
|
|
327
|
|
|
153
|
|
|
226
|
|
|
(274
|
)
|
|||||
Income from continuing operations
|
2,443
|
|
|
2,696
|
|
|
1,204
|
|
|
449
|
|
|
64
|
|
|||||
(Loss) income from discontinued operations, net of tax
|
—
|
|
|
(4
|
)
|
|
(777
|
)
|
|
211
|
|
|
236
|
|
|||||
Net income
|
2,443
|
|
|
2,692
|
|
|
427
|
|
|
660
|
|
|
300
|
|
|||||
Net income (loss) attributable to Kinder Morgan, Inc.
|
1,026
|
|
|
1,193
|
|
|
315
|
|
|
594
|
|
|
(41
|
)
|
|||||
Class P Shares
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Basic and Diluted Earnings Per Common Share From Continuing Operations
|
$
|
0.89
|
|
|
$
|
1.15
|
|
|
$
|
0.56
|
|
|
$
|
0.70
|
|
|
|
||
Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations
|
—
|
|
|
—
|
|
|
(0.21
|
)
|
|
0.04
|
|
|
|
||||||
Total Basic and Diluted Earnings Per Common Share
|
$
|
0.89
|
|
|
$
|
1.15
|
|
|
$
|
0.35
|
|
|
$
|
0.74
|
|
|
|
||
Class A Shares
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Basic and Diluted Earnings Per Common Share From Continuing Operations
|
|
|
|
|
$
|
0.47
|
|
|
$
|
0.64
|
|
|
|
||||||
Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations
|
|
|
|
|
(0.21
|
)
|
|
0.04
|
|
|
|
||||||||
Total Basic and Diluted Earnings Per Common Share
|
|
|
|
|
$
|
0.26
|
|
|
$
|
0.68
|
|
|
|
||||||
Basic Weighted Average Number of Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Class P shares
|
1,137
|
|
|
1,036
|
|
|
461
|
|
|
118
|
|
|
|
||||||
Class A shares
|
|
|
|
|
446
|
|
|
589
|
|
|
|
||||||||
Diluted Weighted Average Number of Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Class P shares
|
1,137
|
|
|
1,036
|
|
|
908
|
|
|
708
|
|
|
|
||||||
Class A shares
|
|
|
|
|
446
|
|
|
589
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Dividends per common share declared for the period(a)(b)
|
$
|
1.74
|
|
|
$
|
1.60
|
|
|
$
|
1.40
|
|
|
$
|
1.05
|
|
|
|
||
Dividends per common share paid in the period(a)
|
1.70
|
|
|
1.56
|
|
|
1.34
|
|
|
0.74
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet Data (at end of period):
|
|
|
|
|
|
|
|
|
|
||||||||||
Net property, plant and equipment
|
$
|
38,564
|
|
|
$
|
35,847
|
|
|
$
|
30,996
|
|
|
$
|
17,926
|
|
|
$
|
17,071
|
|
Total assets
|
83,198
|
|
|
75,185
|
|
|
68,245
|
|
|
30,717
|
|
|
28,908
|
|
|||||
Long-term debt(c)
|
38,312
|
|
|
31,910
|
|
|
29,409
|
|
|
13,261
|
|
|
13,219
|
|
(a)
|
Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year.
|
(b)
|
2011 declared dividend per share was prorated for the portion of the first quarter we were a public company ($0.14 per share). If we had been a public company for the entire year, the 2011 declared dividend would have been $1.20 per share.
|
(c)
|
Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled $1,934 million, $1,977 million, $2,591 million, $1,095 million and $594 million as of December 31, 2014, 2013, 2012, 2011, and 2010, respectively.
|
•
|
helping customers by providing safe and reliable energy, bulk commodity and liquids products transportation, storage and distribution; and
|
•
|
creating long-term value for our shareholders.
|
•
|
Natural Gas Pipelines—(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas and crude oil gathering systems and natural gas processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;
|
•
|
CO
2
—(i) the production, transportation and marketing of CO
2
to oil fields that use CO
2
as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
|
•
|
Terminals—(i) the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;
|
•
|
Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
|
•
|
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; and
|
•
|
Other—primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||
|
|
Net benefit cost (income)
|
|
Change in funded status and pretax accumulated other comprehensive income (loss)
|
|
Net benefit cost (income)
|
|
Change in funded status and pretax accumulated other comprehensive income (loss)
|
||||||||
|
|
(In millions)
|
||||||||||||||
One percent increase in:
|
|
|
|
|
|
|
|
|
||||||||
Discount rates
|
|
$
|
10
|
|
|
$
|
260
|
|
|
$
|
2
|
|
|
$
|
55
|
|
Expected return on plan assets
|
|
(23
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
||||
Rate of compensation increase
|
|
2
|
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
||||
Health care cost trends
|
|
—
|
|
|
—
|
|
|
4
|
|
|
(47
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
One percent decrease in:
|
|
|
|
|
|
|
|
|
||||||||
Discount rates
|
|
(11
|
)
|
|
(312
|
)
|
|
—
|
|
|
(65
|
)
|
||||
Expected return on plan assets
|
|
23
|
|
|
—
|
|
|
4
|
|
|
—
|
|
||||
Rate of compensation increase
|
|
(1
|
)
|
|
12
|
|
|
—
|
|
|
—
|
|
||||
Health care cost trends
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
40
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions)
|
||||||||||
Net Income
|
$
|
2,443
|
|
|
$
|
2,692
|
|
|
$
|
427
|
|
Add/(Subtract):
|
|
|
|
|
|
||||||
Certain items before book tax(a)
|
14
|
|
|
(609
|
)
|
|
1,692
|
|
|||
Book tax certain items
|
(117
|
)
|
|
(39
|
)
|
|
(412
|
)
|
|||
Certain items after book tax
|
(103
|
)
|
|
(648
|
)
|
|
1,280
|
|
|||
Net income before certain items
|
2,340
|
|
|
2,044
|
|
|
1,707
|
|
|||
Add/(Subtract):
|
|
|
|
|
|
||||||
Net income attributable to third-party noncontrolling interests(b)
|
(12
|
)
|
|
(5
|
)
|
|
(1
|
)
|
|||
Depreciation, depletion and amortization(c)
|
2,390
|
|
|
2,142
|
|
|
1,678
|
|
|||
Book taxes(d)
|
840
|
|
|
847
|
|
|
584
|
|
|||
Cash taxes(d)
|
(448
|
)
|
|
(552
|
)
|
|
(460
|
)
|
|||
Declared distributions to noncontrolling interests(e)
|
(2,000
|
)
|
|
(2,355
|
)
|
|
(1,797
|
)
|
|||
Sustaining capital expenditures(f)
|
(509
|
)
|
|
(414
|
)
|
|
(393
|
)
|
|||
Other, net(g)
|
17
|
|
|
6
|
|
|
93
|
|
|||
Subtotal
|
278
|
|
|
(331
|
)
|
|
(296
|
)
|
|||
DCF before certain items
|
$
|
2,618
|
|
|
$
|
1,713
|
|
|
$
|
1,411
|
|
|
|
|
|
|
|
||||||
Weighted Average Shares Outstanding for Dividends(h)
|
1,312
|
|
|
1,040
|
|
|
908
|
|
|||
DCF per share before certain items
|
$
|
2.00
|
|
|
$
|
1.65
|
|
|
$
|
1.55
|
|
Declared dividend per common share
|
1.74
|
|
|
1.60
|
|
|
1.40
|
|
(a)
|
Consists of certain items summarized in footnotes (b) through (e) to the “
—
Consolidated Earnings Results” table included below, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “
—
General and Administrative, Interest, and Noncontrolling Interests.”
|
(b)
|
Represents net income allocated to third-party ownership interests in consolidated subsidiaries other than our former Master Limited Partnerships.
|
(c)
|
Includes DD&A, amortization of excess cost of equity investments and our share of equity method investee’s DD&A of $305 million, $297 million and $236 million in 2014, 2013 and 2012, respectively.
|
(d)
|
Includes our share of equity method investee’s book or cash income taxes.
|
(e)
|
Represents distributions to KMP and EPB limited partner units formerly owned by the public.
|
(f)
|
Includes our share of equity method investee’s sustaining capital expenditures of $(59) million, $(48) million and $(51) million in 2014, 2013 and 2012, respectively.
|
(g)
|
Consists primarily of book to cash timing differences related to certain defined benefit plans and other items, and for periods prior to fourth quarter 2014 includes differences between earnings and cash from our former Master Limited Partnerships.
|
(h)
|
Includes restricted shares that participate in dividends. 2014 includes the shares issued on November 26, 2014 for the Merger Transactions as if outstanding for the entire fourth quarter which differs from our GAAP presentation on our Consolidated Statement of Income.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions)
|
||||||||||
Segment EBDA(a)
|
|
|
|
|
|
||||||
Natural Gas Pipelines
|
$
|
4,259
|
|
|
$
|
4,207
|
|
|
$
|
2,174
|
|
CO
2
|
1,240
|
|
|
1,435
|
|
|
1,322
|
|
|||
Terminals
|
944
|
|
|
836
|
|
|
708
|
|
|||
Products Pipelines
|
856
|
|
|
602
|
|
|
668
|
|
|||
Kinder Morgan Canada
|
182
|
|
|
424
|
|
|
229
|
|
|||
Other
|
13
|
|
|
(5
|
)
|
|
7
|
|
|||
Total Segment EBDA(b)
|
7,494
|
|
|
7,499
|
|
|
5,108
|
|
|||
DD&A expense
|
(2,040
|
)
|
|
(1,806
|
)
|
|
(1,419
|
)
|
|||
Amortization of excess cost of equity investments
|
(45
|
)
|
|
(39
|
)
|
|
(23
|
)
|
|||
Other revenues
|
36
|
|
|
36
|
|
|
35
|
|
|||
General and administrative expenses(c)
|
(610
|
)
|
|
(613
|
)
|
|
(929
|
)
|
|||
Interest expense, net of unallocable interest income(d)
|
(1,807
|
)
|
|
(1,688
|
)
|
|
(1,441
|
)
|
|||
Income from continuing operations before unallocable income taxes
|
3,028
|
|
|
3,389
|
|
|
1,331
|
|
|||
Unallocable income tax expense
|
(585
|
)
|
|
(693
|
)
|
|
(127
|
)
|
|||
Income from continuing operations
|
2,443
|
|
|
2,696
|
|
|
1,204
|
|
|||
Loss from discontinued operations, net of tax(e)
|
—
|
|
|
(4
|
)
|
|
(777
|
)
|
|||
Net income
|
2,443
|
|
|
2,692
|
|
|
427
|
|
|||
Net income attributable to noncontrolling interests
|
(1,417
|
)
|
|
(1,499
|
)
|
|
(112
|
)
|
|||
Net income attributable to Kinder Morgan, Inc.
|
$
|
1,026
|
|
|
$
|
1,193
|
|
|
$
|
315
|
|
(a)
|
Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other income (expense). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the years ended December 31, 2014, 2013 and 2012 were $63 million, $49 million and $12 million, respectively.
|
(b)
|
2014, 2013 and 2012 amounts include decrease in earnings of $45 million, increase in earnings of $573 million, and decrease in earnings of $295 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.
|
(c)
|
2014 and 2013 amounts include decrease to expense of $28 million and $8 million, and 2012 amount includes increase in expense of $366 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items related to general and administrative expenses disclosed below in “
—
General and Administrative, Interest, and Noncontrolling Interests.”
|
(d)
|
2014 and 2013 amounts include decrease in expense of $3 million and $32 million and 2012 amount includes increase in expense of $87 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items related to interest expense, net of unallocable interest income disclosed below in “
—
General and Administrative, Interest, and Noncontrolling Interests.”
|
(e)
|
2013 amount represents an incremental loss related to the sale of our FTC Natural Gas Pipelines disposal group effective November 1, 2012. 2012 amount includes a combined $937 million loss from the remeasurement of net assets to fair value and the sale of our disposal group and DD&A expense of $7 million.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions, except operating statistics)
|
||||||||||
Revenues(a)(c)
|
$
|
10,168
|
|
|
$
|
8,617
|
|
|
$
|
5,230
|
|
Operating expenses
|
(6,241
|
)
|
|
(5,235
|
)
|
|
(3,111
|
)
|
|||
Other income (expense)
|
(5
|
)
|
|
24
|
|
|
(14
|
)
|
|||
Earnings from equity investments
|
318
|
|
|
232
|
|
|
52
|
|
|||
Interest income and Other, net
|
25
|
|
|
578
|
|
|
22
|
|
|||
Income tax expense
|
(6
|
)
|
|
(9
|
)
|
|
(5
|
)
|
|||
EBDA from continuing operations(b)
|
4,259
|
|
|
4,207
|
|
|
2,174
|
|
|||
Discontinued operations(c)
|
—
|
|
|
(4
|
)
|
|
(770
|
)
|
|||
Certain items(a)(b)(c)
|
(190
|
)
|
|
(486
|
)
|
|
1,139
|
|
|||
EBDA before certain items
|
$
|
4,069
|
|
|
$
|
3,717
|
|
|
$
|
2,543
|
|
|
|
|
|
|
|
||||||
Change from prior period
|
Increase/(Decrease)
|
|
|
||||||||
Revenues before certain items(a)
|
$
|
1,339
|
|
|
$
|
3,176
|
|
|
|
||
EBDA before certain items
|
$
|
352
|
|
|
$
|
1,174
|
|
|
|
||
|
|
|
|
|
|
||||||
Natural gas transport volumes (BBtu/d)(d)
|
32,627
|
|
|
30,647
|
|
|
31,650
|
|
|||
Natural gas sales volumes (BBtu/d)(e)
|
2,334
|
|
|
2,458
|
|
|
2,402
|
|
|||
Natural gas gathering volumes (BBtu/d)(f)
|
3,080
|
|
|
2,959
|
|
|
2,996
|
|
(a)
|
2014 amount includes a $198 million increase in revenue and earnings associated with the early termination charge of a long-term natural gas transportation contract from a certain customer on our Kinder Morgan Louisiana pipeline system. 2014 and 2013 amounts include $2 million and $16 million decreases, respectively, related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales.
|
(b)
|
2014 and 2013 amounts include $190 million and $490 million increases in earnings and 2012 amount includes a $202 million decrease in earnings, respectively, related to the combined effect from certain items. 2014 amount consists of (i) $198 million increase in earnings related to the early termination of a natural gas transportation contact, as described in footnote (a); (ii) $3 million loss related to sale of certain Gulf Coast offshore and onshore TGP supply facilities; and (iii) a combined $5 million decrease in earnings from other certain items. 2013 amount consists of (i) a $558 million gain from the remeasurement of a previously held 50% equity interest in Eagle Ford to fair value; (ii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iii) a
$16 million decrease in earnings related to derivative contracts, as described in footnote (a); and (iv) a combined $23 million decrease in earnings from other certain items. 2013 and 2012 amounts include $65 million and $200 million, respectively, non-cash equity investment impairment charges related to our 20% ownership interest in NGPL Holdco LLC. 2012 amount also consists of a combined $2 million decrease in earnings from other certain items.
|
(c)
|
Represents EBDA attributable to the FTC Natural Gas Pipelines disposal group. 2013 amount represents a loss from the sale of net assets. 2012 amount includes (i) a combined loss of $937 million from the remeasurement of net assets to fair value and the sale of net assets; (ii) $167 million of EBDA (which included revenues of $227 million); and (iii) $7 million of DD&A expense from discontinued operations.
|
(d)
|
Includes pipeline volumes for TransColorado Gas Transmission Company LLC, MEP, Kinder Morgan Louisiana Pipeline LLC, FEP, TGP, EPNG, Copano South Texas, the Texas intrastate natural gas pipeline group, CIG, WIC, CPG, SNG, Elba Express, NGPL, Citrus and Ruby Pipeline, L.L.C. Volumes for acquired pipelines are included for all periods. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.
|
(e)
|
Represents volumes for the Texas intrastate natural gas pipeline group.
|
(f)
|
Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.
|
(a)
|
On May 1, 2013, as part of Copano acquisition, we acquired the remaining 50% interest of Eagle Ford. Prior to that date, we recorded earnings from Eagle Ford under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput).
|
(b)
|
Equity investment.
|
•
|
increase of $163 million from full year ownership of our Copano operations, which we acquired effective May 1, 2013, including benefits from higher gathering volumes from the Eagle Ford Shale;
|
•
|
increase of $121 million (15%) from TGP primarily due to higher revenues from (i) firm transportation and storage services due largely to new expansion projects placed in service in the latter part of 2013 and during 2014 and (ii) usage and interruptible transportation services due to weather-related demand relative to 2013. Partially offsetting the increase in 2014 revenues were higher operating and franchise tax expenses in 2014, and a favorable operational sales margin in 2013;
|
•
|
increase of $37 million (10%) from EPNG, primarily driven by higher transportation revenues and throughput due to increased deliveries to California for storage refill and increased demand in Mexico. The increase in revenues was partially offset by higher field operation and maintenance expenses;
|
•
|
increase of $18 million (199%) from Ruby due largely to higher contracted firm transportation revenues and lower interest expense;
|
•
|
increase of $13 million (15%) from Citrus assets, primarily due to higher transportation revenues and reduction in property taxes;
|
•
|
increase of $11 million (3%) from Texas Intrastate Natural Gas Pipeline Group (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems), due largely to higher natural gas sales and transportation margins driven by higher volumes, additional customer contracts and colder weather in the first quarter of 2014, which were offset by lower processing margin due to non-renewal of a certain contract;
|
•
|
decrease of $24 million (17%) from WIC, primarily due to lower reservation revenue as a result of rate reductions pursuant to its FERC Section 5 rate settlement effective November 1, 2013 and lower rates on contract renewals; and
|
•
|
decrease of $17 million (4%) from SNG, driven by lower reservation and usage revenues due to rate reductions pursuant to its rate case settlement effective September 1, 2013; partially offset by incremental revenues from increased firm transportation services and revenue related to an expansion project that was placed in service in late 2013.
|
(a)
|
On May 1, 2013, as part of our Copano acquisition, we acquired the remaining 50% interest of Eagle Ford. Prior to that date, we recorded earnings from Eagle Ford under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput).
|
(b)
|
Equity investment.
|
(c)
|
Represents amounts attributable to the FTC Natural Gas Pipelines disposal group.
|
•
|
incremental earnings of $1,043 million associated with full-year contributions from assets acquired from EP, which was acquired effective May 25, 2012, including earnings from TGP, EPNG, SNG, CIG, SLNG, WIC, EP midstream asset operations, Elba Express, CPG and Citrus; and
|
•
|
incremental earnings of $289 million from the Copano operations, which we acquired effective May 1, 2013.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions, except operating statistics)
|
||||||||||
Revenues(a)
|
$
|
1,960
|
|
|
$
|
1,857
|
|
|
$
|
1,677
|
|
Operating expenses
|
(494
|
)
|
|
(439
|
)
|
|
(381
|
)
|
|||
Other (loss) income
|
(243
|
)
|
|
—
|
|
|
7
|
|
|||
Earnings from equity investments
|
25
|
|
|
24
|
|
|
25
|
|
|||
Interest income and Other, net
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Income tax expense
|
(8
|
)
|
|
(7
|
)
|
|
(5
|
)
|
|||
EBDA(b)
|
1,240
|
|
|
1,435
|
|
|
1,322
|
|
|||
Certain items(a)(b)
|
218
|
|
|
(3
|
)
|
|
4
|
|
|||
EBDA before certain items
|
$
|
1,458
|
|
|
$
|
1,432
|
|
|
$
|
1,326
|
|
|
|
|
|
|
|
||||||
Change from prior period
|
Increase/(Decrease)
|
|
|
||||||||
Revenues before certain items(a)
|
$
|
81
|
|
|
$
|
166
|
|
|
|
||
EBDA before certain items
|
$
|
26
|
|
|
$
|
106
|
|
|
|
||
|
|
|
|
|
|
||||||
Southwest Colorado CO
2
production (gross) (Bcf/d)(c)
|
1.3
|
|
|
1.2
|
|
|
1.2
|
|
|||
Southwest Colorado CO
2
production (net) (Bcf/d)(c)
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|||
SACROC oil production (gross)(MBbl/d)(d)
|
33.2
|
|
|
30.7
|
|
|
29.0
|
|
|||
SACROC oil production (net)(MBbl/d)(e)
|
27.6
|
|
|
25.5
|
|
|
24.1
|
|
|||
Yates oil production (gross)(MBbl/d)(d)
|
19.5
|
|
|
20.4
|
|
|
20.8
|
|
|||
Yates oil production (net)(MBbl/d)(e)
|
8.8
|
|
|
9.0
|
|
|
9.3
|
|
|||
Katz oil production (gross)(MBbl/d)(d)
|
3.6
|
|
|
2.7
|
|
|
1.7
|
|
|||
Katz oil production (net)(MBbl/d)(e)
|
3.0
|
|
|
2.2
|
|
|
1.4
|
|
|||
Goldsmith Landreth oil production (gross)(MBbl/d)(d)
|
1.3
|
|
|
0.7
|
|
|
—
|
|
|||
Goldsmith Landreth oil production (net)(MBbl/d)(e)
|
1.1
|
|
|
0.6
|
|
|
—
|
|
|||
NGL sales volumes (net)(MBbl/d)(e)
|
10.1
|
|
|
9.9
|
|
|
9.5
|
|
|||
Realized weighted-average oil price per Bbl(f)
|
$
|
88.41
|
|
|
$
|
92.70
|
|
|
$
|
87.72
|
|
Realized weighted-average NGL price per Bbl(g)
|
$
|
41.87
|
|
|
$
|
46.43
|
|
|
$
|
50.95
|
|
(a)
|
2014 and 2013 amounts include unrealized gains of $25 million and $3 million, and 2012 amount includes unrealized losses of $11 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.
|
(b)
|
2014 amount includes certain items of a $218 million decrease in earnings (consists of impairment charge of $235 million related primarily to the Katz Strawn unit, an exploration charge of $8 million related to our Wolfcamp operation and a $25 million gain discussed in footnote (a) above). 2013 amount includes a $3 million increase in earnings discussed in footnote (a) above. 2012 amount includes $4 million decrease in earnings (consists of $11 million loss discussed in footnote (a) above and $7 million gain from the sale of our ownership interest in the Claytonville oil field unit), respectively.
|
(c)
|
Includes McElmo Dome and Doe Canyon sales volumes.
|
(d)
|
Represents 100% of the production from the field. We own approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the Goldsmith Landreth unit.
|
(e)
|
Net after royalties and outside working interests.
|
(f)
|
Includes all crude oil production properties.
|
(g)
|
Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.
|
•
|
EBDA increase of $56 million (14%) driven primarily by higher revenues (described following), partly offset by higher labor costs, power costs, property taxes and severance taxes; and
|
•
|
a revenue increase of $59 million (13%) driven primarily by an increase of 8% in average CO
2
contract prices. The increase in contract prices were due primarily to two factors: (i) a change in the mix of contracts resulting in more CO
2
being delivered under higher price contracts and (ii) heavier weighting of new CO
2
contract prices to the price of crude oil. CO
2
volumes were also higher by 7% when compared to the period in 2013, primarily due to expansion projects at our Doe Canyon field placed in service in the fourth quarter of 2013.
|
•
|
EBDA decrease of $30 million (3%) driven by higher operating expenses as a result of (i) incremental well work costs at our recently acquired Goldsmith Landreth unit; (ii) increased power costs; and (iii) higher property and severance tax expenses related to higher revenues (described following). Also contributing to lower EBDA for the comparable period was lower crude oil and NGL prices, which were offset by improved net crude oil production of 8%; and
|
•
|
a $26 million (2%) increase in revenues, driven primarily by
an 8% increase in crude oil sales volumes. The increase in sales volumes was due primarily to higher production at the Katz unit, incremental production from the Goldsmith Landreth unit (acquired effective June 1, 2013), and higher production at the SACROC unit (volumes presented in the results of operations table above). The increase in revenues was offset in part by a 5% decrease in the realized weighted average price per barrel of crude oil and a 10% decrease in NGL prices.
|
•
|
EBDA increase of $74 million (8%) was driven by (i) a $144 million (11%) increase in crude oil sales revenues, due primarily to higher average realized sales prices for U.S. crude oil and partly due to higher oil sales volumes. Our realized weighted average price per barrel of crude oil increased 6% in 2013 versus 2012. The overall increase in oil sales revenues were also favorably impacted by a 7% increase in crude oil sales volumes, due primarily to both higher
|
•
|
EBDA increase of $32 million (9%) and revenue increase of $40 million (10%) were primarily driven by (i) higher CO
2
sales revenues, due to an almost 10% increase in average sales prices; (ii) higher reimbursable project revenues, largely related to the completion of prior expansion projects on the Central Basin pipeline system; and (iii) higher third party storage revenues at the Yates field unit.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions, except operating statistics)
|
||||||||||
Revenues(a)
|
$
|
1,718
|
|
|
$
|
1,410
|
|
|
$
|
1,359
|
|
Operating expenses
|
(746
|
)
|
|
(657
|
)
|
|
(685
|
)
|
|||
Other (expense) income
|
(29
|
)
|
|
74
|
|
|
14
|
|
|||
Earnings from equity investments
|
18
|
|
|
22
|
|
|
21
|
|
|||
Interest income and Other, net
|
12
|
|
|
1
|
|
|
2
|
|
|||
Income tax expense
|
(29
|
)
|
|
(14
|
)
|
|
(3
|
)
|
|||
EBDA(a)
|
944
|
|
|
836
|
|
|
708
|
|
|||
Certain items, net(a)
|
35
|
|
|
(38
|
)
|
|
44
|
|
|||
EBDA before certain items
|
$
|
979
|
|
|
$
|
798
|
|
|
$
|
752
|
|
|
|
|
|
|
|
||||||
Change from prior period
|
Increase/(Decrease)
|
|
|
||||||||
Revenues before certain items(a)
|
$
|
298
|
|
|
$
|
43
|
|
|
|
||
EBDA before certain items
|
$
|
181
|
|
|
$
|
46
|
|
|
|
||
|
|
|
|
|
|
||||||
Bulk transload tonnage (MMtons)(b)
|
88.0
|
|
|
89.9
|
|
|
97.5
|
|
|||
Ethanol (MMBbl)
|
71.8
|
|
|
65.0
|
|
|
65.3
|
|
|||
Liquids leaseable capacity (MMBbl)
|
78.0
|
|
|
68.0
|
|
|
60.4
|
|
|||
Liquids utilization %(c)
|
95.3
|
%
|
|
94.6
|
%
|
|
92.8
|
%
|
(a)
|
2014 amount includes (i) an $18 million increase in revenues from the amortization of deferred credits (associated with below market contracts assumed upon acquisition) from our Jones Act tankers acquired effective January 17, 2014 (APT acquisition); (ii) a $29 million write-down associated with a pending sale of certain terminals to a third-party; (iii) a $12 million increase in expenses due to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals; and (iv) a $12 million increase in expense associated with a liability adjustment related to a certain litigation matter. 2013 amount includes (i) a $109 million increase in earnings from casualty indemnification gains; (ii) a $59 million increase in clean-up and repair expense, all related to 2012 hurricane activity at the New York Harbor and Mid-Atlantic terminals; and (iii) a combined $12 million decrease of earnings from other certain items (which includes a $8 million increase in revenues related to hurricane reimbursements). 2012 amount includes a $51 million increase in expense related to hurricanes Sandy and Isaac clean-up and repair activities and the associated write-off of damaged assets, a $12 million casualty indemnification gain related to a 2010 casualty at the Myrtle Grove, Louisiana, International Marine Terminal facility and a combined $5 million decrease of earnings from other certain items.
|
(b)
|
Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage.
|
(c)
|
The ratio of our actual leased capacity to its estimated potential capacity.
|
•
|
increase of $66 million from acquired assets and businesses, primarily the acquisition of the Jones Act tankers;
|
•
|
increase of $32 million (45%) from our West region terminals, driven by the completion of Edmonton expansion projects;
|
•
|
increase of $30 million (213%) from our Gulf Central terminals, driven by higher earnings from our 55% owned Battleground Oil Specialty Terminal Company LLC (BOSTCO) oil terminal joint venture, which is located on the Houston Ship Channel and began operations in October 2013;
|
•
|
increase of $20 million (10%) from our Gulf Liquids terminals, due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services and new and incremental customer agreements at higher rates, due in part to new tankage from completed expansion projects;
|
•
|
increase of $19 million (25%) from our Gulf Bulk terminals, driven by increased revenue from take-or-pay coal contracts and higher petcoke period-to-period volumes in 2014, due largely to refinery and coker shutdowns in 2013 as a result of turnarounds taken; and
|
•
|
increase of $14 million (3%) from the rest of the terminal operations was driven primarily by increased shortfall revenue recognized on take-or-pay contracts at out International Marine Terminal in Myrtle Grove, Louisiana and earnings from the BP Whiting terminal in Whiting, Indiana which was placed in service in the third quarter of 2013.
|
Year Ended December 31, 2013 versus Year Ended December 31, 20
|
|||||||||||
|
EBDA
increase/(decrease)
|
|
Revenues
increase/(decrease)
|
||||||||
|
(In millions, except percentages)
|
||||||||||
Gulf Liquids
|
$
|
21
|
|
|
11%
|
|
$
|
34
|
|
|
14%
|
Rivers
|
15
|
|
|
24%
|
|
7
|
|
|
5%
|
||
Midwest
|
9
|
|
|
18%
|
|
14
|
|
|
11%
|
||
All others (including intrasegment eliminations and unallocated income tax expenses)
|
1
|
|
|
—%
|
|
(12
|
)
|
|
1%
|
||
Total Terminals
|
$
|
46
|
|
|
6%
|
|
$
|
43
|
|
|
3%
|
•
|
increase of $21 million (11%) from our Gulf Liquids terminals, primarily due to higher liquids revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services, and new and incremental customer agreements at higher rates. For all terminals included in the Terminals business segment, total liquids leaseable capacity increased to 68.0 MMBbl at year-end 2013, up 12.6% from a capacity of
60.4 MMBbl at the end of 2012. The increase in capacity was mainly due to the acquisition of Norfolk and Chesapeake, Virginia facilities from Allied Terminals in June 2013 (incremental contributions from these two terminals are included within the “All others” line in the table above), and the partial in-service of BOSTCO and Edmonton Tank expansion projects. At the same time, Terminals’ overall liquids utilization rate increased
1.8% since the end of 2012;
|
•
|
increase of $15 million (24%) from our Rivers region terminals due to the IMT Phase I and II expansion projects at International Marine Terminal (located at Myrtle Grove, Louisiana, near the mouth of the Mississippi River) being placed in service in March 2013. The region also benefited from lower operating and maintenance costs; and
|
•
|
increase of $9 million (18%) from our Midwest region terminals, primarily driven by the opening of the BP Whiting terminal (Whiting Indiana) in August 2013. Salt and ethanol volumes increases also contributed to the overall improvement.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions, except operating statistics)
|
||||||||||
Revenues
|
$
|
2,068
|
|
|
$
|
1,853
|
|
|
$
|
1,370
|
|
Operating expenses
|
(1,258
|
)
|
|
(1,295
|
)
|
|
(759
|
)
|
|||
Other income (expense)
|
3
|
|
|
(6
|
)
|
|
5
|
|
|||
Earnings from equity investments
|
44
|
|
|
45
|
|
|
39
|
|
|||
Interest income and Other, net
|
1
|
|
|
3
|
|
|
11
|
|
|||
Income tax (expense) benefit
|
(2
|
)
|
|
2
|
|
|
2
|
|
|||
EBDA(a)
|
856
|
|
|
602
|
|
|
668
|
|
|||
Certain items, net(a)
|
4
|
|
|
182
|
|
|
35
|
|
|||
EBDA before certain items
|
$
|
860
|
|
|
$
|
784
|
|
|
$
|
703
|
|
|
|
|
|
|
|
||||||
Change from prior period
|
Increase/(Decrease)
|
|
|
||||||||
Revenues
|
$
|
215
|
|
|
$
|
483
|
|
|
|
||
EBDA before certain items
|
$
|
76
|
|
|
$
|
81
|
|
|
|
||
|
|
|
|
|
|
||||||
Gasoline (MMBbl) (b)
|
451.8
|
|
|
423.4
|
|
|
395.3
|
|
|||
Diesel fuel (MMBbl)
|
151.5
|
|
|
142.4
|
|
|
141.5
|
|
|||
Jet fuel (MMBbl)
|
113.3
|
|
|
110.6
|
|
|
110.6
|
|
|||
Total refined product volumes (MMBbl)(c)
|
716.6
|
|
|
676.4
|
|
|
647.4
|
|
|||
NGL (MMBbl)(d)
|
35.2
|
|
|
37.3
|
|
|
31.7
|
|
|||
Condensate (MMBbl)(e)
|
36.8
|
|
|
12.6
|
|
|
1.4
|
|
|||
Total delivery volumes (MMBbl)
|
788.6
|
|
|
726.3
|
|
|
680.5
|
|
|||
Ethanol (MMBbl)(f)
|
41.6
|
|
|
38.7
|
|
|
33.1
|
|
(a)
|
2014 amount includes a $4 million increase in expense associated with a certain Pacific operations litigation matter. 2013 amount includes (i) a $162 million increase in expense associated with rate case liability adjustments; (ii) a $15 million increase in expense associated with a legal liability adjustment related to a certain West Coast terminal environmental matter; and (iii) $5 million loss from the write-off of assets at our Los Angeles Harbor West Coast terminal. 2012 amount includes a $32 million increase in expense associated with environmental liability and environmental recoverable receivable adjustments and a combined $3 million decrease in earnings from other certain items.
|
(b)
|
Volumes include ethanol pipeline volumes.
|
(c)
|
Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes.
|
(d)
|
Includes Cochin and Cypress pipeline volumes.
|
(e)
|
Includes Kinder Morgan Crude & Condensate and Double Eagle Pipeline LLC pipeline volumes.
|
(f)
|
Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.
|
•
|
increase of $67 million (320%) from Kinder Morgan Crude & Condensate Pipeline, driven primarily by an increase of pipeline throughput volumes to 81.0 MBbl/d as compared to 24.1 MBbl/d in 2013 (236%);
|
•
|
increase of $36 million (13%) from our Pacific operations, due to higher service revenues driven by higher volumes and margins and lower operating expenses primarily due to lower rights-of-way expenses; and
|
•
|
decrease of $19 million (44%) from our transmix processing operations, primarily driven by unfavorable inventory pricing.
|
Year Ended December 31, 2013 versus Year Ended December 31, 2012
|
|||||||||||
|
EBDA
increase/(decrease)
|
|
Revenues
increase/(decrease)
|
||||||||
|
(In millions, except percentages)
|
||||||||||
Transmix operations
|
$
|
27
|
|
|
174%
|
|
$
|
406
|
|
|
82%
|
Cochin Pipeline
|
25
|
|
|
34%
|
|
33
|
|
|
42%
|
||
Crude & Condensate Pipeline
|
14
|
|
|
n/a
|
|
19
|
|
|
n/a
|
||
All others (including eliminations)
|
15
|
|
|
2%
|
|
25
|
|
|
3%
|
||
Total Products Pipelines
|
$
|
81
|
|
|
12%
|
|
$
|
483
|
|
|
35%
|
•
|
a $27 million (174%) increase from our transmix processing operations due to higher margins on processing volumes, incremental earnings from third-party sales of excess renewable identification numbers (RINS) (generated through its ethanol blending operations), and the recognition of unfavorable net carrying value adjustments to product inventory recognized in 2012. The period-to-period increases in revenues were mainly due to the expiration of certain transmix fee-based processing agreements since the end of the third quarter of 2012. Due to the expiration of these contracts, we now directly purchase incremental transmix volumes and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;
|
•
|
a $25 million (34%) increase from Cochin Pipeline primarily due to higher transportation revenues, driven by an overall 33% increase in pipeline throughput volumes, partly attributable to incremental ethane/propane volumes as a result of pipeline modification projects completed in June 2012;
|
•
|
incremental earnings of $14 million from Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes from the Eagle Ford shale gas formation to multiple terminaling facilities along the Texas Gulf Coast in October 2012; and
|
•
|
a $15 million (2%) increase from all other represents a number of small increases at various locations.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions, except operating statistics)
|
||||||||||
Revenues
|
$
|
291
|
|
|
$
|
302
|
|
|
$
|
311
|
|
Operating expenses
|
(106
|
)
|
|
(110
|
)
|
|
(103
|
)
|
|||
Earnings from equity investments
|
—
|
|
|
4
|
|
|
5
|
|
|||
Interest income and Other, net
|
15
|
|
|
249
|
|
|
17
|
|
|||
Income tax expense
|
(18
|
)
|
|
(21
|
)
|
|
(1
|
)
|
|||
EBDA(a)
|
182
|
|
|
424
|
|
|
229
|
|
|||
Certain items, net(a)
|
—
|
|
|
(224
|
)
|
|
—
|
|
|||
EBDA before certain items
|
$
|
182
|
|
|
$
|
200
|
|
|
$
|
229
|
|
|
|
|
|
|
|
||||||
Change from prior period
|
Increase/(Decrease)
|
|
|
||||||||
Revenues
|
$
|
(11
|
)
|
|
$
|
(9
|
)
|
|
|
||
EBDA before certain items
|
$
|
(18
|
)
|
|
$
|
(29
|
)
|
|
|
||
|
|
|
|
|
|
||||||
Transport volumes (MMBbl)(b)
|
106.8
|
|
|
101.1
|
|
|
106.1
|
|
(a)
|
2013 amount includes a $224 million pre-tax gain from the sale of our equity and debt investments in the Express pipeline system.
|
(b)
|
Represents Trans Mountain pipeline system volumes.
|
(a)
|
Amount consists of unrealized foreign currency gains/losses, net of book tax, on outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013.
|
(a)
|
We sold our debt and equity investments in Express Pipeline on March 14, 2013. Prior to the sale, the earnings from Express Pipeline were recorded under the equity method of accounting.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(In millions)
|
||||||||||
General and administrative expense(a)(c)
|
$
|
610
|
|
|
$
|
613
|
|
|
$
|
929
|
|
Certain items(a)
|
28
|
|
|
8
|
|
|
(366
|
)
|
|||
Management fee reimbursement(c)
|
(36
|
)
|
|
(36
|
)
|
|
(35
|
)
|
|||
General and administrative expense before certain items
|
$
|
602
|
|
|
$
|
585
|
|
|
$
|
528
|
|
Unallocable interest expense net of interest income and other, net(b)
|
$
|
1,807
|
|
|
$
|
1,688
|
|
|
$
|
1,441
|
|
Certain items(b)
|
3
|
|
|
32
|
|
|
(87
|
)
|
|||
Unallocable interest expense net of interest income and other, net, before certain items
|
$
|
1,810
|
|
|
$
|
1,720
|
|
|
$
|
1,354
|
|
Net income attributable to noncontrolling interests
|
$
|
1,417
|
|
|
$
|
1,499
|
|
|
$
|
112
|
|
(a)
|
2014 amount includes a decrease in expense of $39 million related to pension credit income and a net increase of $11 million in expense for various other certain items. 2013 amount includes a decrease in expense of $59 million related to EP post-merger pension credits, partially offset by increases in expense of (i) $41 million related to asset and business acquisition costs and unallocated legal expenses and (ii) combined $10 million from other certain items primarily related to the EP acquisition. 2012 amount includes $366 million increase of pre-tax expense associated with the EP acquisition and EP Energy sale, which includes (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million for legal fees and reserves, net of recoveries;
|
(b)
|
2014, 2013 and 2012 amounts include $9 million, $21 million and $108 million of amortization of capitalized financing fees, almost all of which was associated with the EP acquisition financing. 2012 also includes amounts written-off due to debt repayment. 2014, 2013 and 2012 amounts include (i) $12 million, $14 million and $9 million, respectively, of interest expense on margin for marketing contracts and (ii) $65 million, $67 million and $29 million, respectively, of decreased interest expense related to debt fair value adjustments associated with the EP and Copano acquisitions. 2014 amount includes (i) $27 million of interest expense related to the Merger Transactions; and (ii) an increase in interest expense of $15 million associated with a certain Pacific operations litigation matter. 2014 and 2012 also include $1 million and $1 million decreases in expense, respectively, related to the combined effect from other certain items.
|
(c)
|
2014, 2013 and 2012 amounts include NGPL Holdco LLC general and administrative reimbursements of $36 million, $36 million and $35 million, respectively. These amounts were recorded to the “Product sales and other” caption in our accompanying consolidated statements of income with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income.
|
•
|
cash dividends and sustaining capital expenditures with existing cash and cash flows from operating activities;
|
•
|
expansion capital expenditures and working capital deficits with retained cash, proceeds from divestitures, additional borrowings (including commercial paper issuances), and the issuance of additional common stock;
|
•
|
interest payments with cash flows from operating activities; and
|
•
|
debt principal payments, as such debt principal payments become due, with proceeds from divestitures, additional borrowings or by the issuance of additional common stock.
|
Rating agency
|
|
Senior debt rating
|
|
Date of last change
|
|
Outlook
|
Standard and Poor’s
|
|
BBB-
|
|
November 20, 2014
|
|
Stable
|
Moody’s Investor Services
|
|
Baa3
|
|
November 21, 2014
|
|
Stable
|
Fitch Ratings, Inc.
|
|
BBB-
|
|
November 20, 2014
|
|
Stable
|
|
2014
|
|
Expected 2015
|
||||
Sustaining capital expenditures(a)
|
$
|
509
|
|
|
$
|
586
|
|
Discretionary capital expenditures(b)(c)
|
$
|
3,580
|
|
|
$
|
4,381
|
|
(a)
|
2014 and Expected 2015 amounts include $57 million and $82 million, respectively, for our proportionate share of sustaining capital expenditures of certain unconsolidated joint ventures.
|
(b)
|
2014 amount (i) includes $533 million of discretionary capital expenditures of unconsolidated joint ventures and acquisitions and (ii) excludes a combined $118 million net change from accrued capital expenditures, contractor retainage and amounts primarily related to contributions from noncontrolling interests to fund a portion of certain capital projects
|
(c)
|
Expected 2015 includes our contributions to certain unconsolidated joint ventures and small acquisitions, net of contributions estimated from unaffiliated joint venture partners for consolidated investments.
|
|
Payments due by period
|
||||||||||||||||||
|
Total
|
|
Less than 1
year
|
|
2-3 years
|
|
4-5 years
|
|
More than 5
years
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Contractual obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Debt borrowings-principal payments
|
$
|
41,029
|
|
|
$
|
2,717
|
|
|
$
|
4,743
|
|
|
$
|
5,147
|
|
|
$
|
28,422
|
|
Interest payments(a)
|
29,438
|
|
|
2,203
|
|
|
4,077
|
|
|
3,512
|
|
|
19,646
|
|
|||||
Leases and rights-of-way obligations(b)
|
678
|
|
|
97
|
|
|
160
|
|
|
132
|
|
|
289
|
|
|||||
Pension and postretirement welfare plans(c)
|
862
|
|
|
75
|
|
|
47
|
|
|
48
|
|
|
692
|
|
|||||
Transportation, volume and storage agreements(d)
|
1,189
|
|
|
162
|
|
|
277
|
|
|
249
|
|
|
501
|
|
|||||
Other obligations(e)
|
402
|
|
|
153
|
|
|
112
|
|
|
25
|
|
|
112
|
|
|||||
Total
|
$
|
73,598
|
|
|
$
|
5,407
|
|
|
$
|
9,416
|
|
|
$
|
9,113
|
|
|
$
|
49,662
|
|
Other commercial commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Standby letters of credit(f)
|
$
|
381
|
|
|
$
|
350
|
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Capital expenditures(g)
|
$
|
1,026
|
|
|
$
|
1,026
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(a)
|
Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2014.
|
(b)
|
Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way.
|
(c)
|
Represents the amount by which the benefit obligations exceeded the fair value of fund assets for pension and other postretirement benefit plans at year-end. The payments by period include expected contributions to funded plans in 2015 and estimated benefit payments for unfunded plans in all years.
|
(d)
|
Primarily represents transportation agreements of
$305 million, volume agreements of
$498 million and storage agreements for capacity on third party and an affiliate pipeline systems of
$257 million.
|
(e)
|
Primarily includes environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will
perform remediation activities. These liabilities are included within “Other long-term liabilities and deferred credits” in our consolidated balance sheets.
|
(f)
|
The $381 million in letters of credit outstanding as of December 31, 2014 consisted of the following (i) $20 million under four letters of credit related to power and marketing purposes; (ii) $86 million under fourteen letters of credit for insurance purposes; (iii) a $100 million letter of credit that supports certain proceedings with the CPUC involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (iv) our $30 million guarantee under letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $34 million letter of credit supporting our pipeline and terminal operations in Canada; (vi) a $25 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (viii) a $13 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (ix) a combined $33 million in twenty-four letters of credit supporting environmental and other obligations of us and our subsidiaries.
|
(g)
|
Represents commitments for the purchase of plant, property and equipment as of December 31, 2014.
|
•
|
a $984 million increase in cash from overall higher net income after adjusting our period-to-period $249 million decrease in net income for non-cash items primarily consisting of the following: (i) 2013 gain on the remeasurement of our previous 50% equity investment in Eagle Ford; (ii) 2013 gain on sale of our investments in the Express pipeline system (see the discussion of these investments in Note 3 “Acquisitions and Divestitures” to our consolidated financial statements); (iii) 2014 loss on impairments on both our CO
2
and terminal long-lived assets; (iv) DD&A expenses (including amortization of excess cost of equity investments); (v) deferred income tax expenses; (vi) gains from the sale or casualty of property, plant and equipment (see discussion above in “—Results of Operations”); (vii) the net activity of our equity method investees; and (viii) adjustments to accrued transportation rate case and legal liabilities;
|
•
|
a $315 million decrease in cash associated with rate case reserve payments primarily driven by the 2014 CPUC settlement and refund payments;
|
•
|
a $228 million decrease in cash associated with net changes in working capital items and non-current assets and liabilities. The decrease was primarily driven by a $195 million use of cash for income tax payments made during the first three quarters of 2014 (due to discrete events in the fourth quarter, we received a refund for these payments in the first quarter of 2015); lower cash flows from both natural gas storage and pipeline transportation system balancing, and lower net dock premiums and toll collections received from our Trans Mountain pipeline system customers. These decreases were partially offset by, among other things, higher cash inflows from favorable changes in the collection and payment of trade and related party receivables and payables (due primarily to the timing of invoices received from customers and paid to vendors and suppliers), and favorable changes in previously deferred reimbursable costs; and
|
•
|
a $96 million decrease in cash from interest rate swap termination payments received. In 2013, we terminated, in three separate transactions, three existing fixed-to-variable interest rate swap agreements prior to their contractual maturity dates.
|
•
|
a $1,096 million decrease in cash due to higher expenditures for acquisitions. The increase in acquisition expenditures was primarily related to the $1,231 million we paid in 2014 for our APT and Crowley tanker acquisitions, versus the $280 million we paid in 2013 to acquire the Goldsmith Landreth San Andres oil field unit (both discussed in Note 3 “Acquisitions and Divestitures”);
|
•
|
a combined $490 million decrease in cash due to proceeds received in 2013 from divestitures, primarily consisting of our sale of the investments in the Express pipeline system;
|
•
|
a $248 million decrease in cash due to higher capital expenditures in 2014 primarily reflecting higher investment undertaken to expand and improve our Products Pipelines and CO
2
business segments; and
|
•
|
a $172 million decrease in cash due to higher capital contributions, driven by a $175 million contribution we made in 2014 to MEP, our 50%-owned joint venture, to fund our share of the joint venture’s repayment of $350 million of senior notes that matured on September 15, 2014.
|
•
|
a $5,533 million net increase in cash from overall debt financing activities. The increase was driven by, among other things, a $5,259 million increase in cash due to the issuance of our senior notes, including proceeds of $5,987 million received in 2014 from the series of senior notes we issued to fund our Merger Transactions, and a net increase of $583 million in cash from both our commercial paper and revolving credit facilities programs (reflecting an increase in issuances of $5,733 million, partially offset by an increase in payments of $5,150 million). Further information regarding the debt related to our Merger Transactions is discussed in Note 8 “Debt” to our consolidated financial statements;
|
•
|
a $445 million increase in cash due to lower combined repurchases of shares and warrants;
|
•
|
a $3,937 million decrease in cash resulting from the cash portion of consideration for the Merger Transactions;
|
•
|
a $321 million decrease in cash associated with distributions to noncontrolling interests, primarily reflecting increased distributions to common unit owners of KMP and EPB prior to the Merger Transactions offset by no distribution being paid for the fourth quarter of 2014 since the closing date of the Merger Transactions occurred prior to KMP or EPB declaring any additional distributions; and
|
•
|
a $138 million decrease in cash due to higher dividend payments.
|
Three months ended
|
|
Total quarterly dividend per share for the period
|
|
Date of declaration
|
|
Date of record
|
|
Date of dividend
|
|||
March 31, 2014
|
|
$
|
0.42
|
|
|
|
April 16, 2014
|
|
April 30, 2014
|
|
May 16, 2014
|
June 30, 2014
|
|
$
|
0.43
|
|
|
|
July 16, 2014
|
|
July 31, 2014
|
|
August 15, 2014
|
September 30, 2014
|
|
$
|
0.44
|
|
|
|
October 15, 2014
|
|
October 31, 2014
|
|
November 17, 2014
|
December 31, 2014
|
|
$
|
0.45
|
|
|
|
January 21, 2015
|
|
February 2, 2015
|
|
February 17, 2015
|
|
Credit Rating
|
Bank of America / Merrill Lynch
|
A-
|
J. Aron & Company / Goldman Sachs
|
A-
|
J.P. Morgan
|
A
|
Morgan Stanley
|
A-
|
Macquarie
|
BBB
|
(a)
|
(1) Financial Statements and (2) Financial Statement Schedules
|
See “Index to Financial Statements” set forth on Page
77
.
|
|
(3)
|
Exhibits
|
Exhibit
Number
|
Description
|
||
2.1
|
|
*
|
Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan, Inc., and P Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
|
|
|
|
|
2.2
|
|
*
|
Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Management, LLC, Kinder Morgan, Inc., and R Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.2 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
|
|
|
|
|
2.3
|
|
*
|
Agreement and Plan of Merger, dated as of August 9, 2014, by and among El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., Kinder Morgan, Inc., and E Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.3 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
|
|
|
|
|
3.1
|
|
|
Certificate of Incorporation of Kinder Morgan, Inc. as amended by the Certificate of Amendment to the Certificate of Incorporation
|
|
|
|
3.2
|
|
|
Amended and Restated Bylaws of Kinder Morgan, Inc. as amended by the Amendment No. 1 to the Amended and Restated Bylaws
|
|
|
|
|
4.1
|
|
*
|
Form of certificate representing Class P common shares of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))
|
|
|
|
|
4.2
|
|
*
|
Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.2 to the KMI 10-Q)
|
|
|
|
|
4.3
|
|
*
|
Amendment No. 1 to the Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.3 Kinder Morgan, Inc.’s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))
|
|
|
|
|
4.4
|
|
*
|
Amendment No. 2 to the Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on December 3, 2014 (File No. 1-35081))
|
|
|
|
|
4.5
|
|
*
|
Warrant Agreement, dated as of May 25, 2012, among Kinder Morgan, Inc., Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to Kinder Morgan Inc.’s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))
|
|
|
|
|
10.1
|
|
*
|
Kinder Morgan, Inc. 2011 Stock Incentive Plan (filed as Exhibit 10.1 to the KMI 10-Q)
|
|
|
|
|
10.2
|
|
*
|
Form of Restricted Stock Agreement (filed as Exhibit 10.2 to the KMI 10-Q)
|
|
|
|
|
10.3
|
|
*
|
Kinder Morgan, Inc. Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.4 to the KMI 10-Q)
|
|
|
|
|
10.4
|
|
*
|
Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to the KMI 10-Q)
|
|
|
|
|
10.5
|
|
*
|
Kinder Morgan, Inc. Employees Stock Purchase Plan (filed as Exhibit 10.5 to the KMI 10-Q)
|
|
|
|
|
10.6
|
|
*
|
Kinder Morgan, Inc. Annual Incentive Plan (filed as Exhibit 10.6 to the KMI 10-Q)
|
|
|
|
|
10.7
|
|
*
|
Employment Agreement dated October 7, 1999, between K N Energy, Inc. and Richard D. Kinder (filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999 (File No. 5-06259))
|
|
|
|
|
10.8
|
|
*
|
Credit Agreement, dated as of May 30, 2007, among Kinder Morgan Kansas, Inc. and Kinder Morgan Acquisition Co., as the borrower, the several lenders from time to time parties thereto, and Citibank, N.A., as administrative agent and collateral agent (filed as Exhibit 10.10 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on December 30, 2010 (File No. 333-170773))
|
|
|
|
|
10.9
|
|
*
|
Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Kansas, Inc. dated May 18, 2001 (filed as Exhibit 4.7 to Kinder Morgan Kansas, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-06446))
|
|
|
|
|
10.10
|
|
*
|
Form of Indenture dated as of August 27, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))
|
|
|
|
|
10.11
|
|
*
|
Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on January 31, 2003 (File No. 333-102873))
|
|
|
|
|
10.12
|
|
*
|
Form of 6.50% Note due 2012 (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))
|
|
|
|
|
10.13
|
|
*
|
Form of Senior Indenture between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
|
|
|
|
|
10.14
|
|
*
|
Form of Senior Note of Kinder Morgan Kansas, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
|
|
|
|
|
10.15
|
|
*
|
Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
|
|
|
|
10.16
|
|
*
|
Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
|
|
|
|
|
10.17
|
|
*
|
Form of Indemnification Agreement between Kinder Morgan Kansas, Inc. and each member of the Special Committee of the Board of Directors formed in connection with the Going Private Transaction (filed as Exhibit 10.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on June 16, 2006 (File No. 1-06446))
|
|
|
|
|
10.18
|
|
*
|
Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))
|
|
|
|
|
10.19
|
|
*
|
Amendment No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K on July 20, 2007 (File No. 1-11234))
|
|
|
|
|
10.20
|
|
*
|
Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))
|
|
|
|
|
10.21
|
|
*
|
Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed November 22, 2004 (File No. 1-11234))
|
|
|
|
|
10.22
|
|
*
|
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed May 5, 2005 (File No. 1-11234))
|
|
|
|
|
10.23
|
|
*
|
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed April 21, 2008 (File No. 1-11234))
|
|
|
|
|
10.24
|
|
*
|
Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.5 to Kinder Morgan Energy Partners, L.P. Form 10-K 2012 (File No. 1-11234))
|
|
|
|
|
10.25
|
|
*
|
Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed June 24, 2010 (File No. 1-11234))
|
|
|
|
|
10.26
|
|
*
|
First Amendment to Credit Agreement, dated as of July 1, 2011, among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 1-11234))
|
|
|
|
|
10.27
|
|
*
|
Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed February 16, 1999 (File No. 1-11234))
|
|
|
|
|
10.28
|
|
*
|
Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11234))
|
|
|
|
|
10.29
|
|
*
|
Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))
|
|
|
|
|
10.30
|
|
*
|
Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))
|
|
|
|
|
10.31
|
|
*
|
Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))
|
|
|
|
10.32
|
|
*
|
Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
|
|
|
|
|
10.33
|
|
*
|
Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
|
|
|
|
|
10.34
|
|
*
|
Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
|
|
|
|
|
10.35
|
|
*
|
First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
|
|
|
|
|
10.36
|
|
*
|
Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
|
|
|
|
|
10.37
|
|
*
|
Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
|
|
|
|
|
10.38
|
|
*
|
Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
|
|
|
|
|
10.39
|
|
*
|
Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))
|
|
|
|
|
10.40
|
|
*
|
Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))
|
|
|
|
|
10.41
|
|
*
|
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))
|
|
|
|
|
10.42
|
|
*
|
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))
|
|
|
|
|
10.43
|
|
*
|
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))
|
|
|
|
|
10.44
|
|
*
|
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))
|
|
|
|
|
10.45
|
|
*
|
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))
|
|
|
|
|
10.46
|
|
*
|
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))
|
|
|
|
|
10.47
|
|
*
|
Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas, Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
|
|
|
|
|
10.48
|
|
*
|
Officers’ Certificate establishing the terms of the 6.000% Senior Notes due 2018 of Kinder Morgan Finance Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
|
|
|
|
|
10.49
|
|
*
|
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2016, and the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-11234))
|
|
|
|
|
10.50
|
|
*
|
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (File No. 1-11234))
|
|
|
|
|
10.51
|
|
*
|
Certificate of the Vice President, Finance and Investor Relations and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2021 and the 5.500% Senior Notes due 2044 (Filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (File No. 1-11234))
|
|
|
|
|
10.52
|
|
*
|
Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.250% Senior Notes due 2024 and the 5.400% Senior Notes due 2044 (Filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 (File No. 1-11234))
|
|
|
|
|
10.53
|
|
|
Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan, Inc. establishing the terms of the 2.000% Senior Notes due 2017, the 3.050% Senior Notes due 2019, the 4.300% Senior Notes due 2025, the 5.300% Senior Notes due 2034 and the 5.550% Senior Notes due 2045
|
|
|
|
|
10.54
|
|
*
|
Debt Commitment Letter between Kinder Morgan, Inc. and Barclays Capital PLC, dated as of October 16, 2011 (filed as Exhibit 10.71 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 filed on December 14, 2011 (File No. 333-177895))
|
|
|
|
|
10.55
|
|
*
|
Support Agreement, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., Richard D. Kinder and RDK Investments, Ltd. (filed as Exhibit 10.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
|
|
|
|
|
10.56
|
|
*
|
Bridge Credit Agreement, dated September 19, 2014 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed September 25, 2014)
|
|
|
|
|
10.57
|
|
*
|
Revolving Credit Agreement, dated September 19, 2014 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed September 25, 2014)
|
|
|
|
|
10.58
|
|
|
Cross Guarantee Agreement, dated as of November 26, 2014 among Kinder Morgan, Inc. and certain of its subsidiaries with schedules updated as of February 13, 2015
|
|
|
|
|
12.1
|
|
|
Statement re: computation of ratio of earnings to fixed charges
|
|
|
|
|
21.1
|
|
|
Subsidiaries of Kinder Morgan, Inc.
|
|
|
|
|
23.1
|
|
|
Consent of PricewaterhouseCoopers LLP
|
|
|
|
|
23.2
|
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
|
|
|
31.1
|
|
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
|
31.2
|
|
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
32.1
|
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
|
32.2
|
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
|
95.1
|
|
|
Mine Safety Disclosures
|
|
|
|
|
99.1
|
|
|
Netherland, Sewell & Associates, Inc.’s report of estimates of the net reserves and future net revenues, as of December 31, 2014, related to Kinder Morgan CO
2
Company, L.P.’s interest in certain oil and gas properties located in the state of Texas
|
|
|
|
|
101
|
|
|
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2014, 2013, and 2012; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013, and 2012; (iii) our Consolidated Balance Sheets as of December 31, 2014 and 2013; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013, and 2012; (v) our Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2014, 2013, and 2012; and (vi) the notes to our Consolidated Financial Statements
|
KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
|
|
|
Page
Number
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Share Amounts)
|
|||||||||||
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
|
|
|
|
|
|
||||||
Natural gas sales
|
$
|
4,115
|
|
|
$
|
3,605
|
|
|
$
|
2,511
|
|
Services
|
7,650
|
|
|
6,677
|
|
|
5,013
|
|
|||
Product sales and other
|
4,461
|
|
|
3,788
|
|
|
2,449
|
|
|||
Total Revenues
|
16,226
|
|
|
14,070
|
|
|
9,973
|
|
|||
|
|
|
|
|
|
||||||
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|||||
Costs of sales
|
6,278
|
|
|
5,253
|
|
|
3,057
|
|
|||
Operations and maintenance
|
2,157
|
|
|
2,112
|
|
|
1,702
|
|
|||
Depreciation, depletion and amortization
|
2,040
|
|
|
1,806
|
|
|
1,419
|
|
|||
General and administrative
|
610
|
|
|
613
|
|
|
929
|
|
|||
Taxes, other than income taxes
|
418
|
|
|
395
|
|
|
286
|
|
|||
Loss on impairments of long-lived assets
|
272
|
|
|
—
|
|
|
—
|
|
|||
Other expense (income), net
|
3
|
|
|
(99
|
)
|
|
(13
|
)
|
|||
Total Operating Costs, Expenses and Other
|
11,778
|
|
|
10,080
|
|
|
7,380
|
|
|||
|
|
|
|
|
|
||||||
Operating Income
|
4,448
|
|
|
3,990
|
|
|
2,593
|
|
|||
|
|
|
|
|
|
||||||
Other Income (Expense)
|
|
|
|
|
|
|
|||||
Earnings from equity investments
|
406
|
|
|
327
|
|
|
153
|
|
|||
Amortization of excess cost of equity investments
|
(45
|
)
|
|
(39
|
)
|
|
(23
|
)
|
|||
Interest, net
|
(1,798
|
)
|
|
(1,675
|
)
|
|
(1,399
|
)
|
|||
Gain on remeasurement of previously held equity investments to fair value (Note 3)
|
—
|
|
|
558
|
|
|
—
|
|
|||
Gain on sale of investments in Express pipeline system (Note 3)
|
—
|
|
|
224
|
|
|
—
|
|
|||
Other, net
|
80
|
|
|
53
|
|
|
19
|
|
|||
Total Other Income (Expense)
|
(1,357
|
)
|
|
(552
|
)
|
|
(1,250
|
)
|
|||
|
|
|
|
|
|
||||||
Income from Continuing Operations Before Income Taxes
|
3,091
|
|
|
3,438
|
|
|
1,343
|
|
|||
|
|
|
|
|
|
||||||
Income Tax Expense
|
(648
|
)
|
|
(742
|
)
|
|
(139
|
)
|
|||
|
|
|
|
|
|
||||||
Income from Continuing Operations
|
2,443
|
|
|
2,696
|
|
|
1,204
|
|
|||
|
|
|
|
|
|
|
|||||
Discontinued Operations (Note 3)
|
|
|
|
|
|
||||||
Income from operations of the FTC Natural Gas Pipelines
disposal group and other, net of tax
|
—
|
|
|
—
|
|
|
160
|
|
|||
Loss on sale and the remeasurement of the FTC Natural Gas Pipelines disposal group to fair value, net of tax
|
—
|
|
|
(4
|
)
|
|
(937
|
)
|
|||
Loss from Discontinued Operations, Net of Tax
|
—
|
|
|
(4
|
)
|
|
(777
|
)
|
|||
|
|
|
|
|
|
||||||
Net Income
|
2,443
|
|
|
2,692
|
|
|
427
|
|
|||
|
|
|
|
|
|
||||||
Net Income Attributable to Noncontrolling Interests
|
(1,417
|
)
|
|
(1,499
|
)
|
|
(112
|
)
|
|||
|
|
|
|
|
|
||||||
Net Income Attributable to Kinder Morgan, Inc.
|
$
|
1,026
|
|
|
$
|
1,193
|
|
|
$
|
315
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (continued)
(In Millions, Except Per Share Amounts)
|
|||||||||||
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Class P Shares
|
|
|
|
|
|
|
|
||||
Basic and Diluted Earnings Per Common Share From Continuing Operations
|
$
|
0.89
|
|
|
$
|
1.15
|
|
|
$
|
0.56
|
|
Basic and Diluted Loss Per Common Share From Discontinued Operations
|
—
|
|
|
—
|
|
|
(0.21
|
)
|
|||
Total Basic and Diluted Earnings Per Common Share
|
$
|
0.89
|
|
|
$
|
1.15
|
|
|
$
|
0.35
|
|
|
|
|
|
|
|
||||||
Class A Shares
|
|
|
|
|
|
||||||
Basic and Diluted Earnings Per Common Share From Continuing Operations
|
|
|
|
|
$
|
0.47
|
|
||||
Basic and Diluted Loss Per Common Share From Discontinued Operations
|
|
|
|
|
(0.21
|
)
|
|||||
Total Basic and Diluted Earnings Per Common Share
|
|
|
|
|
$
|
0.26
|
|
||||
|
|
|
|
|
|
||||||
Basic Weighted-Average Number of Shares Outstanding
|
|
|
|
|
|
||||||
Class P Shares
|
1,137
|
|
|
1,036
|
|
|
461
|
|
|||
Class A Shares
|
|
|
|
|
446
|
|
|||||
|
|
|
|
|
|
||||||
Diluted Weighted-Average Number of Shares Outstanding
|
|
|
|
|
|
|
|
||||
Class P Shares
|
1,137
|
|
|
1,036
|
|
|
908
|
|
|||
Class A Shares
|
|
|
|
|
446
|
|
|||||
|
|
|
|
|
|
||||||
Dividends Per Common Share Declared for the Period
|
$
|
1.74
|
|
|
$
|
1.60
|
|
|
$
|
1.40
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Kinder Morgan, Inc.
|
|
|
|
|
|
||||||
Net income
|
$
|
1,026
|
|
|
$
|
1,193
|
|
|
$
|
315
|
|
Other comprehensive income (loss), net of tax
|
|
|
|
|
|
|
|
|
|||
Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $(150), $6 and $(19), respectively)
|
254
|
|
|
(14
|
)
|
|
32
|
|
|||
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $13, $(2) and $3, respectively)
|
(22
|
)
|
|
4
|
|
|
(5
|
)
|
|||
Foreign currency
translation
adjustments (net of tax benefit (expense) of $41, $22, and $(8), respectively)
|
(68
|
)
|
|
(49
|
)
|
|
14
|
|
|||
Benefit plan adjustments (net of tax benefit (expense) of $125, $(88) and $30, respectively)
|
(213
|
)
|
|
153
|
|
|
(44
|
)
|
|||
Total other comprehensive (loss) income
|
(49
|
)
|
|
94
|
|
|
(3
|
)
|
|||
Total comprehensive income
|
977
|
|
|
1,287
|
|
|
312
|
|
|||
|
|
|
|
|
|
||||||
Noncontrolling Interests
|
|
|
|
|
|
|
|
|
|||
Net income
|
1,417
|
|
|
1,499
|
|
|
112
|
|
|||
Other comprehensive income (loss), net of tax
|
|
|
|
|
|
|
|
|
|||
Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $(13), $4 and $(7), respectively)
|
155
|
|
|
(24
|
)
|
|
50
|
|
|||
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $-, $(1) and $-, respectively)
|
(3
|
)
|
|
7
|
|
|
(3
|
)
|
|||
Foreign currency
translation
adjustments (net of tax benefit (expense) of $7, $9 and $(2), respectively)
|
(70
|
)
|
|
(54
|
)
|
|
18
|
|
|||
Benefit plan adjustments (net of tax benefit (expense) of $1, $(3) and $-, respectively)
|
(13
|
)
|
|
17
|
|
|
9
|
|
|||
Total other comprehensive income (loss)
|
69
|
|
|
(54
|
)
|
|
74
|
|
|||
Total comprehensive income
|
1,486
|
|
|
1,445
|
|
|
186
|
|
|||
|
|
|
|
|
|
||||||
Total
|
|
|
|
|
|
|
|
|
|||
Net income
|
2,443
|
|
|
2,692
|
|
|
427
|
|
|||
Other comprehensive income (loss), net of tax
|
|
|
|
|
|
|
|
|
|||
Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of
$(163), $10 and $(26), respectively)
|
409
|
|
|
(38
|
)
|
|
82
|
|
|||
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $13, $(3) and $3, respectively)
|
(25
|
)
|
|
11
|
|
|
(8
|
)
|
|||
Foreign currency
translation
adjustments (net of tax benefit (expense) of $48, $31 and $(10), respectively)
|
(138
|
)
|
|
(103
|
)
|
|
32
|
|
|||
Benefit plan adjustments (net of tax benefit (expense) of $126, $(91) and $30, respectively)
|
(226
|
)
|
|
170
|
|
|
(35
|
)
|
|||
Total other comprehensive income
|
20
|
|
|
40
|
|
|
71
|
|
|||
Total comprehensive income
|
$
|
2,463
|
|
|
$
|
2,732
|
|
|
$
|
498
|
|
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(In Millions, Except Share and Per Share Amounts)
|
|||||||
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Commitments and contingencies (Notes 8, 12 and 16)
|
|
|
|
|
|
||
Stockholders’ Equity
|
|
|
|
|
|
||
Class P shares, $0.01 par value, 4,000,000,000 and 2,000,000,000 shares, respectively, authorized, 2,125,147,116 and 1,030,677,076 shares, respectively, issued and outstanding
|
$
|
21
|
|
|
$
|
10
|
|
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none outstanding
|
—
|
|
|
—
|
|
||
Additional paid-in capital
|
36,178
|
|
|
14,479
|
|
||
Retained deficit
|
(2,106
|
)
|
|
(1,372
|
)
|
||
Accumulated other comprehensive loss
|
(17
|
)
|
|
(24
|
)
|
||
Total Kinder Morgan, Inc.’s stockholders’ equity
|
34,076
|
|
|
13,093
|
|
||
Noncontrolling interests
|
350
|
|
|
15,192
|
|
||
Total Stockholders’ Equity
|
34,426
|
|
|
28,285
|
|
||
Total Liabilities and Stockholders’ Equity
|
$
|
83,198
|
|
|
$
|
75,185
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Cash Flows From Operating Activities
|
|
|
|
|
|
||||||
Net income
|
$
|
2,443
|
|
|
$
|
2,692
|
|
|
$
|
427
|
|
Adjustments to reconcile net income to net cash provided by operating activities
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization
|
2,040
|
|
|
1,806
|
|
|
1,426
|
|
|||
Deferred income taxes
|
615
|
|
|
640
|
|
|
47
|
|
|||
Amortization of excess cost of equity investments
|
45
|
|
|
39
|
|
|
23
|
|
|||
Loss on impairments of long-lived assets
|
272
|
|
|
—
|
|
|
—
|
|
|||
(Gain) loss from the remeasurement of net assets to fair value and the sale of discontinued operations (net of cash selling expenses), net of tax (Note 3)
|
—
|
|
|
(556
|
)
|
|
859
|
|
|||
Gain from sale of investments in Express pipeline system (Note 3)
|
—
|
|
|
(224
|
)
|
|
—
|
|
|||
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
82
|
|
|||
Noncash compensation expense on settlement of EP stock awards
|
—
|
|
|
—
|
|
|
87
|
|
|||
Earnings from equity investments
|
(406
|
)
|
|
(327
|
)
|
|
(223
|
)
|
|||
Distributions from equity investment earnings
|
381
|
|
|
398
|
|
|
381
|
|
|||
Proceeds from termination of interest rate swap agreements
|
—
|
|
|
96
|
|
|
53
|
|
|||
Pension contributions and noncash pension benefit credits
|
(88
|
)
|
|
(120
|
)
|
|
(31
|
)
|
|||
Changes in components of working capital, net of the effects of acquisitions
|
|
|
|
|
|
|
|
|
|||
Accounts receivable
|
(84
|
)
|
|
(131
|
)
|
|
(231
|
)
|
|||
Income tax receivable
|
(195
|
)
|
|
—
|
|
|
—
|
|
|||
Inventories
|
(30
|
)
|
|
(53
|
)
|
|
(92
|
)
|
|||
Other current assets
|
(31
|
)
|
|
(24
|
)
|
|
32
|
|
|||
Accounts payable
|
(1
|
)
|
|
(36
|
)
|
|
70
|
|
|||
Accrued interest
|
75
|
|
|
42
|
|
|
(26
|
)
|
|||
Accrued contingencies and other current liabilities
|
108
|
|
|
(100
|
)
|
|
(68
|
)
|
|||
Rate reparations, refunds and other litigation reserve adjustments
|
(280
|
)
|
|
174
|
|
|
(39
|
)
|
|||
Other, net
|
(397
|
)
|
|
(194
|
)
|
|
31
|
|
|||
Net Cash Provided by Operating Activities
|
4,467
|
|
|
4,122
|
|
|
2,808
|
|
|||
|
|
|
|
|
|
||||||
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|||
Acquisition of EP, net of $6,581 cash acquired (Note 3)
|
—
|
|
|
—
|
|
|
(4,970
|
)
|
|||
Acquisitions of other assets and investments, net of cash acquired
|
(1,388
|
)
|
|
(292
|
)
|
|
(83
|
)
|
|||
Proceeds from sales of assets and investments
|
—
|
|
|
490
|
|
|
—
|
|
|||
Proceeds from disposal of discountinued operations (Note 3)
|
—
|
|
|
—
|
|
|
1,791
|
|
|||
Capital expenditures
|
(3,617
|
)
|
|
(3,369
|
)
|
|
(2,022
|
)
|
|||
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs
|
5
|
|
|
87
|
|
|
154
|
|
|||
Contributions to investments
|
(389
|
)
|
|
(217
|
)
|
|
(192
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings
|
182
|
|
|
185
|
|
|
200
|
|
|||
Other, net
|
(3
|
)
|
|
(6
|
)
|
|
25
|
|
|||
Net Cash Used in Investing Activities
|
(5,210
|
)
|
|
(3,122
|
)
|
|
(5,097
|
)
|
|||
|
|
|
|
|
|
||||||
Cash Flows From Financing Activities
|
|
|
|
|
|
||||||
Issuance of debt
|
24,573
|
|
|
13,581
|
|
|
18,148
|
|
|||
Payment of debt
|
(17,801
|
)
|
|
(12,393
|
)
|
|
(14,755
|
)
|
|||
Debt issue costs
|
(89
|
)
|
|
(38
|
)
|
|
(111
|
)
|
|||
Cash dividends (Note 10)
|
(1,760
|
)
|
|
(1,622
|
)
|
|
(1,184
|
)
|
|||
Repurchases of shares and warrants
|
(192
|
)
|
|
(637
|
)
|
|
(157
|
)
|
|||
Cash consideration of Merger Transactions (Note 1)
|
(3,937
|
)
|
|
—
|
|
|
—
|
|
|||
Merger Transactions costs
|
(74
|
)
|
|
—
|
|
|
—
|
|
|||
Contributions from noncontrolling interests
|
1,767
|
|
|
1,706
|
|
|
1,939
|
|
|||
Distributions to noncontrolling interests
|
(2,013
|
)
|
|
(1,692
|
)
|
|
(1,219
|
)
|
|||
Other, net
|
(3
|
)
|
|
—
|
|
|
(77
|
)
|
|||
Net Cash Provided by (Used in) Financing Activities
|
471
|
|
|
(1,095
|
)
|
|
2,584
|
|
|||
|
|
|
|
|
|
||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
(11
|
)
|
|
(21
|
)
|
|
8
|
|
|||
|
|
|
|
|
|
||||||
Net (decrease) increase in Cash and Cash Equivalents
|
(283
|
)
|
|
(116
|
)
|
|
303
|
|
|||
Cash and Cash Equivalents, beginning of period
|
598
|
|
|
714
|
|
|
411
|
|
|||
Cash and Cash Equivalents, end of period
|
$
|
315
|
|
|
$
|
598
|
|
|
$
|
714
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Noncash Investing and Financing Activities
|
|
|
|
|
|
|
|
|
|||
Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1 and 3)
|
$
|
16,023
|
|
|
$
|
—
|
|
|
$
|
11,454
|
|
Assets acquired by the assumption or incurrence of liabilities
|
106
|
|
|
1,510
|
|
|
—
|
|
|||
Assets acquired or liabilities settled by contributions from noncontrolling interests
|
—
|
|
|
3,733
|
|
|
306
|
|
|||
|
|
|
|
|
|
||||||
Supplemental Disclosures of Cash Flow Information
|
|
|
|
|
|
|
|
||||
Cash paid during the period for interest (net of capitalized interest)
|
1,718
|
|
|
1,652
|
|
|
1,349
|
|
|||
Cash paid during the period for income taxes (net of refunds)
|
227
|
|
|
67
|
|
|
182
|
|
|
Par value of common
shares
|
|
Additional
paid-in
capital
|
|
Retained
deficit
|
|
Accumulated
other
comprehensive
loss
|
|
Stockholders’
equity
attributable
to KMI
|
|
Non-controlling
interests
|
|
Total
|
||||||||||||||
Balance at December 31, 2011
|
$
|
8
|
|
|
$
|
3,431
|
|
|
$
|
(3
|
)
|
|
$
|
(115
|
)
|
|
$
|
3,321
|
|
|
$
|
5,247
|
|
|
$
|
8,568
|
|
Issuance of shares for EP acquisition
|
3
|
|
|
10,598
|
|
|
|
|
|
|
10,601
|
|
|
|
|
10,601
|
|
||||||||||
Issuance of warrants for EP acquisition
|
|
|
863
|
|
|
|
|
|
|
863
|
|
|
|
|
863
|
|
|||||||||||
Acquisition of EP noncontrolling interests
|
|
|
|
|
|
|
|
|
—
|
|
|
3,797
|
|
|
3,797
|
|
|||||||||||
Warrants repurchased
|
|
|
(157
|
)
|
|
|
|
|
|
(157
|
)
|
|
|
|
(157
|
)
|
|||||||||||
EP Trust I Preferred security conversions
|
|
|
14
|
|
|
|
|
|
|
14
|
|
|
|
|
14
|
|
|||||||||||
Class A, Class B and Class C share conversions
|
(1
|
)
|
|
1
|
|
|
(71
|
)
|
|
|
|
(71
|
)
|
|
|
|
(71
|
)
|
|||||||||
Amortization of restricted shares
|
|
|
14
|
|
|
|
|
|
|
14
|
|
|
|
|
14
|
|
|||||||||||
Impact from equity transactions of KMP, EPB and KMR
|
|
|
64
|
|
|
|
|
|
|
64
|
|
|
(102
|
)
|
|
(38
|
)
|
||||||||||
Tax impact on stock based compensation
|
|
|
90
|
|
|
|
|
|
|
90
|
|
|
|
|
90
|
|
|||||||||||
Net income
|
|
|
|
|
315
|
|
|
|
|
315
|
|
|
112
|
|
|
427
|
|
||||||||||
Distributions
|
|
|
|
|
|
|
|
|
—
|
|
|
(1,219
|
)
|
|
(1,219
|
)
|
|||||||||||
Contributions
|
|
|
|
|
|
|
|
|
—
|
|
|
2,329
|
|
|
2,329
|
|
|||||||||||
Cash dividends
|
|
|
|
|
(1,184
|
)
|
|
|
|
(1,184
|
)
|
|
|
|
(1,184
|
)
|
|||||||||||
Other
|
|
|
(1
|
)
|
|
|
|
|
|
(1
|
)
|
|
(4
|
)
|
|
(5
|
)
|
||||||||||
Other comprehensive (loss) income
|
|
|
|
|
|
|
(3
|
)
|
|
(3
|
)
|
|
74
|
|
|
71
|
|
||||||||||
Balance at December 31, 2012
|
10
|
|
|
14,917
|
|
|
(943
|
)
|
|
(118
|
)
|
|
13,866
|
|
|
10,234
|
|
|
24,100
|
|
|||||||
Shares repurchased
|
|
|
(172
|
)
|
|
|
|
|
|
(172
|
)
|
|
|
|
(172
|
)
|
|||||||||||
Warrants repurchased
|
|
|
(465
|
)
|
|
|
|
|
|
(465
|
)
|
|
|
|
(465
|
)
|
|||||||||||
Warrants exercised
|
|
|
1
|
|
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|||||||||||
EP Trust I Preferred security conversions
|
|
|
3
|
|
|
|
|
|
|
3
|
|
|
|
|
3
|
|
|||||||||||
Amortization of restricted shares
|
|
|
35
|
|
|
|
|
|
|
35
|
|
|
|
|
35
|
|
|||||||||||
Impact from equity transactions of KMP, EPB and KMR
|
|
|
161
|
|
|
|
|
|
|
161
|
|
|
(254
|
)
|
|
(93
|
)
|
||||||||||
Net income
|
|
|
|
|
1,193
|
|
|
|
|
1,193
|
|
|
1,499
|
|
|
2,692
|
|
||||||||||
Distributions
|
|
|
|
|
|
|
|
|
—
|
|
|
(1,692
|
)
|
|
(1,692
|
)
|
|||||||||||
Contributions
|
|
|
|
|
|
|
|
|
—
|
|
|
5,439
|
|
|
5,439
|
|
|||||||||||
KMP’s acquisition of Copano noncontrolling interests
|
|
|
|
|
|
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|||||||||||
Cash dividends
|
|
|
|
|
(1,622
|
)
|
|
|
|
(1,622
|
)
|
|
|
|
(1,622
|
)
|
|||||||||||
Other
|
|
|
(1
|
)
|
|
|
|
|
|
(1
|
)
|
|
3
|
|
|
2
|
|
||||||||||
Other comprehensive income
|
|
|
|
|
|
|
94
|
|
|
94
|
|
|
(54
|
)
|
|
40
|
|
||||||||||
Balance at December 31, 2013
|
10
|
|
|
14,479
|
|
|
(1,372
|
)
|
|
(24
|
)
|
|
13,093
|
|
|
15,192
|
|
|
28,285
|
|
|||||||
Impact of Merger Transactions
|
11
|
|
|
21,880
|
|
|
|
|
|
|
21,891
|
|
|
(15,936
|
)
|
|
5,955
|
|
|||||||||
Merger Transactions costs
|
|
|
(75
|
)
|
|
|
|
|
|
(75
|
)
|
|
|
|
(75
|
)
|
|||||||||||
Shares repurchased
|
|
|
(94
|
)
|
|
|
|
|
|
(94
|
)
|
|
|
|
(94
|
)
|
|||||||||||
Warrants repurchased
|
|
|
(98
|
)
|
|
|
|
|
|
(98
|
)
|
|
|
|
(98
|
)
|
|||||||||||
Amortization of restricted shares
|
|
|
57
|
|
|
|
|
|
|
57
|
|
|
|
|
57
|
|
|||||||||||
Impact from equity transactions of KMP, EPB and KMR
|
|
|
36
|
|
|
|
|
|
|
36
|
|
|
(55
|
)
|
|
(19
|
)
|
||||||||||
Net income
|
|
|
|
|
1,026
|
|
|
|
|
1,026
|
|
|
1,417
|
|
|
2,443
|
|
||||||||||
Distributions
|
|
|
|
|
|
|
|
|
—
|
|
|
(2,013
|
)
|
|
(2,013
|
)
|
|||||||||||
Contributions
|
|
|
|
|
|
|
|
|
—
|
|
|
1,767
|
|
|
1,767
|
|
|||||||||||
Cash dividends
|
|
|
|
|
(1,760
|
)
|
|
|
|
(1,760
|
)
|
|
|
|
(1,760
|
)
|
|||||||||||
Other
|
|
|
(7
|
)
|
|
|
|
|
|
(7
|
)
|
|
(4
|
)
|
|
(11
|
)
|
||||||||||
Other comprehensive (loss) income
|
|
|
|
|
|
|
(49
|
)
|
|
(49
|
)
|
|
69
|
|
|
20
|
|
||||||||||
Impact of Merger Transactions on Accumulated other comprehensive loss
|
|
|
|
|
|
|
56
|
|
|
56
|
|
|
(87
|
)
|
|
(31
|
)
|
||||||||||
Balance at December 31, 2014
|
$
|
21
|
|
|
$
|
36,178
|
|
|
$
|
(2,106
|
)
|
|
$
|
(17
|
)
|
|
$
|
34,076
|
|
|
$
|
350
|
|
|
$
|
34,426
|
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Current regulatory assets
|
$
|
81
|
|
|
$
|
91
|
|
Non-current regulatory assets
|
406
|
|
|
446
|
|
||
Total regulatory assets
|
$
|
487
|
|
|
$
|
537
|
|
|
|
|
|
||||
Current regulatory liabilities
|
$
|
189
|
|
|
$
|
135
|
|
Non-current regulatory liabilities
|
290
|
|
|
397
|
|
||
Total regulatory liabilities
|
$
|
479
|
|
|
$
|
532
|
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
Class P
|
$
|
1,015
|
|
|
$
|
1,187
|
|
Participating securities(a)
|
11
|
|
|
6
|
|
||
Net Income Attributable to Kinder Morgan, Inc.
|
$
|
1,026
|
|
|
$
|
1,193
|
|
(a)
|
Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalent payments.
|
|
Year Ended December 31,
|
||||
|
2014
|
|
2013
|
||
Unvested restricted stock awards
|
7
|
|
|
4
|
|
Outstanding warrants to purchase our Class P shares(a)
|
312
|
|
|
401
|
|
Convertible trust preferred securities
|
10
|
|
|
10
|
|
(a)
|
Each of our warrants entitles the holder to purchase one share of our common stock for an exercise price of
$40
per share, payable in cash or by cashless exercise, at any time until May 25, 2017.
|
|
Year ended December 31, 2012
|
||||||||||||||
|
Income from Continuing Operations Available to Shareholders
|
||||||||||||||
|
Class P
|
|
Class A
|
|
Participating
Securities(a)
|
|
Total
|
||||||||
Income from continuing operations
|
|
|
|
|
|
|
$
|
1,204
|
|
||||||
Less: income from continuing operations attributable to noncontrolling interests
|
|
|
|
|
|
|
(696
|
)
|
|||||||
Income from continuing operations attributable to KMI
|
|
|
|
|
|
|
508
|
|
|||||||
Dividends paid in the period
|
$
|
601
|
|
|
$
|
542
|
|
|
$
|
41
|
|
|
(1,184
|
)
|
|
Excess distributions over earnings
|
(344
|
)
|
|
(331
|
)
|
|
(1
|
)
|
|
$
|
(676
|
)
|
|||
Income from continuing operations attributable to shareholders
|
$
|
257
|
|
|
$
|
211
|
|
|
$
|
40
|
|
|
$
|
508
|
|
Basic earnings per share from continuing operations
|
|
|
|
|
|
|
|
||||||||
Basic weighted-average number of shares outstanding
|
461
|
|
|
446
|
|
|
N/A
|
|
|
||||||
Basic earnings per common share from continuing operations(b)
|
$
|
0.56
|
|
|
$
|
0.47
|
|
|
N/A
|
|
|
||||
Diluted earnings per share from continuing operations
|
|
|
|
|
|
|
|
||||||||
Income from continuing operations attributable to shareholders and assumed conversions(c)
|
$
|
508
|
|
|
$
|
211
|
|
|
N/A
|
|
|
||||
Diluted weighted-average number of shares
|
908
|
|
|
446
|
|
|
N/A
|
|
|
||||||
Diluted earnings per common share from continuing operations(b)
|
$
|
0.56
|
|
|
$
|
0.47
|
|
|
N/A
|
|
|
|
Year ended December 31, 2012
|
||||||||||||||
|
Net Income Available to Shareholders
|
||||||||||||||
|
Class P
|
|
Class A
|
|
Participating
Securities(a)
|
|
Total
|
||||||||
Net income attributable to KMI
|
|
|
|
|
|
|
$
|
315
|
|
||||||
Dividends paid in the period
|
$
|
601
|
|
|
$
|
542
|
|
|
$
|
41
|
|
|
(1,184
|
)
|
|
Excess distributions over earnings
|
(441
|
)
|
|
(426
|
)
|
|
(2
|
)
|
|
$
|
(869
|
)
|
|||
Net income attributable to shareholders
|
$
|
160
|
|
|
$
|
116
|
|
|
$
|
39
|
|
|
$
|
315
|
|
Basic earnings per share
|
|
|
|
|
|
|
|
||||||||
Basic weighted-average number of shares outstanding
|
461
|
|
|
446
|
|
|
N/A
|
|
|
||||||
Basic earnings per common share(b)
|
$
|
0.35
|
|
|
$
|
0.26
|
|
|
N/A
|
|
|
||||
Diluted earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income attributable to shareholders and assumed conversions(c)
|
$
|
315
|
|
|
$
|
116
|
|
|
N/A
|
|
|
||||
Diluted weighted-average number of shares
|
908
|
|
|
446
|
|
|
N/A
|
|
|
||||||
Diluted earnings per common share(b)
|
$
|
0.35
|
|
|
$
|
0.26
|
|
|
N/A
|
|
|
(a)
|
Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalents payments.
|
(b)
|
The Class A shares earnings per share as compared to the Class P shares earnings per share were reduced due to the sharing of economic benefits (including dividends) amongst the Class A, B, and C shares. Class A, B and C shares owned by Richard Kinder, the sponsor investors, the original shareholders, and other management were referred to as “investor retained stock,” and were convertible into a fixed number of Class P shares. In the aggregate, our investor retained stock was entitled to receive a dividend per share on a fully-converted basis equal to the dividend per share on our common stock. The conversion of shares of investor retained stock into Class P shares did not increase our total fully-converted shares outstanding, impact the aggregate dividends we paid or the dividends we paid per share on our Class P common stock.
|
(c)
|
For the diluted earnings per share calculation, total net income attributable to each class of common stock was divided by the adjusted weighted-average shares outstanding during the period, including all potential common stock equivalents.
|
|
|
|
Assignment of Purchase Price
|
||||||||||||||||||||||||||||||||||
Ref.
|
Date
|
Acquisition
|
Purchase
price
|
|
Current
assets
|
|
Property
plant &
equipment
|
|
Deferred
charges
& other
|
|
Goodwill
|
|
Long-term debt
|
|
Other liabilities
|
|
Non-controlling interest
|
|
Previously held equity interest
|
||||||||||||||||||
(1)
|
11/14
|
Pennsylvania and Florida Jones Act Tankers
|
$
|
270
|
|
|
$
|
—
|
|
|
$
|
270
|
|
|
$
|
8
|
|
|
$
|
25
|
|
|
$
|
—
|
|
|
$
|
(33
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
(2)
|
1/14
|
American Petroleum Tankers and State Class Tankers
|
961
|
|
|
6
|
|
|
951
|
|
|
6
|
|
|
64
|
|
|
—
|
|
|
(66
|
)
|
|
—
|
|
|
—
|
|
|||||||||
(3)
|
6/13
|
Goldsmith-Landreth Field Unit
|
280
|
|
|
—
|
|
|
298
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
|||||||||
(4)
|
5/13
|
Copano
|
3,733
|
|
|
218
|
|
|
2,788
|
|
|
1,973
|
|
|
963
|
|
|
(1,252
|
)
|
|
(236
|
)
|
|
(17
|
)
|
|
(704
|
)
|
|||||||||
(5)
|
5/12
|
EP
|
22,928
|
|
|
7,175
|
|
|
12,921
|
|
|
5,718
|
|
|
18,562
|
|
|
(13,417
|
)
|
|
(4,234
|
)
|
|
(3,797
|
)
|
|
—
|
|
|
|
Pro Forma
|
||||||
|
|
Year Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(Unaudited)
|
||||||
Revenues
|
|
$
|
16,260
|
|
|
$
|
14,911
|
|
Income from continuing operations
|
|
2,448
|
|
|
2,665
|
|
||
Income from discontinued operations, net of tax
|
|
—
|
|
|
(4
|
)
|
||
Net income
|
|
2,448
|
|
|
2,661
|
|
||
Net income attributable to noncontrolling interests
|
|
(1,419
|
)
|
|
(1,490
|
)
|
||
Net income attributable to Kinder Morgan, Inc.
|
|
1,029
|
|
|
1,171
|
|
||
Diluted earnings per common share
|
|
|
|
|
||||
Class P shares
|
|
$
|
0.90
|
|
|
$
|
1.12
|
|
•
|
Effective
August 1, 2012
, KMP acquired from us a
100%
ownership interest in TGP and an initial
50%
ownership interest in EPNG, referred to in this report as the August 2012 drop-down transaction;
|
•
|
Effective
March 1, 2013
, KMP acquired from us the remaining
50%
ownership interest it did not already own in both EPNG and the EP midstream assets (see “—KMP Previously Held Investment in El Paso Midstream Investment Company, LLC” following), referred to in this report as the March 2013 drop-down transaction; and
|
•
|
On May 2, 2014, EPB acquired from us our
50%
equity interest in Ruby Pipeline Holding Company, L.L.C. (Ruby), our indirect
50%
equity interest in Gulf LNG Holdings Group, L.L.C. (Gulf LNG) and our indirect
47.5%
equity interest in Young Gas Storage Company, Ltd., referred to in this report as the May 2014 drop-down transaction.
|
|
Year Ended
December 31, 2012(a)
|
||
Operating revenues
|
$
|
227
|
|
Operating expenses
|
(131
|
)
|
|
Depreciation and amortization
|
(7
|
)
|
|
Other expense
|
(1
|
)
|
|
Earnings from equity investments
|
70
|
|
|
Interest income and Other, net
|
2
|
|
|
Income from operations of the FTC Natural Gas Pipelines disposal group
|
$
|
160
|
|
(a)
|
2012 amounts represent financial information for the ten month period ended October 31, 2012. We sold the FTC Natural Gas Pipelines disposal group effective November 1, 2012.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
U.S.
|
$
|
2,941
|
|
|
$
|
3,107
|
|
|
$
|
1,246
|
|
Foreign
|
150
|
|
|
331
|
|
|
97
|
|
|||
Total Income from Continuing Operations Before Income Taxes
|
$
|
3,091
|
|
|
$
|
3,438
|
|
|
$
|
1,343
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Current tax expense
|
|
|
|
|
|
||||||
Federal
|
$
|
(16
|
)
|
|
$
|
57
|
|
|
$
|
48
|
|
State
|
36
|
|
|
36
|
|
|
34
|
|
|||
Foreign
|
13
|
|
|
9
|
|
|
10
|
|
|||
Total
|
33
|
|
|
102
|
|
|
92
|
|
|||
Deferred tax expense
|
|
|
|
|
|
|
|
|
|||
Federal
|
572
|
|
|
612
|
|
|
49
|
|
|||
State
|
14
|
|
|
—
|
|
|
4
|
|
|||
Foreign
|
29
|
|
|
28
|
|
|
(6
|
)
|
|||
Total
|
615
|
|
|
640
|
|
|
47
|
|
|||
Total tax provision
|
$
|
648
|
|
|
$
|
742
|
|
|
$
|
139
|
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Deferred tax assets
|
|
|
|
||||
Employee benefits
|
$
|
329
|
|
|
$
|
238
|
|
Accrued expenses
|
123
|
|
|
136
|
|
||
Net operating loss, capital loss, tax credit carryforwards
|
778
|
|
|
673
|
|
||
Derivative instruments and interest rate and currency swaps
|
43
|
|
|
68
|
|
||
Debt fair value adjustment
|
102
|
|
|
112
|
|
||
Investments
|
4,858
|
|
|
—
|
|
||
Other
|
31
|
|
|
43
|
|
||
Valuation allowances
|
(154
|
)
|
|
(95
|
)
|
||
Total deferred tax assets
|
6,110
|
|
|
1,175
|
|
||
Deferred tax liabilities
|
|
|
|
|
|
||
Property, plant and equipment
|
373
|
|
|
351
|
|
||
Investments
|
—
|
|
|
4,888
|
|
||
Other
|
30
|
|
|
20
|
|
||
Total deferred tax liabilities
|
403
|
|
|
5,259
|
|
||
Net deferred tax assets (liabilities)
|
$
|
5,707
|
|
|
$
|
(4,084
|
)
|
|
|
|
|
||||
Current deferred tax asset
|
$
|
56
|
|
|
$
|
567
|
|
Non-current deferred tax assets (liabilities)
|
5,651
|
|
|
(4,651
|
)
|
||
Net deferred tax assets (liabilities)
|
$
|
5,707
|
|
|
$
|
(4,084
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Balance at beginning of period
|
$
|
209
|
|
|
$
|
269
|
|
|
$
|
57
|
|
Uncertain tax positions of EP
|
—
|
|
|
4
|
|
|
289
|
|
|||
Subtotal
|
209
|
|
|
273
|
|
|
346
|
|
|||
Additions based on current year tax positions
|
12
|
|
|
11
|
|
|
11
|
|
|||
Additions based on prior year tax positions
|
—
|
|
|
26
|
|
|
1
|
|
|||
Reductions based on prior year tax positions
|
(3
|
)
|
|
—
|
|
|
—
|
|
|||
Reductions based on settlements with taxing authority
|
(24
|
)
|
|
(86
|
)
|
|
(55
|
)
|
|||
Reductions due to lapse in statute of limitations
|
(5
|
)
|
|
(15
|
)
|
|
(34
|
)
|
|||
Balance at end of period
|
$
|
189
|
|
|
$
|
209
|
|
|
$
|
269
|
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Natural gas, liquids, crude oil and CO
2
pipelines
|
$
|
18,119
|
|
|
$
|
17,399
|
|
Natural gas, liquids, CO
2
, and terminals station equipment
|
21,233
|
|
|
17,960
|
|
||
Natural gas, liquids (including linefill), and transmix processing
|
520
|
|
|
259
|
|
||
Other
|
3,964
|
|
|
3,656
|
|
||
Accumulated depreciation, depletion and amortization
|
(8,369
|
)
|
|
(6,757
|
)
|
||
|
35,467
|
|
|
32,517
|
|
||
Land and land rights-of-way
|
1,324
|
|
|
1,158
|
|
||
Construction work in process
|
1,773
|
|
|
2,172
|
|
||
Property, plant and equipment, net
|
$
|
38,564
|
|
|
$
|
35,847
|
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Citrus Corporation
|
$
|
1,805
|
|
|
$
|
1,875
|
|
Ruby Pipeline Holding Company, L.L.C.
|
1,123
|
|
|
1,153
|
|
||
Midcontinent Express Pipeline LLC
|
748
|
|
|
602
|
|
||
Gulf LNG Holdings Group, LLC
|
547
|
|
|
578
|
|
||
EagleHawk
|
337
|
|
|
272
|
|
||
Plantation Pipe Line Company
|
303
|
|
|
307
|
|
||
Red Cedar Gathering Company
|
184
|
|
|
176
|
|
||
Double Eagle Pipeline LLC
|
150
|
|
|
144
|
|
||
Parkway Pipeline LLC
|
144
|
|
|
131
|
|
||
Fayetteville Express Pipeline LLC
|
130
|
|
|
144
|
|
||
Watco Companies, LLC
|
103
|
|
|
103
|
|
||
Fort Union Gas Gathering L.L.C.
|
70
|
|
|
161
|
|
||
Sierrita Pipeline LLC
|
63
|
|
|
19
|
|
||
Cortez Pipeline Company
|
17
|
|
|
12
|
|
||
All others
|
304
|
|
|
266
|
|
||
Total equity investments
|
6,028
|
|
|
5,943
|
|
||
Bond investments
|
8
|
|
|
8
|
|
||
Total investments
|
$
|
6,036
|
|
|
$
|
5,951
|
|
•
|
Citrus Corporation—We own a
50%
interest in Citrus Corporation, the sole owner of Florida Gas Transmission Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities, independent power producers, municipal generators, and local distribution companies through a
5,300
-mile natural gas pipeline. Energy Transfer Partners L.P. operates and owns the remaining
50%
interest;
|
•
|
Ruby Pipeline Holding Company, L.L.C.—We operate and own a
50%
interest in Ruby Pipeline Holding Company, L.L.C., the sole owner of Ruby Pipeline natural gas transmission system. The remaining
50%
interest is owned by a subsidiary of Veresen Inc. as convertible preferred interests;
|
•
|
Midcontinent Express Pipeline LLC—We operate and own a
50%
interest in MEP, the sole owner of the Midcontinent Express natural gas pipeline system. The remaining
50%
ownership interest is owned by subsidiaries of Regency Energy Partners L.P.;
|
•
|
Gulf LNG Holdings Group, LLC—We operate and own a
50%
interest in Gulf LNG Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula, Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into various markets around the country. The remaining
50%
ownership interests are wholly and partially owned by subsidiaries of GE Financial Services and The Blackstone Group L.P.;
|
•
|
BHP Billiton Petroleum (Eagle Ford Gathering) LLC, f/k/a EagleHawk Field Services LLC and referred to in this report as EagleHawk—We own a
25%
interest in EagleHawk, the sole owner of natural gas and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton operates EagleHawk and owns the remaining
75%
ownership interest;
|
•
|
Plantation—We operate and own a
51.17%
interest in Plantation, the sole owner of the Plantation refined petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation owns the remaining interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered substantive participating rights; therefore, we do not control Plantation, and account for the investment under the equity method;
|
•
|
Red Cedar Gathering Company—We own a
49%
interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system. The Southern Ute Indian Tribe owns the remaining
51%
interest;
|
•
|
Double Eagle Pipeline LLC - We owns a
50%
equity interest in Double Eagle Pipeline LLC. The remaining
50%
interest is owned by Magellan Midstream Partners;
|
•
|
Parkway Pipeline LLC —We operate and own a
50%
interest in Parkway Pipeline LLC, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining
50%
interest;
|
•
|
Fayetteville Express Pipeline LLC —We own a
50%
interest in FEP, the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. owns the remaining
50%
interest and serves as operator of Fayetteville Express Pipeline LLC;
|
•
|
Watco Companies, LLC—We hold a preferred equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. We own
100,000
Class A preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash distributions from the preferred shares at a rate of
3.25%
per quarter, and participates partially in additional profit distributions at a rate equal to
0.5%
. The preferred shares have
no
conversion features and hold
no
voting powers, but do provide us certain approval rights, including the right to appoint
one
of the members to Watco’s Board of Managers;
|
•
|
Fort Union Gas Gathering LLC—We own a
37.04%
equity interest in the Fort Union Gas Gathering LLC. Crestone Powder River LLC, a subsidiary of ONEOK Partners, owns
37.04%
; WPX Energy Rocky Mountain, LLC owns
11.11%
; and Western Gas Wyoming, LLC owns the remaining
14.81%
. Western Gas Resources, Inc. serves as operator of Fort Union Gas Gathering LLC;
|
•
|
Sierrita Pipeline LLC — We operate and own a
35%
equity interest in the Sierrita Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns
35%
; and MIT Pipeline Investment Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns
30%
;
|
•
|
Cortez Pipeline Company—We operate and own a
50%
interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a
37%
interest and Cortez Vickers Pipeline Company owns the remaining
13%
interest; and
|
•
|
NGPL Holdco LLC— We operate and own a
20%
interest in NGPL Holdco LLC, the owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Citrus Corporation(a)
|
$
|
97
|
|
|
$
|
84
|
|
|
$
|
53
|
|
Fayetteville Express Pipeline LLC
|
55
|
|
|
55
|
|
|
55
|
|
|||
Gulf LNG Holdings Group, LLC(a)
|
48
|
|
|
47
|
|
|
22
|
|
|||
Midcontinent Express Pipeline LLC
|
45
|
|
|
40
|
|
|
42
|
|
|||
Red Cedar Gathering Company
|
33
|
|
|
31
|
|
|
32
|
|
|||
Plantation Pipe Line Company
|
29
|
|
|
35
|
|
|
32
|
|
|||
Cortez Pipeline Company
|
25
|
|
|
24
|
|
|
25
|
|
|||
Fort Union Gas Gathering L.L.C.(b)
|
16
|
|
|
11
|
|
|
—
|
|
|||
Ruby Pipeline Holding Company, L.L.C.(a)
|
15
|
|
|
(6
|
)
|
|
(5
|
)
|
|||
Watco Companies, LLC
|
13
|
|
|
13
|
|
|
13
|
|
|||
Parkway Pipeline LLC
|
8
|
|
|
1
|
|
|
—
|
|
|||
Sierrita Pipeline LLC
|
3
|
|
|
—
|
|
|
—
|
|
|||
NGPL Holdco LLC(c)
|
—
|
|
|
(66
|
)
|
|
(198
|
)
|
|||
Double Eagle Pipeline LLC(b)
|
(1
|
)
|
|
1
|
|
|
—
|
|
|||
EagleHawk
|
(7
|
)
|
|
9
|
|
|
11
|
|
|||
All others
|
27
|
|
|
48
|
|
|
71
|
|
|||
Total
|
$
|
406
|
|
|
$
|
327
|
|
|
$
|
153
|
|
Amortization of excess costs
|
$
|
(45
|
)
|
|
$
|
(39
|
)
|
|
$
|
(23
|
)
|
(a)
|
2012 amounts are for the period from May 25, 2012 through December 31, 2012.
|
(b)
|
2013 amounts are for the period from May 1, 2013 through December 31, 2013.
|
(c)
|
2013 and 2012 amounts include non-cash investment impairment charges, which we recorded in the amount of
$65 million
and
$200 million
(pre-tax), respectively.
|
|
|
Year Ended December 31,
|
||||||||||
Income Statement
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
|
|
$
|
3,829
|
|
|
$
|
3,615
|
|
|
$
|
3,681
|
|
Costs and expenses
|
|
3,063
|
|
|
2,803
|
|
|
3,194
|
|
|||
Net income (loss)
|
|
$
|
766
|
|
|
$
|
812
|
|
|
$
|
487
|
|
|
|
December 31,
|
||||||
Balance Sheet
|
|
2014
|
|
2013
|
||||
Current assets
|
|
$
|
943
|
|
|
$
|
950
|
|
Non-current assets
|
|
20,630
|
|
|
20,782
|
|
||
Current liabilities
|
|
1,643
|
|
|
1,451
|
|
||
Non-current liabilities
|
|
10,841
|
|
|
11,351
|
|
||
Partners’/owners’ equity
|
|
9,089
|
|
|
8,930
|
|
|
Natural Gas Pipelines
|
|
CO
2
|
|
Products Pipelines
|
|
Terminals
|
|
Kinder
Morgan
Canada
|
|
Total
|
||||||||||||
Historical Goodwill
|
$
|
22,276
|
|
|
$
|
1,528
|
|
|
$
|
2,129
|
|
|
$
|
1,484
|
|
|
$
|
626
|
|
|
$
|
28,043
|
|
Accumulated impairment losses
|
(2,090
|
)
|
|
—
|
|
|
(1,267
|
)
|
|
(677
|
)
|
|
(377
|
)
|
|
(4,411
|
)
|
||||||
Balance as of December 31, 2012
|
20,186
|
|
|
1,528
|
|
|
862
|
|
|
807
|
|
|
249
|
|
|
23,632
|
|
||||||
Acquisitions(a)
|
888
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
888
|
|
||||||
Currency translation adjustments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
(16
|
)
|
||||||
Balance as of December 31, 2013
|
21,074
|
|
|
1,528
|
|
|
862
|
|
|
807
|
|
|
233
|
|
|
24,504
|
|
||||||
Acquisitions(a)(b)
|
82
|
|
|
—
|
|
|
—
|
|
|
89
|
|
|
—
|
|
|
171
|
|
||||||
Currency translation adjustments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
||||||
Impairment
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
||||||
Balance as of December 31, 2014
|
$
|
21,156
|
|
|
$
|
1,528
|
|
|
$
|
862
|
|
|
$
|
894
|
|
|
$
|
214
|
|
|
$
|
24,654
|
|
(a)
|
2014 and 2013 Natural Gas Pipelines acquisition amounts include
$82 million
and
$881 million
, respectively, relating to the May 1, 2013 Copano acquisition as discussed in Note 3. 2013 Natural Gas Pipelines acquisition amount also includes
$7 million
relating to other EP acquisition assets.
|
(b)
|
2014 Terminals acquisition amount includes
$64 million
related to the January 17, 2014 APT acquisition and
$25 million
related to the November 5, 2014 Crowley acquisition.
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
KMI and Subsidiaries
|
|
|
|
||||
Senior term loan facilities, variable rate, due May 24, 2015 and May 6, 2017(a)
|
$
|
—
|
|
|
$
|
1,528
|
|
Senior notes and debentures, 2.00% through 8.25%, due 2014 through 2098(b)(c)(d)
|
11,438
|
|
|
5,645
|
|
||
Credit facility due November 26, 2019(e)(f)
|
850
|
|
|
175
|
|
||
Commercial paper borrowings(e)(f)
|
386
|
|
|
—
|
|
||
KMP
|
|
|
|
||||
Senior notes, 2.65% through 9.00%, due 2014 through 2044(b)
|
17,800
|
|
|
15,600
|
|
||
Commercial paper borrowings(g)(h)
|
—
|
|
|
979
|
|
||
Credit facility due May 1, 2018(g)
|
—
|
|
|
—
|
|
||
TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b)
|
1,790
|
|
|
1,790
|
|
||
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b)
|
1,115
|
|
|
1,115
|
|
||
Copano senior notes, 7.125% due April 1, 2021(b)
|
332
|
|
|
332
|
|
||
EPB
|
|
|
|
||||
EPPOC senior notes, 4.10% through 7.50%, due 2015 through 2042(b)(i)
|
2,860
|
|
|
2,260
|
|
||
Credit facility due May 27, 2016(g)
|
—
|
|
|
—
|
|
||
CIG, senior notes, 5.95% through 6.85%, due 2015 through 2037(b)(j)
|
475
|
|
|
475
|
|
||
SLNG senior notes, 9.50% through 9.75%, due 2014 through 2016(b)(k)
|
—
|
|
|
135
|
|
||
SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(l)
|
1,211
|
|
|
1,211
|
|
||
Other Subsidiary Borrowings (as obligor)
|
|
|
|
||||
Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b)
|
1,636
|
|
|
1,636
|
|
||
EPC Building, LLC, promissory note, 3.967%, due 2014 through 2035
|
453
|
|
|
461
|
|
||
Preferred securities, 4.75%, due March 31, 2028(d)(m)
|
280
|
|
|
280
|
|
||
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(n)
|
100
|
|
|
100
|
|
||
Other miscellaneous debt(o)
|
303
|
|
|
494
|
|
||
Total debt – KMI and Subsidiaries
|
41,029
|
|
|
34,216
|
|
||
Less: Current portion of debt(p)
|
2,717
|
|
|
2,306
|
|
||
Total long-term debt – KMI and Subsidiaries(q)
|
$
|
38,312
|
|
|
$
|
31,910
|
|
(a)
|
The senior secured term loan facility, due May 24, 2015, was repaid and replaced in May 2014 with a new unsecured senior term loan facility due May 6, 2017. The unsecured senior term loan facility was repaid in November 2014 (see “—Credit Facilities and Restrictive Covenants” below).
|
(b)
|
Notes provide for the redemption at any time at a price equal to
100%
of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium.
|
(c)
|
Includes
$6.0 billion
of senior notes issued on November 26, 2014 as a result of the Merger Transactions (see “—Debt Issuances and Repayments” below).
|
(d)
|
On June 30, 2014, El Paso Issuing Corporation, a wholly-owned subsidiary of El Paso Holdco LLC and the corporate co-issuer under certain guaranteed notes, merged with and into El Paso Holdco LLC, a wholly-owned subsidiary of KMI, and immediately thereafter, El Paso Holdco LLC merged with and into KMI pursuant to an internal restructuring transaction. KMI succeeded El Paso Holdco LLC as issuer with respect to these debt obligations. Consequently, El Paso Holdco LLC ceased to be an obligor with respect to approximately
$3.6 billion
of outstanding senior notes.
|
(e)
|
As of
December 31, 2014
and
2013
, the weighted average interest rates on our credit facility borrowings, including commercial paper borrowings in 2014, were
1.54%
and
2.67%
, respectively.
|
(f)
|
On November 26, 2014, we entered into a
$4 billion
replacement credit facility and a commercial paper program of up to
$4 billion
of unsecured notes (see “—Credit Facilities and Restrictive Covenants” below).
|
(g)
|
On November 26, 2014, in conjunction with the Merger Transactions, KMP’s and EPB’s credit facility and KMP’s commercial paper program were terminated.
|
(h)
|
As of
December 31, 2013
, the average interest rate on KMP’s outstanding commercial paper borrowings was
0.28%
. The borrowings under KMP’s commercial paper program were used principally to finance the acquisitions and capital expansions it made during 2014 and 2013.
|
(i)
|
EPPOC’s operating assets are its investments in WIC, CIG, SLNG, Elba Express, SNG, SLC, CPG, EP Ruby, LLC, Southern Gulf LNG Company, L.L.C. and CIG Gas Storage Company LLC. There are no significant restrictions on EPPOC’s ability to access the net assets or cash flows related to its controlling interests in the operating companies either through dividend or loan. The restrictive covenants
|
(j)
|
CIG is subject to a number of restrictions and covenants under its debt obligation. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
|
(k)
|
The SLNG senior notes were repaid on November 26, 2014.
|
(l)
|
Under its indentures, SNG is subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. Southern Natural Issuing Corporation (SNIC) is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of the debt securities. Accordingly, it has no ability to service obligations on the debt securities.
|
(m)
|
Capital Trust I (Trust I), is a
100%
-owned business trust that as of
December 31, 2014
, had
$5.6 million
of
4.75%
trust convertible preferred securities outstanding (referred to as the EP Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in
4.75%
convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the EP Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The EP Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of
4.75%
, carry a liquidation value of
$50
per security plus accrued and unpaid distributions and are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i)
0.7197
of a share of our Class P common stock; (ii)
$25.18
in cash without interest; and (iii)
1.100
warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the EP Trust I Preferred Securities into debt and equity components and as of
December 31, 2014
, the outstanding balance of
$280 million
(of which
$141 million
is classified as current) was bifurcated between debt (
$248 million
) and equity (
$32 million
). During the years ended
December 31, 2014
and
2013
,
3,923
and
107,618
EP Trust I Preferred Securities had been converted into (i)
2,820
and
77,442
shares of our Class P common stock; (ii) approximately
$99,000
and
$3 million
in cash; and (iii)
4,315
and
118,377
in warrants, respectively.
|
(n)
|
As of
December 31, 2014
, KMGP had outstanding
100,000
shares of its
$1,000
Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus
3.8975%
and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries (see “—KMGP Preferred Shares” below).
|
(o)
|
In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded
50%
of the construction costs. EPB reflected the payments made by their joint venture partner as other long-term liabilities on the balance sheet during construction and upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, EPB transferred its title in the projects to WYCO and leased the assets back. Although EPB transferred the title in these projects to WYCO, the transfer did not qualify for sale leaseback accounting because of EPB’s continuing involvement through its equity investment in WYCO. As such, the costs of the facilities remain on our balance sheets and the advanced payments received from EPB’s
50%
joint venture partner were converted into a financing obligation due to WYCO. As of
December 31, 2014
, the principal amounts of the Totem and High Plains financing obligations were
$73 million
and
$100 million
, respectively, which will be paid in monthly installments through 2039 based on the initial lease term. At the expiration of the initial lease term, the lease agreement shall be extended automatically for the term of related firm service agreements. The interest rate on these obligations is
15.5%
, payable on a monthly basis.
|
(p)
|
Includes commercial paper borrowings.
|
(q)
|
Excludes debt fair value adjustments. As of
December 31, 2014
and
December 31, 2013
, our total “Debt fair value adjustments” increased our combined debt carrying amounts by
$1,934 million
and
$1,977 million
, respectively. In addition to all unamortized debt discount/premium amounts and purchase accounting on our debt balances, our debt fair value adjustments also include (i) amounts associated with the offsetting entry for hedged debt and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 13.
|
•
|
total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed:
|
•
|
6.50
:
1.00
, for the period ended on or prior to December 31, 2017; or
|
•
|
6.25
:
1.00
, for the period ended after December 31, 2017 and on or prior to December 31, 2018; or
|
•
|
6.00
:
1.00
, for the period ended after December 31, 2018;
|
•
|
certain limitations on indebtedness, including payments and amendments;
|
•
|
certain limitations on entering into mergers, consolidations, sales of assets and investments;
|
•
|
limitations on granting liens; and
|
•
|
prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.
|
|
|
2014
|
|
2013
|
|
|
|
|
|
Issuances
|
|
$650 million senior term loan facility due 2017
|
|
$750 million 5.00% notes due 2021
|
|
|
$500 million 2.00% notes due 2017(b)
|
|
$750 million 5.625% notes due 2023
|
|
|
$1,500 million 3.05% notes due 2019(b)
|
|
$251 million EPC Building, LLC 3.967% promissory notes(a)
|
|
|
$1,500 million 4.30% notes due 2025(b)
|
|
$600 million 3.50% notes due 2023
|
|
|
$750 million 5.30% notes due 2034(b)
|
|
$700 million 5.00% notes due 2043
|
|
|
$1,750 million 5.55% notes due 2045(b)
|
|
$800 million 2.65% notes due 2019
|
|
|
$750 million 3.50% notes due 2021
|
|
$650 million 4.15% notes due 2024
|
|
|
$750 million 5.50% notes due 2044
|
|
|
|
|
$650 million 4.25% notes due 2024
|
|
|
|
|
$550 million 5.40% notes due 2044
|
|
|
|
|
$600 million 4.30% notes due 2024
|
|
|
|
|
|
|
|
Repayments
|
|
$500 million 5.125% notes due 2014
|
|
$500 million 5.00% notes due 2013
|
|
|
$1,528 million senior term loan facility due 2015
|
|
$1,186 million senior term loan facility due 2015
|
|
|
$650 million senior term loan facility due 2017(b)
|
|
$88 million 8.00% notes due 2013
|
|
|
$207 million 6.875% notes due 2014
|
|
$249 million 7.75% notes due 2018(c)
|
|
|
|
|
$178 million portion of 7.125% notes due 2021(d)
|
(a)
|
In December 2012, our subsidiary, EPC Building, LLC had issued
$468 million
of
3.967%
amortizing promissory notes with payments due 2013 through 2035, of which
$217 million
was issued to third parties and the remaining
$251 million
was held by KMI until they were sold to third parties in April of 2013.
|
|
|
Year Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
Per share cash distribution declared for the period(a)
|
|
$
|
41.860
|
|
|
$
|
42.101
|
|
Per share cash distribution paid in the period
|
|
$
|
41.877
|
|
|
$
|
42.169
|
|
(a)
|
On January 21, 2015, KMGP declared a distribution for the three months ended December 31, 2014, of
$10.553
per share, which was paid on February 18, 2015 to shareholders of record as of February 2, 2015.
|
Year
|
|
Total
|
||
2015
|
|
$
|
2,717
|
|
2016
|
|
1,684
|
|
|
2017
|
|
3,059
|
|
|
2018
|
|
2,328
|
|
|
2019
|
|
2,819
|
|
|
Thereafter
|
|
28,422
|
|
|
Total
|
|
$
|
41,029
|
|
|
Year Ended
December 31, 2014
|
|
Year Ended
December 31, 2013
|
|
Year Ended
December 31, 2012
|
|||||||||||||||
|
Shares
|
|
Weighted Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted Average
Grant Date
Fair Value
|
|||||||||
Outstanding at beginning of period
|
6,382,885
|
|
|
$
|
239
|
|
|
2,154,022
|
|
|
$
|
69
|
|
|
1,163,090
|
|
|
$
|
33
|
|
Granted
|
1,694,668
|
|
|
61
|
|
|
4,563,495
|
|
|
181
|
|
|
1,463,388
|
|
|
51
|
|
|||
Vested
|
(460,032
|
)
|
|
(14
|
)
|
|
(83,444
|
)
|
|
(3
|
)
|
|
(102,033
|
)
|
|
(3
|
)
|
|||
Forfeited
|
(244,227
|
)
|
|
(9
|
)
|
|
(251,188
|
)
|
|
(8
|
)
|
|
(370,423
|
)
|
|
(12
|
)
|
|||
Outstanding at end of period
|
7,373,294
|
|
|
$
|
277
|
|
|
6,382,885
|
|
|
$
|
239
|
|
|
2,154,022
|
|
|
$
|
69
|
|
Intrinsic value of restricted stock vested during the period
|
|
|
$
|
17
|
|
|
|
|
$
|
3
|
|
|
|
|
$
|
4
|
|
Year
|
|
Vesting of Restricted Shares
|
|
2015
|
|
713,675
|
|
2016
|
|
1,337,884
|
|
2017
|
|
1,653,507
|
|
2018
|
|
1,111,830
|
|
2019
|
|
1,720,568
|
|
2020
|
|
580,759
|
|
2021
|
|
199,725
|
|
2023
|
|
55,346
|
|
Total Outstanding
|
|
7,373,294
|
|
|
Pension Benefits
|
|
OPEB
|
||||||||||||
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of period
|
$
|
2,563
|
|
|
$
|
2,792
|
|
|
$
|
631
|
|
|
$
|
720
|
|
Service cost
|
21
|
|
|
25
|
|
|
—
|
|
|
—
|
|
||||
Interest cost
|
112
|
|
|
92
|
|
|
25
|
|
|
23
|
|
||||
Actuarial loss (gain)
|
294
|
|
|
(132
|
)
|
|
15
|
|
|
(38
|
)
|
||||
Benefits paid
|
(186
|
)
|
|
(239
|
)
|
|
(52
|
)
|
|
(54
|
)
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
3
|
|
|
11
|
|
||||
Medicare Part D subsidy receipts
|
—
|
|
|
—
|
|
|
2
|
|
|
6
|
|
||||
Plan amendments
|
—
|
|
|
25
|
|
|
—
|
|
|
(37
|
)
|
||||
Benefit obligation at end of period
|
2,804
|
|
|
2,563
|
|
|
624
|
|
|
631
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of period
|
2,333
|
|
|
2,240
|
|
|
380
|
|
|
341
|
|
||||
Actual return on plan assets
|
180
|
|
|
254
|
|
|
32
|
|
|
40
|
|
||||
Employer contributions
|
50
|
|
|
78
|
|
|
26
|
|
|
42
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
3
|
|
|
11
|
|
||||
Benefits paid
|
(186
|
)
|
|
(239
|
)
|
|
(52
|
)
|
|
(54
|
)
|
||||
Fair value of plan assets at end of period
|
2,377
|
|
|
2,333
|
|
|
389
|
|
|
380
|
|
||||
Funded status - net liability at December 31,
|
$
|
(427
|
)
|
|
$
|
(230
|
)
|
|
$
|
(235
|
)
|
|
$
|
(251
|
)
|
|
Pension Benefits
|
|
OPEB
|
||||||||||||
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Non-current benefit asset
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
173
|
|
|
$
|
224
|
|
Current benefit liability
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(32
|
)
|
||||
Non-current benefit liability
|
(427
|
)
|
|
(230
|
)
|
|
(386
|
)
|
|
(443
|
)
|
||||
Funded status - net liability at December 31,
|
$
|
(427
|
)
|
|
$
|
(230
|
)
|
|
$
|
(235
|
)
|
|
$
|
(251
|
)
|
|
Pension Benefits
|
|
OPEB
|
||||||||||||
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Unrecognized net actuarial loss
|
$
|
(296
|
)
|
|
$
|
(10
|
)
|
|
$
|
(27
|
)
|
|
$
|
(17
|
)
|
Unrecognized prior service (cost) credit
|
(4
|
)
|
|
(5
|
)
|
|
20
|
|
|
21
|
|
||||
Accumulated other comprehensive (loss) income
|
$
|
(300
|
)
|
|
$
|
(15
|
)
|
|
$
|
(7
|
)
|
|
$
|
4
|
|
•
|
Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, dollar-denominated money market funds, common and preferred stock, exchange traded mutual funds and limited partnerships. These investments are valued at the closing price reported on the active market on which the individual securities are traded.
|
•
|
Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are money market funds, common/collective trust funds, mutual funds, limited partnerships, trusts, fixed income and other securities. Money market funds are valued at amortized cost, which approximates fair value. The common/collective trust funds’, mutual funds’, limited partnerships’ and trusts’ fair values are based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market.
|
•
|
Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets and are also subject to certain restrictions associated with the timing of redemption which extend beyond
90
days as of December 31. Included in this level are insurance contracts, mutual funds with significant redemption restrictions, limited partnerships and private equity. Insurance contracts are valued at contract value, which approximates fair value. The mutual funds’ fair values are primarily based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The limited partnerships’ and private equity investments’ fair values are primarily based on the securities’ value as reported by the issuer, which may be determined utilizing discounted present value.
|
|
Pension Assets
|
||||||||||||||||||||||||||||||
|
2014
|
|
2013
|
||||||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
Cash and money market funds
|
$
|
5
|
|
|
$
|
91
|
|
|
$
|
—
|
|
|
$
|
96
|
|
|
$
|
—
|
|
|
$
|
20
|
|
|
$
|
—
|
|
|
$
|
20
|
|
Common/collective trusts(a)
|
—
|
|
|
863
|
|
|
—
|
|
|
863
|
|
|
—
|
|
|
920
|
|
|
—
|
|
|
920
|
|
||||||||
Insurance contracts
|
—
|
|
|
—
|
|
|
15
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
15
|
|
||||||||
Mutual funds(b)
|
71
|
|
|
198
|
|
|
—
|
|
|
269
|
|
|
92
|
|
|
134
|
|
|
—
|
|
|
226
|
|
||||||||
Common and preferred stocks(c)
|
459
|
|
|
—
|
|
|
—
|
|
|
459
|
|
|
498
|
|
|
—
|
|
|
—
|
|
|
498
|
|
||||||||
Corporate bonds
|
—
|
|
|
247
|
|
|
—
|
|
|
247
|
|
|
—
|
|
|
220
|
|
|
—
|
|
|
220
|
|
||||||||
U.S. government securities
|
—
|
|
|
190
|
|
|
—
|
|
|
190
|
|
|
—
|
|
|
120
|
|
|
—
|
|
|
120
|
|
||||||||
Asset backed securities
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
|
—
|
|
|
29
|
|
|
—
|
|
|
29
|
|
||||||||
Limited partnerships
|
—
|
|
|
—
|
|
|
16
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
28
|
|
|
28
|
|
||||||||
Equity trusts
|
—
|
|
|
199
|
|
|
—
|
|
|
199
|
|
|
—
|
|
|
235
|
|
|
—
|
|
|
235
|
|
||||||||
Private equity
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
||||||||
Other
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
13
|
|
|
—
|
|
|
13
|
|
||||||||
Total asset fair value(c)
|
$
|
535
|
|
|
$
|
1,801
|
|
|
$
|
41
|
|
|
$
|
2,377
|
|
|
$
|
590
|
|
|
$
|
1,691
|
|
|
$
|
52
|
|
|
$
|
2,333
|
|
(a)
|
For
2014
, this category includes common/collective trust funds which are invested in approximately
47%
fixed income and
53%
equity. For
2013
, this category includes common/collective trusts funds which are invested in approximately
36%
fixed income,
62%
equity and
2%
short term securities.
|
(b)
|
For
2014
, this category includes mutual funds which are invested in approximately
74%
fixed income and
26%
equity. For
2013
, this category includes mutual funds which are invested in approximately
60%
fixed income,
40%
equity and other investments.
|
(c)
|
Plan assets include
$252 million
and
$229 million
of KMI Class P common stock for
2014
and
2013
, respectively.
|
|
OPEB Assets
|
||||||||||||||||||||||||||||||
|
2014
|
|
2013
|
||||||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
Cash and money market funds
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Domestic equity securities
|
25
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
13
|
|
||||||||
Common/collective trusts(a)
|
—
|
|
|
71
|
|
|
—
|
|
|
71
|
|
|
—
|
|
|
85
|
|
|
—
|
|
|
85
|
|
||||||||
Fixed income trusts
|
—
|
|
|
63
|
|
|
—
|
|
|
63
|
|
|
65
|
|
|
—
|
|
|
—
|
|
|
65
|
|
||||||||
Limited partnerships
|
76
|
|
|
79
|
|
|
—
|
|
|
155
|
|
|
92
|
|
|
72
|
|
|
—
|
|
|
164
|
|
||||||||
Insurance contracts
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
46
|
|
||||||||
Mutual funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||||||
Total asset fair value
|
$
|
127
|
|
|
$
|
213
|
|
|
$
|
49
|
|
|
$
|
389
|
|
|
$
|
177
|
|
|
$
|
157
|
|
|
$
|
46
|
|
|
$
|
380
|
|
(a)
|
For
2014
, this category includes common/collective trust funds which are invested in approximately
67%
equity and
33%
fixed income securities. For
2013
, this category includes common/collective trust funds which are invested in approximately
70%
equity and
30%
fixed income securities.
|
|
Pension Assets
|
||||||||||||||||||
|
Balance at Beginning of Period
|
|
Transfers In (Out)
|
|
Realized and Unrealized Gains (Losses), net
|
|
Purchases (Sales), net
|
|
Balance at End of Period
|
||||||||||
2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Insurance contracts
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15
|
|
Limited partnerships
|
28
|
|
|
—
|
|
|
5
|
|
|
(17
|
)
|
|
16
|
|
|||||
Private equity
|
9
|
|
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
10
|
|
|||||
Total
|
$
|
52
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
(18
|
)
|
|
$
|
41
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Insurance contracts
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
15
|
|
Mutual funds
|
40
|
|
|
—
|
|
|
—
|
|
|
(40
|
)
|
|
—
|
|
|||||
Limited partnerships
|
24
|
|
|
—
|
|
|
3
|
|
|
1
|
|
|
28
|
|
|||||
Private equity
|
9
|
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
|
9
|
|
|||||
Total
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
(39
|
)
|
|
$
|
52
|
|
|
OPEB Assets
|
||||||||||||||||||
|
Balance at Beginning of Period
|
|
Transfers In (Out)
|
|
Realized and Unrealized Gains (Losses), net
|
|
Purchases (Sales), net
|
|
Balance at End of Period
|
||||||||||
2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Insurance contracts
|
$
|
46
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
6
|
|
|
$
|
49
|
|
Total
|
$
|
46
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
6
|
|
|
$
|
49
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Insurance contracts
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
46
|
|
Total
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
46
|
|
Fiscal year
|
|
Pension Benefits
|
|
OPEB(a)
|
||||
2015
|
|
$
|
190
|
|
|
$
|
46
|
|
2016
|
|
193
|
|
|
46
|
|
||
2017
|
|
193
|
|
|
45
|
|
||
2018
|
|
195
|
|
|
45
|
|
||
2019
|
|
195
|
|
|
44
|
|
||
2020-2024
|
|
965
|
|
|
209
|
|
(a)
|
Includes a reduction of approximately
$2 million
in each of the years 2015 - 2019 and approximately
$12 million
in aggregate for 2020 - 2024 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
|
|
|
Pension Benefits
|
|
OPEB
|
||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2014
|
|
2013
|
|
2012
|
||||||
Assumptions related to benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
|
3.66
|
%
|
|
4.45
|
%
|
|
3.40
|
%
|
|
3.56
|
%
|
|
4.34
|
%
|
|
3.34
|
%
|
Rate of compensation increase
|
|
4.50
|
%
|
|
3.50
|
%
|
|
3.00
|
%
|
|
n/a
|
|
n/a
|
|
n/a
|
|||
Assumptions related to benefit costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate(a)
|
|
4.45
|
%
|
|
3.40
|
%
|
|
4.22
|
%
|
|
4.34
|
%
|
|
3.62
|
%
|
|
4.11
|
%
|
Expected return on plan assets(b)(c)
|
|
7.50
|
%
|
|
8.00
|
%
|
|
8.44
|
%
|
|
7.43
|
%
|
|
7.35
|
%
|
|
8.21
|
%
|
Rate of compensation increase
|
|
3.50
|
%
|
|
3.00
|
%
|
|
3.50
|
%
|
|
n/a
|
|
n/a
|
|
n/a
|
(a)
|
The discount rate related to pension benefit cost was
4.50%
for the period from January 1, 2012 to May 24, 2012, and
4.03%
for the period from May 25, 2012 to December 31, 2012 (the period subsequent to the EP acquisition). The discount rate related to other postretirement benefit cost was
3.34%
for the period from January 1, 2013 to July 31, 2013 (the period prior to an OPEB plan amendment that resulted in a remeasurement) and
4.00%
for the period from August 1, 2013 to December 31, 2013, and
4.25%
for the period from January 1, 2012 to May 24, 2012 and
4.01%
for the period from May 25, 2012 to December 31, 2012.
|
(b)
|
The expected return on plan assets related to pension cost was
8.90%
for the period from January 1, 2012 to May 24, 2012, and
8.11%
for the period from May 25, 2012 to December 31, 2012 (the period subsequent to the EP acquisition). The expected return on plan assets related to other postretirement benefit cost was
8.90%
for the period from January 1, 2012 to May 24, 2012, and
7.72%
for the period from May 25, 2012 to December 31, 2012.
|
(c)
|
The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the assumed EP OPEB plans, we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of
21%
and
24%
for
2014
and
2013
, respectively.
|
|
|
2014
|
|
2013
|
||||
One-percentage point increase:
|
|
|
|
|
||||
Aggregate of service cost and interest cost
|
|
$
|
2
|
|
|
$
|
2
|
|
Accumulated postretirement benefit obligation
|
|
47
|
|
|
45
|
|
||
One-percentage point decrease:
|
|
|
|
|
||||
Aggregate of service cost and interest cost
|
|
$
|
(2
|
)
|
|
$
|
(1
|
)
|
Accumulated postretirement benefit obligation
|
|
(40
|
)
|
|
(39
|
)
|
|
|
Pension Benefits
|
|
OPEB
|
||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
Components of net benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
|
$
|
21
|
|
|
$
|
25
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost
|
|
112
|
|
|
92
|
|
|
67
|
|
|
25
|
|
|
23
|
|
|
18
|
|
||||||
Expected return on assets
|
|
(171
|
)
|
|
(175
|
)
|
|
(110
|
)
|
|
(24
|
)
|
|
(22
|
)
|
|
(15
|
)
|
||||||
Amortization of prior service (credit) cost
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
||||||
Amortization of net actuarial loss (gain)
|
|
—
|
|
|
—
|
|
|
10
|
|
|
(1
|
)
|
|
3
|
|
|
4
|
|
||||||
Curtailment and settlement gain
|
|
—
|
|
|
(3
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||
Net benefit (credit) cost
|
|
(38
|
)
|
|
(61
|
)
|
|
(18
|
)
|
|
(2
|
)
|
|
3
|
|
|
5
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net (gain) loss arising during period
|
|
285
|
|
|
(211
|
)
|
|
85
|
|
|
10
|
|
|
(50
|
)
|
|
25
|
|
||||||
Prior service cost (credit) arising during period
|
|
—
|
|
|
25
|
|
|
(17
|
)
|
|
—
|
|
|
(18
|
)
|
|
(4
|
)
|
||||||
Amortization or settlement recognition of net actuarial gain (loss)
|
|
—
|
|
|
3
|
|
|
(10
|
)
|
|
—
|
|
|
(3
|
)
|
|
(5
|
)
|
||||||
Amortization of prior service credit
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
||||||
Total recognized in total other comprehensive income loss
|
|
285
|
|
|
(183
|
)
|
|
59
|
|
|
11
|
|
|
(70
|
)
|
|
17
|
|
||||||
Total recognized in net benefit (credit) cost and other comprehensive (income) loss
|
|
$
|
247
|
|
|
$
|
(244
|
)
|
|
$
|
41
|
|
|
$
|
9
|
|
|
$
|
(67
|
)
|
|
$
|
22
|
|
|
Class P
|
|
Class A
|
|
Class B
|
|
Class C
|
||||
Balance at December 31, 2011
|
170,921,140
|
|
|
535,972,387
|
|
|
94,132,596
|
|
|
2,318,258
|
|
Shares issued for EP acquisition (see Note 3)
|
330,154,610
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Shares issued with conversions of EP Trust I Preferred securities
|
562,521
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Shares converted
|
535,972,387
|
|
|
(535,972,387
|
)
|
|
(94,132,596
|
)
|
|
(2,318,258
|
)
|
Shares canceled
|
(2,049,615
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Restricted shares vested
|
107,553
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Balance at December 31, 2012
|
1,035,668,596
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Shares issued for EP acquisition(a)
|
53
|
|
|
|
|
|
|
|
|||
Shares repurchased and canceled
|
(5,175,055
|
)
|
|
|
|
|
|
|
|||
Shares issued with conversions of EP Trust I Preferred securities
|
77,442
|
|
|
|
|
|
|
|
|||
Shares issued for exercised warrants
|
16,886
|
|
|
|
|
|
|
|
|||
Restricted shares vested
|
89,154
|
|
|
|
|
|
|
|
|||
Balance at December 31, 2013
|
1,030,677,076
|
|
|
|
|
|
|
|
|||
Shares issued for Merger Transactions
|
1,096,910,451
|
|
|
|
|
|
|
|
|||
Shares repurchased and canceled
|
(2,780,337
|
)
|
|
|
|
|
|
|
|||
Shares issued with conversions of EP Trust I Preferred securities
|
2,820
|
|
|
|
|
|
|
|
|||
Shares issued for exercised warrants
|
12,402
|
|
|
|
|
|
|
|
|||
Restricted shares vested
|
324,704
|
|
|
|
|
|
|
|
|||
Balance at December 31, 2014
|
2,125,147,116
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Per common share cash dividend declared for the period
|
$
|
1.74
|
|
|
$
|
1.60
|
|
|
$
|
1.40
|
|
Per common share cash dividend paid in the period
|
1.70
|
|
|
1.56
|
|
|
1.34
|
|
|
Warrants
|
|||||||
|
2014
|
|
2013
|
|
2012
|
|||
Beginning balance
|
347,933,107
|
|
|
439,809,442
|
|
|
—
|
|
Warrants issued in EP acquisition(a)
|
—
|
|
|
81
|
|
|
504,598,883
|
|
Warrants issued with conversions of EP Trust I Preferred securities(b)
|
4,315
|
|
|
118,377
|
|
|
859,796
|
|
Warrants exercised
|
(18,040
|
)
|
|
(21,208
|
)
|
|
—
|
|
Warrants repurchased and canceled
|
(49,783,406
|
)
|
|
(91,973,585
|
)
|
|
(65,649,237
|
)
|
Ending balance
|
298,135,976
|
|
|
347,933,107
|
|
|
439,809,442
|
|
(a)
|
See Note 3. 2013 amount represents warrants issued upon the settlement of an EP dissenter. The settlement of the dissenter’s
128
EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition.
|
(b)
|
See Note 8.
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
KMP
|
$
|
—
|
|
|
$
|
7,642
|
|
EPB
|
—
|
|
|
4,122
|
|
||
KMR
|
—
|
|
|
3,142
|
|
||
Other
|
350
|
|
|
286
|
|
||
|
$
|
350
|
|
|
$
|
15,192
|
|
(a)
|
Prior to the completion of the Merger Transactions on November 26, 2014, KMP was a party to two equity distribution agreements with UBS Securities LLC (UBS), one of which allowed the aggregate offering price of KMP’s common units of up to
$2.175 billion
, and a second separate equity distribution agreement which allowed the aggregate offering price of up to
$1.9 billion
.
|
(b)
|
KMP valued these units at
$3,733 million
based on the
$86.08
closing market price of a KMP common unit on the NYSE on May 1, 2013.
|
(c)
|
Prior to the completion of the Merger Transactions on November 26, 2014, EPB was a party to an equity distribution agreement with Citigroup. Pursuant to the provisions of EPB’s equity distribution agreement, EPB could sell from time to time through Citigroup, as its sales agent, EPB’s common units representing limited partner interests having an aggregate offering price of up to
$500 million
.
|
(d)
|
Prior to the completion of the Merger Transactions on November 26, 2014, KMR was a party to an equity distribution agreement with Credit Suisse Securities (U.S.A.) LLC (Credit Suisse). Pursuant to the provisions of KMR’s equity distribution agreement, it could sell from time to time through Credit Suisse, as its sales agent, KMR shares having an aggregate offering price of up to
$500 million
.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
KMP(a)
|
|
|
|
|
|
||||||
Per unit cash distribution declared for the period
|
$
|
4.17
|
|
|
$
|
5.33
|
|
|
$
|
4.98
|
|
Per unit cash distribution paid in the period
|
$
|
5.53
|
|
|
$
|
5.26
|
|
|
$
|
4.85
|
|
Cash distributions paid in the period to the public
|
$
|
1,654
|
|
|
$
|
1,372
|
|
|
$
|
1,081
|
|
EPB(a)(b)
|
|
|
|
|
|
||||||
Per unit cash distribution declared for the period
|
$
|
1.95
|
|
|
$
|
2.55
|
|
|
$
|
1.74
|
|
Per unit cash distribution paid in the period
|
$
|
2.60
|
|
|
$
|
2.51
|
|
|
$
|
1.13
|
|
Cash distributions paid in the period to the public
|
$
|
347
|
|
|
$
|
318
|
|
|
$
|
137
|
|
KMR(a)(c)
|
|
|
|
|
|
||||||
Share distributions paid in the period to the public
|
7,794,183
|
|
|
6,588,477
|
|
|
5,586,579
|
|
(a)
|
As a result of the Merger Transactions, no distribution was declared for the fourth quarter of 2014.
|
(b)
|
Represents distribution information since the May 2012 EP acquisition.
|
(c)
|
KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests and excludes
1,127,712
,
976,723
and
902,367
of shares distributed in 2014, 2013 and 2012, respectively, on KMR shares we directly and indirectly owned.
|
|
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Balance sheet location
|
|
|
|
||||
Accounts receivable, net
|
$
|
31
|
|
|
$
|
19
|
|
Other current assets
|
3
|
|
|
3
|
|
||
Deferred charges and other assets
|
46
|
|
|
47
|
|
||
|
$
|
80
|
|
|
$
|
69
|
|
|
|
|
|
||||
Current portion of debt(a)
|
$
|
6
|
|
|
$
|
6
|
|
Accounts payable
|
22
|
|
|
9
|
|
||
Long-term debt(a)
|
172
|
|
|
169
|
|
||
|
$
|
200
|
|
|
$
|
184
|
|
(a)
|
Includes financing obligations payable to WYCO (See Note 8).
|
Year
|
|
Commitment
|
||
2015
|
|
$
|
97
|
|
2016
|
|
85
|
|
|
2017
|
|
75
|
|
|
2018
|
|
67
|
|
|
2019
|
|
65
|
|
|
Thereafter
|
|
289
|
|
|
Total minimum payments
|
|
$
|
678
|
|
|
Net open position long/(short)
|
||
Derivatives designated as hedging contracts
|
|
|
|
Crude oil fixed price
|
(10.9
|
)
|
MMBbl
|
Crude oil basis
|
(10.8
|
)
|
MMBbl
|
Natural gas fixed price
|
(27.2
|
)
|
Bcf
|
Natural gas basis
|
(8.0
|
)
|
Bcf
|
Derivatives not designated as hedging contracts
|
|
|
|
Crude oil fixed price
|
(14.9
|
)
|
MMBbl
|
Natural gas fixed price
|
2.0
|
|
Bcf
|
Natural gas basis
|
6.5
|
|
Bcf
|
NGL fixed price
|
(2.1
|
)
|
MMBbl
|
Fair Value of Derivative Contracts
|
|||||||||||||||||
|
|
|
Asset derivatives
|
|
Liability derivatives
|
||||||||||||
|
|
|
December 31,
|
|
December 31,
|
||||||||||||
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
|
Balance sheet location
|
|
Fair value
|
|
Fair value
|
||||||||||||
Derivatives designated as hedging contracts
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas and crude derivative contracts
|
Other current assets/(Other current liabilities)
|
|
$
|
309
|
|
|
$
|
18
|
|
|
$
|
(34
|
)
|
|
$
|
(33
|
)
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
6
|
|
|
58
|
|
|
—
|
|
|
(30
|
)
|
||||
Subtotal
|
|
|
315
|
|
|
76
|
|
|
(34
|
)
|
|
(63
|
)
|
||||
Interest rate swap agreements
|
Other current assets/(Other current liabilities)
|
|
143
|
|
|
87
|
|
|
—
|
|
|
—
|
|
||||
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
260
|
|
|
172
|
|
|
(53
|
)
|
|
(116
|
)
|
||||
Subtotal
|
|
|
403
|
|
|
259
|
|
|
(53
|
)
|
|
(116
|
)
|
||||
Total
|
|
|
718
|
|
|
335
|
|
|
(87
|
)
|
|
(179
|
)
|
||||
Derivatives not designated as hedging contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Natural gas, crude and NGL derivative contracts
|
Other current assets/(Other current liabilities)
|
|
73
|
|
|
4
|
|
|
(2
|
)
|
|
(5
|
)
|
||||
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
196
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Subtotal
|
|
|
269
|
|
|
4
|
|
|
(2
|
)
|
|
(5
|
)
|
||||
Power derivative contracts
|
Other current assets/(Other current liabilities)
|
|
10
|
|
|
7
|
|
|
(57
|
)
|
|
(54
|
)
|
||||
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
—
|
|
|
11
|
|
|
(16
|
)
|
|
(73
|
)
|
||||
Subtotal
|
|
|
10
|
|
|
18
|
|
|
(73
|
)
|
|
(127
|
)
|
||||
Total
|
|
|
279
|
|
|
22
|
|
|
(75
|
)
|
|
(132
|
)
|
||||
Total derivatives
|
|
|
$
|
997
|
|
|
$
|
357
|
|
|
$
|
(162
|
)
|
|
$
|
(311
|
)
|
Derivatives in fair value hedging relationships
|
|
Location of gain/(loss)recognized in income on derivatives
|
|
Amount of gain/(loss)recognized in income on derivatives and related hedged item
|
||||||||||
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
Interest rate swap agreements
|
|
Interest expense
|
|
$
|
207
|
|
|
$
|
(425
|
)
|
|
$
|
55
|
|
Total
|
|
|
|
$
|
207
|
|
|
$
|
(425
|
)
|
|
$
|
55
|
|
Fixed rate debt
|
|
Interest expense
|
|
$
|
(204
|
)
|
|
$
|
425
|
|
|
$
|
(55
|
)
|
Total
|
|
|
|
$
|
(204
|
)
|
|
$
|
425
|
|
|
$
|
(55
|
)
|
Derivatives in cash flow hedging relationships
|
|
Amount of gain/(loss) recognized in OCI on derivative (effective portion)(a)
|
|
Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)
|
|
Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)
|
|
Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
|
|
Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
|
||||||||||||||||||||||||||||||
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
Year Ended
|
||||||||||||||||||||||||||||||
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
||||||||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
|
|
2014
|
|
2013
|
|
2012
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||||||||
Energy commodity derivative contracts
|
|
$
|
423
|
|
|
$
|
(45
|
)
|
|
$
|
87
|
|
|
Revenues—Natural gas sales
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
4
|
|
|
Revenues—Natural gas sales
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Revenues—Product sales and other
|
|
26
|
|
|
(13
|
)
|
|
(15
|
)
|
|
Revenues—Product sales and other
|
|
11
|
|
|
3
|
|
|
(11
|
)
|
||||||||||
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
4
|
|
|
—
|
|
|
17
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||||
Interest rate swap agreements
|
|
(15
|
)
|
|
7
|
|
|
(5
|
)
|
|
Interest expense
|
|
(4
|
)
|
|
2
|
|
|
2
|
|
|
Interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Total
|
|
$
|
408
|
|
|
$
|
(38
|
)
|
|
$
|
82
|
|
|
Total
|
|
$
|
25
|
|
|
$
|
(11
|
)
|
|
$
|
8
|
|
|
Total
|
|
$
|
11
|
|
|
$
|
3
|
|
|
$
|
(11
|
)
|
(a)
|
We expect to reclassify an approximate
$208 million
gain associated with energy commodity price risk management activities included in our accumulated other comprehensive loss balance as of
December 31, 2014
into earnings during the next
twelve
months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
|
(b)
|
Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
|
Derivatives not designated as accounting hedges
|
|
Location of gain/(loss) recognized in income on derivatives
|
|
Amount of gain/(loss) recognized in income on derivatives
|
||||||||||
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
Energy commodity derivative contracts
|
|
Revenues—Natural gas sales
|
|
$
|
(7
|
)
|
|
$
|
—
|
|
|
$
|
1
|
|
|
|
Revenues—Product sales and other
|
|
20
|
|
|
(10
|
)
|
|
(4
|
)
|
|||
|
|
Costs of sales
|
|
—
|
|
|
2
|
|
|
—
|
|
|||
|
|
Other expense (income)
|
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Total
|
|
|
|
$
|
11
|
|
|
$
|
(10
|
)
|
|
$
|
(3
|
)
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
Accumulated other
comprehensive
income/(loss)
|
||||||||
Balance as of December 31, 2011
|
$
|
(20
|
)
|
|
$
|
37
|
|
|
$
|
(132
|
)
|
|
$
|
(115
|
)
|
Other comprehensive income before reclassifications
|
32
|
|
|
14
|
|
|
(53
|
)
|
|
(7
|
)
|
||||
Amounts reclassified from accumulated other comprehensive loss
|
(5
|
)
|
|
—
|
|
|
9
|
|
|
4
|
|
||||
Net current-period other comprehensive income
|
27
|
|
|
14
|
|
|
(44
|
)
|
|
(3
|
)
|
||||
Balance as of December 31, 2012
|
7
|
|
|
51
|
|
|
(176
|
)
|
|
(118
|
)
|
||||
Other comprehensive income before reclassifications
|
(14
|
)
|
|
(49
|
)
|
|
151
|
|
|
88
|
|
||||
Amounts reclassified from accumulated other comprehensive loss
|
4
|
|
|
—
|
|
|
2
|
|
|
6
|
|
||||
Net current-period other comprehensive income
|
(10
|
)
|
|
(49
|
)
|
|
153
|
|
|
94
|
|
||||
Balance as of December 31, 2013
|
(3
|
)
|
|
2
|
|
|
(23
|
)
|
|
(24
|
)
|
||||
Other comprehensive income before reclassifications
|
254
|
|
|
(68
|
)
|
|
(212
|
)
|
|
(26
|
)
|
||||
Amounts reclassified from accumulated other comprehensive loss
|
(22
|
)
|
|
—
|
|
|
(1
|
)
|
|
(23
|
)
|
||||
Impact of Merger Transactions (See Note 1)
|
98
|
|
|
(42
|
)
|
|
—
|
|
|
56
|
|
||||
Net current-period other comprehensive income
|
330
|
|
|
(110
|
)
|
|
(213
|
)
|
|
7
|
|
||||
Balance as of December 31, 2014
|
$
|
327
|
|
|
$
|
(108
|
)
|
|
$
|
(236
|
)
|
|
$
|
(17
|
)
|
•
|
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
|
•
|
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
|
•
|
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
|
|
Balance sheet asset fair value measurements using
|
|
Amounts not offset in the balance sheet
|
|
|
||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Financial instruments
|
|
Cash collateral held(b)
|
|
Net amount
|
||||||||||||||
As of December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Energy commodity derivative contracts(a)
|
$
|
49
|
|
|
$
|
533
|
|
|
$
|
12
|
|
|
$
|
594
|
|
|
$
|
(46
|
)
|
|
$
|
(13
|
)
|
|
$
|
535
|
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
403
|
|
|
$
|
—
|
|
|
$
|
403
|
|
|
$
|
(44
|
)
|
|
$
|
—
|
|
|
$
|
359
|
|
As of December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Energy commodity derivative contracts(a)
|
$
|
4
|
|
|
$
|
46
|
|
|
$
|
48
|
|
|
$
|
98
|
|
|
$
|
(62
|
)
|
|
$
|
—
|
|
|
$
|
36
|
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
259
|
|
|
$
|
—
|
|
|
$
|
259
|
|
|
$
|
(28
|
)
|
|
$
|
—
|
|
|
$
|
231
|
|
|
Balance sheet liability
fair value measurements using
|
|
Amounts not offset in the balance sheet
|
|
|
||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Financial instruments
|
|
Cash collateral posted(c)
|
|
Net amount
|
||||||||||||||
As of December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Energy commodity derivative contracts(a)
|
$
|
(25
|
)
|
|
$
|
(11
|
)
|
|
$
|
(73
|
)
|
|
$
|
(109
|
)
|
|
$
|
46
|
|
|
$
|
47
|
|
|
$
|
(16
|
)
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
(53
|
)
|
|
$
|
—
|
|
|
$
|
(53
|
)
|
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
(9
|
)
|
As of December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Energy commodity derivative contracts(a)
|
$
|
(6
|
)
|
|
$
|
(31
|
)
|
|
$
|
(158
|
)
|
|
$
|
(195
|
)
|
|
$
|
62
|
|
|
$
|
17
|
|
|
$
|
(116
|
)
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
(116
|
)
|
|
$
|
—
|
|
|
$
|
(116
|
)
|
|
$
|
28
|
|
|
$
|
—
|
|
|
$
|
(88
|
)
|
(a)
|
Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options. Level 3 consists primarily of power derivative contracts.
|
(b)
|
Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets.
|
(c)
|
Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current assets” on our accompanying consolidated balance sheets.
|
Significant unobservable inputs (Level 3)
|
|||||||
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
Derivatives-net asset (liability)
|
|
|
|
||||
Beginning of period
|
$
|
(110
|
)
|
|
$
|
(155
|
)
|
Transfers out(a)
|
(88
|
)
|
|
—
|
|
||
Total gains or (losses)
|
|
|
|
|
|
||
Included in earnings
|
22
|
|
|
(5
|
)
|
||
Included in other comprehensive loss
|
78
|
|
|
(1
|
)
|
||
Purchases(b)
|
—
|
|
|
17
|
|
||
Settlements
|
37
|
|
|
34
|
|
||
End of period
|
$
|
(61
|
)
|
|
$
|
(110
|
)
|
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date
|
$
|
1
|
|
|
$
|
(8
|
)
|
|
December 31, 2014
|
|
December 31, 2013
|
||||||||||||
|
Carrying
value
|
|
Estimated
fair value
|
|
Carrying
value
|
|
Estimated
fair value
|
||||||||
Total debt
|
$
|
42,963
|
|
|
$
|
43,582
|
|
|
$
|
36,193
|
|
|
$
|
36,248
|
|
•
|
Natural Gas Pipelines—(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas and crude oil gathering systems and natural gas processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;
|
•
|
CO
2
—(i) the production, transportation and marketing of CO
2
to oil fields that use CO
2
as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil
|
•
|
Terminals—(i) the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;
|
•
|
Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
|
•
|
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; and
|
•
|
Other—primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
|
|
|
|
|
||||||
Revenues from external customers
|
$
|
10,153
|
|
|
$
|
8,613
|
|
|
$
|
5,230
|
|
Intersegment revenues
|
15
|
|
|
4
|
|
|
—
|
|
|||
CO
2
|
1,960
|
|
|
1,857
|
|
|
1,677
|
|
|||
Terminals
|
|
|
|
|
|
|
|
|
|||
Revenues from external customers
|
1,717
|
|
|
1,408
|
|
|
1,356
|
|
|||
Intersegment revenues
|
1
|
|
|
2
|
|
|
3
|
|
|||
Products Pipelines
|
2,068
|
|
|
1,853
|
|
|
1,370
|
|
|||
Kinder Morgan Canada
|
291
|
|
|
302
|
|
|
311
|
|
|||
Other
|
1
|
|
|
1
|
|
|
(6
|
)
|
|||
Total segment revenues
|
16,206
|
|
|
14,040
|
|
|
9,941
|
|
|||
Other revenues(b)
|
36
|
|
|
36
|
|
|
35
|
|
|||
Less: Total intersegment revenues
|
(16
|
)
|
|
(6
|
)
|
|
(3
|
)
|
|||
Total consolidated revenues
|
$
|
16,226
|
|
|
$
|
14,070
|
|
|
$
|
9,973
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Operating expenses(c)
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
$
|
6,241
|
|
|
$
|
5,235
|
|
|
$
|
3,111
|
|
CO
2
|
494
|
|
|
439
|
|
|
381
|
|
|||
Terminals
|
746
|
|
|
657
|
|
|
685
|
|
|||
Products Pipelines
|
1,258
|
|
|
1,295
|
|
|
759
|
|
|||
Kinder Morgan Canada
|
106
|
|
|
110
|
|
|
103
|
|
|||
Other
|
24
|
|
|
30
|
|
|
5
|
|
|||
Total segment operating expenses
|
8,869
|
|
|
7,766
|
|
|
5,044
|
|
|||
Other operating expenses
|
—
|
|
|
—
|
|
|
4
|
|
|||
Less: Total intersegment operating expenses
|
(16
|
)
|
|
(6
|
)
|
|
(3
|
)
|
|||
Total consolidated operating expenses
|
$
|
8,853
|
|
|
$
|
7,760
|
|
|
$
|
5,045
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Other expense (income)
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
$
|
5
|
|
|
$
|
(24
|
)
|
|
$
|
14
|
|
CO
2
(d)
|
243
|
|
|
—
|
|
|
(7
|
)
|
|||
Terminals
|
29
|
|
|
(74
|
)
|
|
(14
|
)
|
|||
Products Pipelines
|
(3
|
)
|
|
6
|
|
|
(5
|
)
|
|||
Other
|
1
|
|
|
(7
|
)
|
|
(1
|
)
|
|||
Total consolidated other expense (income)
|
$
|
275
|
|
|
$
|
(99
|
)
|
|
$
|
(13
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
DD&A
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
$
|
897
|
|
|
$
|
797
|
|
|
$
|
478
|
|
CO
2
|
570
|
|
|
533
|
|
|
494
|
|
|||
Terminals
|
337
|
|
|
247
|
|
|
236
|
|
|||
Products Pipelines
|
166
|
|
|
155
|
|
|
143
|
|
|||
Kinder Morgan Canada
|
51
|
|
|
54
|
|
|
56
|
|
|||
Other
|
19
|
|
|
20
|
|
|
12
|
|
|||
Total consolidated DD&A
|
$
|
2,040
|
|
|
$
|
1,806
|
|
|
$
|
1,419
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Earnings from equity investments
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)(e)
|
$
|
318
|
|
|
$
|
232
|
|
|
$
|
52
|
|
CO
2
|
25
|
|
|
24
|
|
|
25
|
|
|||
Terminals
|
18
|
|
|
22
|
|
|
21
|
|
|||
Products Pipelines
|
44
|
|
|
45
|
|
|
39
|
|
|||
Kinder Morgan Canada
|
—
|
|
|
4
|
|
|
5
|
|
|||
Other
|
1
|
|
|
—
|
|
|
11
|
|
|||
Total consolidated equity earnings
|
$
|
406
|
|
|
$
|
327
|
|
|
$
|
153
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Amortization of excess cost of equity investments
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
$
|
39
|
|
|
$
|
32
|
|
|
$
|
17
|
|
CO
2
|
(1
|
)
|
|
2
|
|
|
2
|
|
|||
Products Pipelines
|
7
|
|
|
5
|
|
|
4
|
|
|||
Total consolidated amortization of excess cost of equity investments
|
$
|
45
|
|
|
$
|
39
|
|
|
$
|
23
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Interest income
|
|
|
|
|
|
||||||
Natural Gas Pipelines
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
18
|
|
Products Pipelines
|
2
|
|
|
2
|
|
|
2
|
|
|||
Kinder Morgan Canada
|
—
|
|
|
3
|
|
|
14
|
|
|||
Other
|
6
|
|
|
8
|
|
|
3
|
|
|||
Total segment interest income
|
9
|
|
|
13
|
|
|
37
|
|
|||
Unallocated interest income
|
—
|
|
|
2
|
|
|
(9
|
)
|
|||
Total consolidated interest income
|
$
|
9
|
|
|
$
|
15
|
|
|
$
|
28
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Other, net-income (expense)
|
|
|
|
|
|
||||||
Natural Gas Pipelines(f)
|
$
|
24
|
|
|
$
|
578
|
|
|
$
|
4
|
|
CO
2
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Terminals
|
12
|
|
|
1
|
|
|
2
|
|
|||
Products Pipelines
|
(1
|
)
|
|
1
|
|
|
9
|
|
|||
Kinder Morgan Canada(g)
|
15
|
|
|
246
|
|
|
3
|
|
|||
Other
|
30
|
|
|
9
|
|
|
2
|
|
|||
Total consolidated other, net-income (expense)
|
$
|
80
|
|
|
$
|
835
|
|
|
$
|
19
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Income tax benefit (expense)
|
|
|
|
|
|
||||||
Natural Gas Pipelines
|
$
|
(6
|
)
|
|
$
|
(9
|
)
|
|
$
|
(5
|
)
|
CO
2
|
(8
|
)
|
|
(7
|
)
|
|
(5
|
)
|
|||
Terminals
|
(29
|
)
|
|
(14
|
)
|
|
(3
|
)
|
|||
Products Pipelines
|
(2
|
)
|
|
2
|
|
|
2
|
|
|||
Kinder Morgan Canada
|
(18
|
)
|
|
(21
|
)
|
|
(1
|
)
|
|||
Total segment income tax expense
|
(63
|
)
|
|
(49
|
)
|
|
(12
|
)
|
|||
Unallocated income tax expense
|
(585
|
)
|
|
(693
|
)
|
|
(127
|
)
|
|||
Total consolidated income tax expense
|
$
|
(648
|
)
|
|
$
|
(742
|
)
|
|
$
|
(139
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Segment EBDA(h)
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
$
|
4,259
|
|
|
$
|
4,207
|
|
|
$
|
2,174
|
|
CO
2
|
1,240
|
|
|
1,435
|
|
|
1,322
|
|
|||
Terminals
|
944
|
|
|
836
|
|
|
708
|
|
|||
Products Pipelines
|
856
|
|
|
602
|
|
|
668
|
|
|||
Kinder Morgan Canada
|
182
|
|
|
424
|
|
|
229
|
|
|||
Other
|
13
|
|
|
(5
|
)
|
|
7
|
|
|||
Total segment EBDA
|
7,494
|
|
|
7,499
|
|
|
5,108
|
|
|||
Total segment DD&A
|
(2,040
|
)
|
|
(1,806
|
)
|
|
(1,419
|
)
|
|||
Total segment amortization of excess cost of equity investments
|
(45
|
)
|
|
(39
|
)
|
|
(23
|
)
|
|||
Other revenues
|
36
|
|
|
36
|
|
|
35
|
|
|||
General and administrative expenses(i)
|
(610
|
)
|
|
(613
|
)
|
|
(929
|
)
|
|||
Interest expense, net of unallocable interest income(j)
|
(1,807
|
)
|
|
(1,688
|
)
|
|
(1,441
|
)
|
|||
Unallocable income tax expense
|
(585
|
)
|
|
(693
|
)
|
|
(127
|
)
|
|||
Loss from discontinued operations, net of tax(k)
|
—
|
|
|
(4
|
)
|
|
(777
|
)
|
|||
Total consolidated net income
|
$
|
2,443
|
|
|
$
|
2,692
|
|
|
$
|
427
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Capital expenditures
|
|
|
|
|
|
||||||
Natural Gas Pipelines(a)
|
$
|
935
|
|
|
$
|
1,085
|
|
|
$
|
499
|
|
CO
2
|
792
|
|
|
667
|
|
|
453
|
|
|||
Terminals
|
1,049
|
|
|
1,108
|
|
|
707
|
|
|||
Products Pipelines
|
680
|
|
|
416
|
|
|
307
|
|
|||
Kinder Morgan Canada
|
156
|
|
|
77
|
|
|
16
|
|
|||
Other
|
5
|
|
|
16
|
|
|
40
|
|
|||
Total consolidated capital expenditures
|
$
|
3,617
|
|
|
$
|
3,369
|
|
|
$
|
2,022
|
|
|
2014
|
|
2013
|
|
|
||||
Investments at December 31
|
|
|
|
|
|
||||
Natural Gas Pipelines(a)
|
5,174
|
|
|
$
|
5,130
|
|
|
|
|
CO
2
|
17
|
|
|
12
|
|
|
|
||
Terminals
|
219
|
|
|
196
|
|
|
|
||
Products Pipelines
|
624
|
|
|
611
|
|
|
|
||
Kinder Morgan Canada
|
1
|
|
|
1
|
|
|
|
||
Other
|
1
|
|
|
1
|
|
|
|
||
Total consolidated investments
|
$
|
6,036
|
|
|
$
|
5,951
|
|
|
|
|
2014
|
|
2013
|
|
|
||||
Assets at December 31
|
|
|
|
|
|
||||
Natural Gas Pipelines
|
$
|
52,523
|
|
|
$
|
52,357
|
|
|
|
CO
2
|
5,227
|
|
|
4,708
|
|
|
|
||
Terminals
|
8,850
|
|
|
6,888
|
|
|
|
||
Products Pipelines
|
7,179
|
|
|
6,648
|
|
|
|
||
Kinder Morgan Canada
|
1,593
|
|
|
1,677
|
|
|
|
||
Other
|
459
|
|
|
568
|
|
|
|
||
Total segment assets
|
75,831
|
|
|
72,846
|
|
|
|
||
Corporate assets(l)
|
7,311
|
|
|
2,339
|
|
|
|
||
Assets held for sale
|
56
|
|
|
—
|
|
|
|
||
Total consolidated assets
|
$
|
83,198
|
|
|
$
|
75,185
|
|
|
|
(a)
|
The Copano acquisition was effective May 1, 2013 and the EP acquisition was effective May 25, 2012 (see Note 3).
|
(b)
|
Includes a management fee for services we perform for NGPL Holdco LLC.
|
(c)
|
Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
|
(d)
|
2014 amount includes an impairment charge of
$235 million
primarily related to the Katz Strawn unit.
|
(e)
|
2013 and 2012 amounts include impairment charges of
$65 million
and
$200 million
, respectively, to reduce the carrying value of our equity investment in NGPL Holdco LLC.
|
(f)
|
2013 amount includes a
$558 million
gain from the remeasurement of our previously held
50%
equity interest in Eagle Ford to fair value (See Note 3).
|
(g)
|
2013 amount includes a
$224 million
pre-tax gain from the sale of our equity and debt investments in the Express pipeline system (See Note 3).
|
(h)
|
Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
|
(i)
|
2012 amount includes
$366 million
of pre-tax expense associated with the EP acquisition and EP Energy sale.
|
(j)
|
Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. 2012 amount includes
$108 million
of expense for capitalized financing fees associated with the EP acquisition financing that were written-off (primarily due to debt repayments) or amortized.
|
(k)
|
Represents loss from sale of the FTC Natural Gas Pipelines disposal group and other, net of tax (see Note 3).
|
(l)
|
Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues from external customers
|
|
|
|
|
|
||||||
U.S.
|
$
|
15,605
|
|
|
$
|
13,656
|
|
|
$
|
9,488
|
|
Canada
|
437
|
|
|
398
|
|
|
407
|
|
|||
Mexico
|
184
|
|
|
16
|
|
|
78
|
|
|||
Total consolidated revenues from external customers
|
$
|
16,226
|
|
|
$
|
14,070
|
|
|
$
|
9,973
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
Long-lived assets at December 31(a)
|
|
|
|
|
|
||||||
U.S.
|
$
|
50,141
|
|
|
$
|
42,080
|
|
|
$
|
37,651
|
|
Canada
|
2,268
|
|
|
2,214
|
|
|
2,035
|
|
|||
Mexico
|
81
|
|
|
81
|
|
|
82
|
|
|||
Total consolidated long-lived assets
|
$
|
52,490
|
|
|
$
|
44,375
|
|
|
$
|
39,768
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2014
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
Total Revenues
|
|
$
|
36
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14,310
|
|
|
$
|
1,886
|
|
|
$
|
(6
|
)
|
|
$
|
16,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating costs, expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Costs of sales
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,737
|
|
|
499
|
|
|
42
|
|
|
6,278
|
|
||||||||
Depreciation, depletion and amortization
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,655
|
|
|
364
|
|
|
—
|
|
|
2,040
|
|
||||||||
Other operating expenses
|
|
30
|
|
|
—
|
|
|
32
|
|
|
5
|
|
|
2,927
|
|
|
514
|
|
|
(48
|
)
|
|
3,460
|
|
||||||||
Total operating costs, expenses and other
|
|
51
|
|
|
—
|
|
|
32
|
|
|
5
|
|
|
10,319
|
|
|
1,377
|
|
|
(6
|
)
|
|
11,778
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating (loss) income
|
|
(15
|
)
|
|
—
|
|
|
(32
|
)
|
|
(5
|
)
|
|
3,991
|
|
|
509
|
|
|
—
|
|
|
4,448
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Earnings from consolidated subsidiaries
|
|
1,948
|
|
|
3,235
|
|
|
224
|
|
|
742
|
|
|
2,259
|
|
|
1,120
|
|
|
(9,528
|
)
|
|
—
|
|
||||||||
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
407
|
|
|
(1
|
)
|
|
—
|
|
|
406
|
|
||||||||
Interest, net
|
|
(493
|
)
|
|
41
|
|
|
(46
|
)
|
|
(171
|
)
|
|
(1,040
|
)
|
|
(89
|
)
|
|
—
|
|
|
(1,798
|
)
|
||||||||
Amortization of excess cost of equity investments and other, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
48
|
|
|
—
|
|
|
35
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income from continuing operations before income taxes
|
|
1,440
|
|
|
3,276
|
|
|
146
|
|
|
566
|
|
|
5,604
|
|
|
1,587
|
|
|
(9,528
|
)
|
|
3,091
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income tax expense
|
|
(166
|
)
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(183
|
)
|
|
(292
|
)
|
|
—
|
|
|
(648
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income
|
|
1,274
|
|
|
3,269
|
|
|
146
|
|
|
566
|
|
|
5,421
|
|
|
1,295
|
|
|
(9,528
|
)
|
|
2,443
|
|
||||||||
Net income attributable to noncontrolling interests
|
|
(248
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(211
|
)
|
|
—
|
|
|
(958
|
)
|
|
(1,417
|
)
|
||||||||
Net income attributable to controlling interests
|
|
$
|
1,026
|
|
|
$
|
3,269
|
|
|
$
|
146
|
|
|
$
|
566
|
|
|
$
|
5,210
|
|
|
$
|
1,295
|
|
|
$
|
(10,486
|
)
|
|
$
|
1,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net Income
|
|
$
|
1,274
|
|
|
$
|
3,269
|
|
|
$
|
146
|
|
|
$
|
566
|
|
|
$
|
5,421
|
|
|
$
|
1,295
|
|
|
$
|
(9,528
|
)
|
|
$
|
2,443
|
|
Total other comprehensive (loss) income
|
|
(24
|
)
|
|
287
|
|
|
—
|
|
|
(10
|
)
|
|
386
|
|
|
(168
|
)
|
|
(451
|
)
|
|
20
|
|
||||||||
Comprehensive income
|
|
1,250
|
|
|
3,556
|
|
|
146
|
|
|
556
|
|
|
5,807
|
|
|
1,127
|
|
|
(9,979
|
)
|
|
2,463
|
|
||||||||
Comprehensive income attributable to noncontrolling interests
|
|
(273
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(203
|
)
|
|
—
|
|
|
(1,010
|
)
|
|
(1,486
|
)
|
||||||||
Comprehensive income attributable to controlling interests
|
|
$
|
977
|
|
|
$
|
3,556
|
|
|
$
|
146
|
|
|
$
|
556
|
|
|
$
|
5,604
|
|
|
$
|
1,127
|
|
|
$
|
(10,989
|
)
|
|
$
|
977
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2013
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
Total Revenues
|
|
$
|
36
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12,511
|
|
|
$
|
1,512
|
|
|
$
|
11
|
|
|
$
|
14,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating costs, expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Costs of sales
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,739
|
|
|
468
|
|
|
46
|
|
|
5,253
|
|
||||||||
Depreciation, depletion and amortization
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,466
|
|
|
320
|
|
|
—
|
|
|
1,806
|
|
||||||||
Other operating expenses
|
|
22
|
|
|
—
|
|
|
38
|
|
|
8
|
|
|
2,325
|
|
|
663
|
|
|
(35
|
)
|
|
3,021
|
|
||||||||
Total operating costs, expenses and other
|
|
42
|
|
|
—
|
|
|
38
|
|
|
8
|
|
|
8,530
|
|
|
1,451
|
|
|
11
|
|
|
10,080
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating (loss) income
|
|
(6
|
)
|
|
—
|
|
|
(38
|
)
|
|
(8
|
)
|
|
3,981
|
|
|
61
|
|
|
—
|
|
|
3,990
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Earnings from consolidated subsidiaries
|
|
2,025
|
|
|
3,251
|
|
|
163
|
|
|
759
|
|
|
1,986
|
|
|
1,755
|
|
|
(9,939
|
)
|
|
—
|
|
||||||||
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
323
|
|
|
4
|
|
|
—
|
|
|
327
|
|
||||||||
Interest, net
|
|
(539
|
)
|
|
41
|
|
|
(36
|
)
|
|
(157
|
)
|
|
(949
|
)
|
|
(35
|
)
|
|
—
|
|
|
(1,675
|
)
|
||||||||
Amortization of excess cost of equity investments and other, net
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
549
|
|
|
249
|
|
|
—
|
|
|
796
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income from continuing operations before income taxes
|
|
1,479
|
|
|
3,292
|
|
|
88
|
|
|
594
|
|
|
5,890
|
|
|
2,034
|
|
|
(9,939
|
)
|
|
3,438
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income tax (expense) benefit
|
|
(41
|
)
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
50
|
|
|
(740
|
)
|
|
—
|
|
|
(742
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income from continuing operations
|
|
1,438
|
|
|
3,281
|
|
|
88
|
|
|
594
|
|
|
5,940
|
|
|
1,294
|
|
|
(9,939
|
)
|
|
2,696
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Loss from discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income
|
|
1,438
|
|
|
3,281
|
|
|
88
|
|
|
594
|
|
|
5,936
|
|
|
1,294
|
|
|
(9,939
|
)
|
|
2,692
|
|
||||||||
Net income attributable to noncontrolling interests
|
|
(245
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(236
|
)
|
|
—
|
|
|
(1,018
|
)
|
|
(1,499
|
)
|
||||||||
Net income attributable to controlling interests
|
|
$
|
1,193
|
|
|
$
|
3,281
|
|
|
$
|
88
|
|
|
$
|
594
|
|
|
$
|
5,700
|
|
|
$
|
1,294
|
|
|
$
|
(10,957
|
)
|
|
$
|
1,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net Income
|
|
$
|
1,438
|
|
|
$
|
3,281
|
|
|
$
|
88
|
|
|
$
|
594
|
|
|
$
|
5,936
|
|
|
$
|
1,294
|
|
|
$
|
(9,939
|
)
|
|
$
|
2,692
|
|
Total other comprehensive income (loss)
|
|
81
|
|
|
(135
|
)
|
|
—
|
|
|
—
|
|
|
(145
|
)
|
|
(172
|
)
|
|
411
|
|
|
40
|
|
||||||||
Comprehensive income
|
|
1,519
|
|
|
3,146
|
|
|
88
|
|
|
594
|
|
|
5,791
|
|
|
1,122
|
|
|
(9,528
|
)
|
|
2,732
|
|
||||||||
Comprehensive income attributable to noncontrolling interests
|
|
(232
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(237
|
)
|
|
—
|
|
|
(976
|
)
|
|
(1,445
|
)
|
||||||||
Comprehensive income attributable to controlling interests
|
|
$
|
1,287
|
|
|
$
|
3,146
|
|
|
$
|
88
|
|
|
$
|
594
|
|
|
$
|
5,554
|
|
|
$
|
1,122
|
|
|
$
|
(10,504
|
)
|
|
$
|
1,287
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2012
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
Total Revenues
|
|
$
|
35
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8,651
|
|
|
$
|
1,265
|
|
|
$
|
22
|
|
|
$
|
9,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating costs, expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Costs of sales
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,761
|
|
|
271
|
|
|
25
|
|
|
3,057
|
|
||||||||
Depreciation, depletion and amortization
|
|
19
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,091
|
|
|
309
|
|
|
—
|
|
|
1,419
|
|
||||||||
Other operating expenses
|
|
295
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2,172
|
|
|
438
|
|
|
(3
|
)
|
|
2,904
|
|
||||||||
Total operating costs, expenses and other
|
|
314
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
6,024
|
|
|
1,018
|
|
|
22
|
|
|
7,380
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating (loss) income
|
|
(279
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
2,627
|
|
|
247
|
|
|
—
|
|
|
2,593
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Earnings from consolidated subsidiaries
|
|
842
|
|
|
1,351
|
|
|
—
|
|
|
436
|
|
|
815
|
|
|
1,466
|
|
|
(4,910
|
)
|
|
—
|
|
||||||||
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
206
|
|
|
(53
|
)
|
|
—
|
|
|
153
|
|
||||||||
Interest, net
|
|
(630
|
)
|
|
41
|
|
|
—
|
|
|
(69
|
)
|
|
(757
|
)
|
|
16
|
|
|
—
|
|
|
(1,399
|
)
|
||||||||
Amortization of excess cost of equity investments and other, net
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
18
|
|
|
—
|
|
|
(4
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
(Loss) income from continuing operations before income taxes
|
|
(68
|
)
|
|
1,392
|
|
|
—
|
|
|
365
|
|
|
2,870
|
|
|
1,694
|
|
|
(4,910
|
)
|
|
1,343
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income tax benefit (expense)
|
|
392
|
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
98
|
|
|
(620
|
)
|
|
—
|
|
|
(139
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income from continuing operations
|
|
324
|
|
|
1,383
|
|
|
—
|
|
|
365
|
|
|
2,968
|
|
|
1,074
|
|
|
(4,910
|
)
|
|
1,204
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Loss from discontinued operations
|
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(761
|
)
|
|
—
|
|
|
(777
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income
|
|
310
|
|
|
1,383
|
|
|
—
|
|
|
365
|
|
|
2,966
|
|
|
313
|
|
|
(4,910
|
)
|
|
427
|
|
||||||||
Net loss (income) attributable to noncontrolling interests
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(168
|
)
|
|
—
|
|
|
51
|
|
|
(112
|
)
|
||||||||
Net income attributable to controlling interests
|
|
$
|
315
|
|
|
$
|
1,383
|
|
|
$
|
—
|
|
|
$
|
365
|
|
|
$
|
2,798
|
|
|
$
|
313
|
|
|
$
|
(4,859
|
)
|
|
$
|
315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net Income
|
|
$
|
310
|
|
|
$
|
1,383
|
|
|
$
|
—
|
|
|
$
|
365
|
|
|
$
|
2,966
|
|
|
$
|
313
|
|
|
$
|
(4,910
|
)
|
|
$
|
427
|
|
Total other comprehensive income
|
|
12
|
|
|
165
|
|
|
—
|
|
|
10
|
|
|
200
|
|
|
96
|
|
|
(412
|
)
|
|
71
|
|
||||||||
Comprehensive income
|
|
322
|
|
|
1,548
|
|
|
—
|
|
|
375
|
|
|
3,166
|
|
|
409
|
|
|
(5,322
|
)
|
|
498
|
|
||||||||
Comprehensive income attributable to noncontrolling interests
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(174
|
)
|
|
—
|
|
|
(2
|
)
|
|
(186
|
)
|
||||||||
Comprehensive income attributable to controlling interests
|
|
$
|
312
|
|
|
$
|
1,548
|
|
|
$
|
—
|
|
|
$
|
375
|
|
|
$
|
2,992
|
|
|
$
|
409
|
|
|
$
|
(5,324
|
)
|
|
$
|
312
|
|
Condensed Consolidating Balance Sheets as of December 31, 2014
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating
Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash and cash equivalents
|
|
$
|
4
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
279
|
|
|
$
|
—
|
|
|
$
|
315
|
|
Other current assets - affiliates
|
|
1,870
|
|
|
1,332
|
|
|
11
|
|
|
1
|
|
|
11,575
|
|
|
403
|
|
|
(15,192
|
)
|
|
—
|
|
||||||||
All other current assets
|
|
397
|
|
|
151
|
|
|
3
|
|
|
1
|
|
|
2,547
|
|
|
358
|
|
|
(20
|
)
|
|
3,437
|
|
||||||||
Property, plant and equipment, net
|
|
263
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
29,490
|
|
|
8,806
|
|
|
—
|
|
|
38,564
|
|
||||||||
Investments
|
|
16
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
5,910
|
|
|
109
|
|
|
—
|
|
|
6,036
|
|
||||||||
Investments in subsidiaries
|
|
31,364
|
|
|
27,264
|
|
|
1,911
|
|
|
6,150
|
|
|
16,387
|
|
|
3,337
|
|
|
(86,413
|
)
|
|
—
|
|
||||||||
Goodwill
|
|
15,087
|
|
|
—
|
|
|
920
|
|
|
22
|
|
|
5,419
|
|
|
3,206
|
|
|
—
|
|
|
24,654
|
|
||||||||
Notes receivable from affiliates
|
|
4,459
|
|
|
19,824
|
|
|
—
|
|
|
8
|
|
|
3,621
|
|
|
496
|
|
|
(28,408
|
)
|
|
—
|
|
||||||||
Deferred tax assets
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,251
|
|
|
—
|
|
|
(3,600
|
)
|
|
5,651
|
|
||||||||
Other non-current assets
|
|
287
|
|
|
341
|
|
|
—
|
|
|
19
|
|
|
3,782
|
|
|
112
|
|
|
—
|
|
|
4,541
|
|
||||||||
Total assets
|
|
$
|
53,747
|
|
|
$
|
48,927
|
|
|
$
|
2,850
|
|
|
$
|
6,202
|
|
|
$
|
87,999
|
|
|
$
|
17,106
|
|
|
$
|
(133,633
|
)
|
|
$
|
83,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Current portion of debt
|
|
$
|
1,486
|
|
|
$
|
324
|
|
|
$
|
—
|
|
|
$
|
375
|
|
|
$
|
381
|
|
|
$
|
151
|
|
|
$
|
—
|
|
|
$
|
2,717
|
|
Other current liabilities - affiliates
|
|
709
|
|
|
11,926
|
|
|
115
|
|
|
23
|
|
|
1,553
|
|
|
866
|
|
|
(15,192
|
)
|
|
—
|
|
||||||||
All other current liabilities
|
|
318
|
|
|
463
|
|
|
12
|
|
|
34
|
|
|
1,814
|
|
|
1,024
|
|
|
(20
|
)
|
|
3,645
|
|
||||||||
Long-term debt
|
|
11,862
|
|
|
18,197
|
|
|
386
|
|
|
2,478
|
|
|
6,609
|
|
|
714
|
|
|
—
|
|
|
40,246
|
|
||||||||
Notes payable to affiliates
|
|
2,619
|
|
|
153
|
|
|
753
|
|
|
1,206
|
|
|
22,437
|
|
|
1,240
|
|
|
(28,408
|
)
|
|
—
|
|
||||||||
Deferred income taxes
|
|
2,094
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
1,504
|
|
|
(3,600
|
)
|
|
—
|
|
||||||||
All other long-term liabilities and deferred credits
|
|
583
|
|
|
78
|
|
|
2
|
|
|
—
|
|
|
987
|
|
|
514
|
|
|
—
|
|
|
2,164
|
|
||||||||
Total liabilities
|
|
19,671
|
|
|
31,141
|
|
|
1,270
|
|
|
4,116
|
|
|
33,781
|
|
|
6,013
|
|
|
(47,220
|
)
|
|
48,772
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Total KMI equity
|
|
34,076
|
|
|
17,786
|
|
|
1,580
|
|
|
2,086
|
|
|
54,218
|
|
|
11,093
|
|
|
(86,763
|
)
|
|
34,076
|
|
||||||||
Noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
350
|
|
|
350
|
|
||||||||
Total stockholders’ equity
|
|
34,076
|
|
|
17,786
|
|
|
1,580
|
|
|
2,086
|
|
|
54,218
|
|
|
11,093
|
|
|
(86,413
|
)
|
|
34,426
|
|
||||||||
Total liabilities and stockholders’ equity
|
|
$
|
53,747
|
|
|
$
|
48,927
|
|
|
$
|
2,850
|
|
|
$
|
6,202
|
|
|
$
|
87,999
|
|
|
$
|
17,106
|
|
|
$
|
(133,633
|
)
|
|
$
|
83,198
|
|
Condensed Consolidating Balance Sheets as of December 31, 2013
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating
Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash and cash equivalents
|
|
$
|
83
|
|
|
$
|
10
|
|
|
$
|
1
|
|
|
$
|
78
|
|
|
$
|
17
|
|
|
$
|
409
|
|
|
$
|
—
|
|
|
$
|
598
|
|
Other current assets - affiliates
|
|
287
|
|
|
751
|
|
|
—
|
|
|
18
|
|
|
10,992
|
|
|
220
|
|
|
(12,268
|
)
|
|
—
|
|
||||||||
All other current assets
|
|
657
|
|
|
136
|
|
|
2
|
|
|
—
|
|
|
2,184
|
|
|
302
|
|
|
(11
|
)
|
|
3,270
|
|
||||||||
Property, plant and equipment, net
|
|
284
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
26,698
|
|
|
8,695
|
|
|
—
|
|
|
35,847
|
|
||||||||
Investments
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,822
|
|
|
112
|
|
|
—
|
|
|
5,951
|
|
||||||||
Investments in subsidiaries
|
|
13,618
|
|
|
26,555
|
|
|
4,430
|
|
|
4,445
|
|
|
3,584
|
|
|
3,839
|
|
|
(56,471
|
)
|
|
—
|
|
||||||||
Goodwill
|
|
15,099
|
|
|
—
|
|
|
813
|
|
|
22
|
|
|
5,317
|
|
|
3,253
|
|
|
—
|
|
|
24,504
|
|
||||||||
Notes receivable from affiliates
|
|
—
|
|
|
17,284
|
|
|
—
|
|
|
—
|
|
|
3,087
|
|
|
511
|
|
|
(20,882
|
)
|
|
—
|
|
||||||||
Other non-current assets
|
|
455
|
|
|
233
|
|
|
—
|
|
|
20
|
|
|
3,866
|
|
|
441
|
|
|
—
|
|
|
5,015
|
|
||||||||
Total assets
|
|
$
|
30,500
|
|
|
$
|
44,969
|
|
|
$
|
5,416
|
|
|
$
|
4,583
|
|
|
$
|
61,567
|
|
|
$
|
17,782
|
|
|
$
|
(89,632
|
)
|
|
$
|
75,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Current portion of debt
|
|
$
|
575
|
|
|
$
|
1,504
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
77
|
|
|
$
|
150
|
|
|
$
|
—
|
|
|
$
|
2,306
|
|
Other current liabilities - affiliates
|
|
379
|
|
|
10,453
|
|
|
55
|
|
|
19
|
|
|
823
|
|
|
539
|
|
|
(12,268
|
)
|
|
—
|
|
||||||||
All other current liabilities
|
|
72
|
|
|
394
|
|
|
41
|
|
|
30
|
|
|
1,728
|
|
|
1,515
|
|
|
(11
|
)
|
|
3,769
|
|
||||||||
Long-term debt
|
|
7,775
|
|
|
15,644
|
|
|
393
|
|
|
2,253
|
|
|
7,101
|
|
|
721
|
|
|
—
|
|
|
33,887
|
|
||||||||
Notes payable to affiliates
|
|
1,993
|
|
|
—
|
|
|
907
|
|
|
1,143
|
|
|
15,599
|
|
|
1,240
|
|
|
(20,882
|
)
|
|
—
|
|
||||||||
Deferred income taxes
|
|
2,022
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
1,142
|
|
|
1,485
|
|
|
—
|
|
|
4,651
|
|
||||||||
Other long-term liabilities and deferred credits
|
|
384
|
|
|
173
|
|
|
—
|
|
|
—
|
|
|
1,023
|
|
|
707
|
|
|
—
|
|
|
2,287
|
|
||||||||
Total liabilities
|
|
13,200
|
|
|
28,168
|
|
|
1,398
|
|
|
3,445
|
|
|
27,493
|
|
|
6,357
|
|
|
(33,161
|
)
|
|
46,900
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Total KMI equity
|
|
13,093
|
|
|
16,801
|
|
|
4,018
|
|
|
1,138
|
|
|
31,025
|
|
|
11,478
|
|
|
(64,460
|
)
|
|
13,093
|
|
||||||||
Noncontrolling interests
|
|
4,207
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,049
|
|
|
(53
|
)
|
|
7,989
|
|
|
15,192
|
|
||||||||
Total stockholders’ equity
|
|
17,300
|
|
|
16,801
|
|
|
4,018
|
|
|
1,138
|
|
|
34,074
|
|
|
11,425
|
|
|
(56,471
|
)
|
|
28,285
|
|
||||||||
Total liabilities and stockholders’ equity
|
|
$
|
30,500
|
|
|
$
|
44,969
|
|
|
$
|
5,416
|
|
|
$
|
4,583
|
|
|
$
|
61,567
|
|
|
$
|
17,782
|
|
|
$
|
(89,632
|
)
|
|
$
|
75,185
|
|
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2014
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
Net cash provided by (used in) operating activities
|
|
$
|
1,426
|
|
|
$
|
3,998
|
|
|
$
|
(77
|
)
|
|
$
|
885
|
|
|
$
|
6,345
|
|
|
$
|
1,174
|
|
|
$
|
(9,284
|
)
|
|
$
|
4,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Funding to affiliates
|
|
(1,756
|
)
|
|
(6,559
|
)
|
|
—
|
|
|
(1,252
|
)
|
|
(4,706
|
)
|
|
(1,088
|
)
|
|
15,361
|
|
|
—
|
|
||||||||
Capital expenditures
|
|
(1
|
)
|
|
—
|
|
|
(63
|
)
|
|
—
|
|
|
(3,050
|
)
|
|
(705
|
)
|
|
202
|
|
|
(3,617
|
)
|
||||||||
Sale, casualty and transfer of property, plant and equipment, investments and other net assets, net of removal costs
|
|
—
|
|
|
—
|
|
|
202
|
|
|
—
|
|
|
(9
|
)
|
|
14
|
|
|
(202
|
)
|
|
5
|
|
||||||||
Contributions to investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(189
|
)
|
|
(594
|
)
|
|
—
|
|
|
394
|
|
|
(389
|
)
|
||||||||
Investments in KMP and EPB
|
|
(550
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
550
|
|
|
—
|
|
||||||||
Acquisitions of assets and investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,370
|
)
|
|
(18
|
)
|
|
—
|
|
|
(1,388
|
)
|
||||||||
Drop down assets to EPB
|
|
875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(875
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Distributions from equity investments in excess of cumulative earnings
|
|
93
|
|
|
—
|
|
|
—
|
|
|
440
|
|
|
183
|
|
|
—
|
|
|
(534
|
)
|
|
182
|
|
||||||||
Other, net
|
|
—
|
|
|
29
|
|
|
—
|
|
|
—
|
|
|
27
|
|
|
(60
|
)
|
|
1
|
|
|
(3
|
)
|
||||||||
Net cash (used in) provided by investing activities
|
|
(1,339
|
)
|
|
(6,530
|
)
|
|
139
|
|
|
(1,001
|
)
|
|
(10,394
|
)
|
|
(1,857
|
)
|
|
15,772
|
|
|
(5,210
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Issuance of debt
|
|
10,594
|
|
|
13,057
|
|
|
—
|
|
|
922
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,573
|
|
||||||||
Payment of debt
|
|
(5,479
|
)
|
|
(11,849
|
)
|
|
—
|
|
|
(322
|
)
|
|
(142
|
)
|
|
(9
|
)
|
|
—
|
|
|
(17,801
|
)
|
||||||||
Funding from (to) affiliates
|
|
756
|
|
|
3,823
|
|
|
(63
|
)
|
|
786
|
|
|
9,138
|
|
|
921
|
|
|
(15,361
|
)
|
|
—
|
|
||||||||
Debt issuance costs
|
|
(74
|
)
|
|
(11
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(89
|
)
|
||||||||
Cash dividends
|
|
(1,760
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,760
|
)
|
||||||||
Repurchases of shares and warrants
|
|
(192
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(192
|
)
|
||||||||
Cash consideration of Merger Transactions
|
|
(3,937
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,937
|
)
|
||||||||
Merger Transactions costs
|
|
(74
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(74
|
)
|
||||||||
Contributions from parents
|
|
—
|
|
|
1,178
|
|
|
—
|
|
|
205
|
|
|
1,267
|
|
|
64
|
|
|
(2,714
|
)
|
|
—
|
|
||||||||
Contributions from noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,767
|
|
|
1,767
|
|
||||||||
Distributions to parents
|
|
—
|
|
|
(3,660
|
)
|
|
—
|
|
|
(1,549
|
)
|
|
(6,213
|
)
|
|
(411
|
)
|
|
11,833
|
|
|
—
|
|
||||||||
Distributions to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,013
|
)
|
|
(2,013
|
)
|
||||||||
Other, net
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
||||||||
Net cash (used in) provided by financing activities
|
|
(166
|
)
|
|
2,537
|
|
|
(63
|
)
|
|
38
|
|
|
4,048
|
|
|
565
|
|
|
(6,488
|
)
|
|
471
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Effect of exchange rate changes on cash and cash equivalents
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(12
|
)
|
|
—
|
|
|
(11
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net (decrease) increase in cash and cash equivalents
|
|
(79
|
)
|
|
5
|
|
|
(1
|
)
|
|
(78
|
)
|
|
—
|
|
|
(130
|
)
|
|
—
|
|
|
(283
|
)
|
||||||||
Cash and cash equivalents, beginning of period
|
|
83
|
|
|
10
|
|
|
1
|
|
|
78
|
|
|
17
|
|
|
409
|
|
|
—
|
|
|
598
|
|
||||||||
Cash and cash equivalents, end of period
|
|
$
|
4
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
279
|
|
|
$
|
—
|
|
|
$
|
315
|
|
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2013
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
Net cash provided by (used in) operating activities
|
|
$
|
1,775
|
|
|
$
|
4,173
|
|
|
$
|
(408
|
)
|
|
$
|
64
|
|
|
$
|
5,491
|
|
|
$
|
769
|
|
|
$
|
(7,742
|
)
|
|
$
|
4,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Funding to affiliates
|
|
(402
|
)
|
|
(7,145
|
)
|
|
(1
|
)
|
|
(661
|
)
|
|
(4,270
|
)
|
|
(1,332
|
)
|
|
13,811
|
|
|
—
|
|
||||||||
Capital expenditures
|
|
(6
|
)
|
|
—
|
|
|
(141
|
)
|
|
—
|
|
|
(2,418
|
)
|
|
(804
|
)
|
|
—
|
|
|
(3,369
|
)
|
||||||||
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
87
|
|
|
—
|
|
|
—
|
|
|
87
|
|
||||||||
Proceeds from sale of assets and investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
118
|
|
|
372
|
|
|
—
|
|
|
490
|
|
||||||||
Contributions to investments
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(52
|
)
|
|
(218
|
)
|
|
—
|
|
|
59
|
|
|
(217
|
)
|
||||||||
Investments in KMP and EPB
|
|
(68
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68
|
|
|
—
|
|
||||||||
Acquisitions of assets and investments
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
(297
|
)
|
|
—
|
|
|
—
|
|
|
(292
|
)
|
||||||||
Drop down assets to KMP
|
|
994
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(994
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Distributions from equity investments in excess of cumulative earnings
|
|
41
|
|
|
—
|
|
|
—
|
|
|
296
|
|
|
183
|
|
|
—
|
|
|
(335
|
)
|
|
185
|
|
||||||||
Other, net
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
18
|
|
|
(12
|
)
|
|
—
|
|
|
(6
|
)
|
||||||||
Net cash provided by (used in) investing activities
|
|
553
|
|
|
(7,157
|
)
|
|
(137
|
)
|
|
(417
|
)
|
|
(7,791
|
)
|
|
(1,776
|
)
|
|
13,603
|
|
|
(3,122
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Issuance of debt
|
|
3,028
|
|
|
10,213
|
|
|
—
|
|
|
87
|
|
|
14
|
|
|
239
|
|
|
—
|
|
|
13,581
|
|
||||||||
Payment of debt
|
|
(3,624
|
)
|
|
(7,627
|
)
|
|
(854
|
)
|
|
(175
|
)
|
|
(106
|
)
|
|
(7
|
)
|
|
—
|
|
|
(12,393
|
)
|
||||||||
Funding from affiliates
|
|
576
|
|
|
1,971
|
|
|
1,400
|
|
|
1,332
|
|
|
7,740
|
|
|
792
|
|
|
(13,811
|
)
|
|
—
|
|
||||||||
Debt issuance costs
|
|
(15
|
)
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(38
|
)
|
||||||||
Cash dividends
|
|
(1,622
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,622
|
)
|
||||||||
Repurchases of shares and warrants
|
|
(637
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(637
|
)
|
||||||||
Contributions from parents
|
|
—
|
|
|
1,533
|
|
|
—
|
|
|
1
|
|
|
162
|
|
|
132
|
|
|
(1,828
|
)
|
|
—
|
|
||||||||
Contributions from noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,706
|
|
|
1,706
|
|
||||||||
Distributions to parents
|
|
—
|
|
|
(3,168
|
)
|
|
—
|
|
|
(924
|
)
|
|
(5,522
|
)
|
|
(150
|
)
|
|
9,764
|
|
|
—
|
|
||||||||
Distributions to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,692
|
)
|
|
(1,692
|
)
|
||||||||
Other, net
|
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Net cash (used in) provided by financing activities
|
|
(2,293
|
)
|
|
2,899
|
|
|
546
|
|
|
321
|
|
|
2,288
|
|
|
1,005
|
|
|
(5,861
|
)
|
|
(1,095
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Effect of exchange rate changes on cash and cash equivalents
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(22
|
)
|
|
—
|
|
|
(21
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net increase (decrease) in cash and cash equivalents
|
|
35
|
|
|
(85
|
)
|
|
1
|
|
|
(32
|
)
|
|
(11
|
)
|
|
(24
|
)
|
|
—
|
|
|
(116
|
)
|
||||||||
Cash and cash equivalents, beginning of period
|
|
48
|
|
|
95
|
|
|
—
|
|
|
110
|
|
|
28
|
|
|
433
|
|
|
—
|
|
|
714
|
|
||||||||
Cash and cash equivalents, end of period
|
|
$
|
83
|
|
|
$
|
10
|
|
|
$
|
1
|
|
|
$
|
78
|
|
|
$
|
17
|
|
|
$
|
409
|
|
|
$
|
—
|
|
|
$
|
598
|
|
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2012
(In Millions)
|
||||||||||||||||||||||||||||||||
|
|
Parent
Issuer and Guarantor |
|
Subsidiary
Issuer and Guarantor - KMP |
|
Subsidiary
Issuer and Guarantor - Copano |
|
Subsidiary
Issuer and Guarantor - EPB |
|
Subsidiary
Guarantors |
|
Subsidiary
Non-Guarantors |
|
Consolidating Adjustments
|
|
Consolidated KMI
|
||||||||||||||||
Net cash provided by (used in) operating activities
|
|
$
|
657
|
|
|
$
|
3,867
|
|
|
$
|
—
|
|
|
$
|
(151
|
)
|
|
$
|
3,095
|
|
|
$
|
941
|
|
|
$
|
(5,601
|
)
|
|
$
|
2,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Funding (to) from affiliates
|
|
(857
|
)
|
|
(5,521
|
)
|
|
—
|
|
|
42
|
|
|
(3,515
|
)
|
|
(1,448
|
)
|
|
11,299
|
|
|
—
|
|
||||||||
Capital expenditures
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,423
|
)
|
|
(594
|
)
|
|
—
|
|
|
(2,022
|
)
|
||||||||
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64
|
|
|
90
|
|
|
—
|
|
|
154
|
|
||||||||
Acquisition of EP
|
|
(5,212
|
)
|
|
|
|
|
|
81
|
|
|
70
|
|
|
91
|
|
|
—
|
|
|
(4,970
|
)
|
||||||||||
Contributions to investments
|
|
(15
|
)
|
|
—
|
|
|
—
|
|
|
(454
|
)
|
|
(206
|
)
|
|
—
|
|
|
483
|
|
|
(192
|
)
|
||||||||
Investments in KMP and EPB
|
|
(94
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
94
|
|
|
—
|
|
||||||||
Acquisitions of assets and investments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(83
|
)
|
|
—
|
|
|
—
|
|
|
(83
|
)
|
||||||||
Drop down assets to KMP
|
|
3,485
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,485
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Distributions from equity investments in excess of cumulative earnings
|
|
16
|
|
|
—
|
|
|
—
|
|
|
106
|
|
|
184
|
|
|
—
|
|
|
(106
|
)
|
|
200
|
|
||||||||
Proceeds from disposal of discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,791
|
|
|
—
|
|
|
—
|
|
|
1,791
|
|
||||||||
Other, net
|
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
—
|
|
|
121
|
|
|
(81
|
)
|
|
—
|
|
|
25
|
|
||||||||
Net cash used in investing activities
|
|
(2,682
|
)
|
|
(5,536
|
)
|
|
—
|
|
|
(225
|
)
|
|
(6,482
|
)
|
|
(1,942
|
)
|
|
11,770
|
|
|
(5,097
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Issuance of debt
|
|
8,001
|
|
|
9,270
|
|
|
—
|
|
|
658
|
|
|
—
|
|
|
219
|
|
|
—
|
|
|
18,148
|
|
||||||||
Payment of debt
|
|
(5,692
|
)
|
|
(8,003
|
)
|
|
—
|
|
|
(855
|
)
|
|
(205
|
)
|
|
—
|
|
|
—
|
|
|
(14,755
|
)
|
||||||||
Funding from affiliates
|
|
1,268
|
|
|
1,360
|
|
|
—
|
|
|
1,049
|
|
|
6,612
|
|
|
1,010
|
|
|
(11,299
|
)
|
|
—
|
|
||||||||
Debt issuance costs
|
|
(91
|
)
|
|
(16
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(111
|
)
|
||||||||
Cash dividends
|
|
(1,184
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,184
|
)
|
||||||||
Repurchases of shares and warrants
|
|
(157
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(157
|
)
|
||||||||
Contributions from parents
|
|
—
|
|
|
1,681
|
|
|
—
|
|
|
29
|
|
|
763
|
|
|
30
|
|
|
(2,503
|
)
|
|
—
|
|
||||||||
Contributions from noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,939
|
|
|
1,939
|
|
||||||||
Distributions to parents
|
|
—
|
|
|
(2,528
|
)
|
|
—
|
|
|
(391
|
)
|
|
(3,763
|
)
|
|
(231
|
)
|
|
6,913
|
|
|
—
|
|
||||||||
Distributions to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,219
|
)
|
|
(1,219
|
)
|
||||||||
Other, net
|
|
(74
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(77
|
)
|
||||||||
Net cash provided by financing activities
|
|
2,071
|
|
|
1,763
|
|
|
—
|
|
|
486
|
|
|
3,405
|
|
|
1,028
|
|
|
(6,169
|
)
|
|
2,584
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Effect of exchange rate changes on cash and cash equivalents
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net increase in cash and cash equivalents
|
|
46
|
|
|
94
|
|
|
—
|
|
|
110
|
|
|
18
|
|
|
35
|
|
|
—
|
|
|
303
|
|
||||||||
Cash and cash equivalents, beginning of period
|
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
398
|
|
|
—
|
|
|
411
|
|
||||||||
Cash and cash equivalents, end of period
|
|
$
|
48
|
|
|
$
|
95
|
|
|
$
|
—
|
|
|
$
|
110
|
|
|
$
|
28
|
|
|
$
|
433
|
|
|
$
|
—
|
|
|
$
|
714
|
|
Supplemental Selected Quarterly Financial Data (Unaudited)
|
|||||||||||||||
|
Quarters Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(In millions, except per share amounts)
|
||||||||||||||
2014
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
4,047
|
|
|
$
|
3,937
|
|
|
$
|
4,291
|
|
|
$
|
3,951
|
|
Operating Income
|
1,147
|
|
|
1,013
|
|
|
1,332
|
|
|
956
|
|
||||
Net Income
|
601
|
|
|
497
|
|
|
779
|
|
|
566
|
|
||||
Net Income Attributable to Kinder Morgan, Inc.
|
287
|
|
|
284
|
|
|
329
|
|
|
126
|
|
||||
Basic and Diluted Earnings Per Common Share
|
0.28
|
|
|
0.27
|
|
|
0.32
|
|
|
0.08
|
|
||||
|
|
|
|
|
|
|
|
||||||||
2013
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
3,060
|
|
|
$
|
3,382
|
|
|
$
|
3,756
|
|
|
$
|
3,872
|
|
Operating Income
|
1,017
|
|
|
772
|
|
|
1,041
|
|
|
1,160
|
|
||||
Net Income
|
656
|
|
|
781
|
|
|
551
|
|
|
704
|
|
||||
Net Income Attributable to Kinder Morgan, Inc.
|
292
|
|
|
277
|
|
|
286
|
|
|
338
|
|
||||
Basic and Diluted Earnings Per Common Share
|
0.28
|
|
|
0.27
|
|
|
0.27
|
|
|
0.33
|
|
Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs
|
|||||||||||
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Consolidated Companies(a)
|
|
|
|
|
|
||||||
Production costs per barrel of oil equivalent(b)(c)(d)
|
$
|
20.55
|
|
|
$
|
18.81
|
|
|
$
|
16.44
|
|
Crude oil production (MBbl/d)
|
40.8
|
|
|
37.6
|
|
|
35.0
|
|
|||
SACROC crude oil production (MBbl/d)
|
27.6
|
|
|
25.5
|
|
|
24.1
|
|
|||
Yates crude oil production (MBbl/d)
|
8.8
|
|
|
9.0
|
|
|
9.3
|
|
|||
|
|
|
|
|
|
||||||
NGL production (MBbl/d)(d)
|
4.2
|
|
|
4.1
|
|
|
3.9
|
|
|||
NGL production from gas plants(MBbl/d)(e)
|
5.9
|
|
|
5.8
|
|
|
5.6
|
|
|||
Total NGL production(MBbl/d)
|
10.1
|
|
|
9.9
|
|
|
9.5
|
|
|||
SACROC NGL production (MBbl/d)(d)
|
3.9
|
|
|
3.8
|
|
|
3.7
|
|
|||
Yates NGL production (MBbl/d)(d)
|
0.2
|
|
|
0.2
|
|
|
0.2
|
|
|||
|
|
|
|
|
|
||||||
Natural gas production (MMcf/d)(d)(f)
|
1.0
|
|
|
1.1
|
|
|
1.2
|
|
|||
Natural gas production from gas plants(MMcf/d)(e)(f)
|
1.2
|
|
|
1.7
|
|
|
0.7
|
|
|||
Total natural gas production(MMcf/d)(f)
|
2.2
|
|
|
2.8
|
|
|
1.9
|
|
|||
Yates natural gas production (MMcf/d)(d)(f)
|
1.0
|
|
|
1.1
|
|
|
1.1
|
|
|||
|
|
|
|
|
|
||||||
Average sales prices including hedge gains/losses:
|
|
|
|
|
|
||||||
Crude oil price per Bbl(g)
|
$
|
88.41
|
|
|
$
|
92.70
|
|
|
$
|
87.72
|
|
NGL price per Bbl(d)(g)
|
$
|
42.61
|
|
|
$
|
46.11
|
|
|
$
|
51.79
|
|
Natural gas price per Mcf(d)(h)
|
$
|
4.04
|
|
|
$
|
3.23
|
|
|
$
|
2.58
|
|
Total NGL price per Bbl(e)
|
$
|
41.87
|
|
|
$
|
46.43
|
|
|
$
|
50.95
|
|
Total natural gas price per Mcf(e)
|
$
|
3.91
|
|
|
$
|
3.21
|
|
|
$
|
2.72
|
|
|
|
|
|
|
|
||||||
Average sales prices excluding hedge gains/losses:
|
|
|
|
|
|
||||||
Crude oil price per Bbl(g)
|
$
|
86.48
|
|
|
$
|
94.94
|
|
|
$
|
89.91
|
|
NGL price per Bbl(g)
|
$
|
42.61
|
|
|
$
|
46.11
|
|
|
$
|
51.79
|
|
Natural gas price per Mcf(h)
|
$
|
4.04
|
|
|
$
|
3.23
|
|
|
$
|
2.58
|
|
(a)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries.
|
(b)
|
Computed using production costs, excluding transportation costs, as defined by the SEC. Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six Mcf of natural gas to one barrel of oil.
|
(c)
|
Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, and general and administrative expenses directly related to oil and gas producing activities.
|
(d)
|
Includes only production attributable to leasehold ownership.
|
(e)
|
Includes production attributable to our ownership in processing plants and third party processing agreements.
|
(f)
|
Excludes natural gas production used as fuel.
|
(g)
|
Hedge gains/losses for crude oil and NGL are included with crude oil.
|
(h)
|
Natural gas sales were not hedged.
|
(a)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries. Includes capitalized asset retirement costs and associated accumulated depreciation.
|
(b)
|
As of
December 31, 2014
, capitalized costs related to the unproved property for the Residual Oil Zone (ROZ) unproved exploration property was $100 million and other miscellaneous unproved property was $3 million.
|
(c)
|
2014 amount includes an impairment charge of $234 million on the Katz Strawn unit and $1 million on other miscellaneous property.
|
(a)
|
Acquisition of Goldsmith Landreth San Andres Unit effective June 1, 2013.
|
(b)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries.
|
(c)
|
Amounts relate to exploration wells drilled in the Residual Oil Zone (ROZ) for $87 million and the Yates Wolfcamp for $8 million.
|
Results of Operations for Oil and Gas Producing Activities
|
|||||||||||
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Consolidated Companies(a)
|
|
|
|
|
|
||||||
Revenues(b)
|
$
|
1,412
|
|
|
$
|
1,376
|
|
|
$
|
1,235
|
|
Expenses:
|
|
|
|
|
|
||||||
Production costs
|
403
|
|
|
344
|
|
|
288
|
|
|||
Other operating expenses(c)
|
99
|
|
|
95
|
|
|
77
|
|
|||
Exploration expense(d)
|
8
|
|
|
—
|
|
|
—
|
|
|||
Impairment(e)
|
235
|
|
|
—
|
|
|
—
|
|
|||
DD&A expenses
|
430
|
|
|
415
|
|
|
387
|
|
|||
Total expenses
|
1,175
|
|
|
854
|
|
|
752
|
|
|||
Results of operations for oil and gas producing activities
|
$
|
237
|
|
|
$
|
522
|
|
|
$
|
483
|
|
(a)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries.
|
(b)
|
Revenues include a gain attributable to our hedging contracts of
$28 million
, for the year ended
December 31, 2014
and losses of
$31 million
and
$28 million
for each of the years,
2013
and
2012
, respectively.
|
(c)
|
Consists primarily of CO
2
expense.
|
(d)
|
Exploration charge for Yates Wolfcamp.
|
(e)
|
Impairment charge of
$234 million
on the Katz Strawn unit and
$1 million
on other miscellaneous property.
|
•
|
no employee’s compensation is tied to the amount of recorded reserves;
|
•
|
we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;
|
•
|
we review our reported proved reserves at each year-end, and at each year-end, the CO
2
business segment managers and the Vice President (President, CO
2
) review all significant reserves changes and all new proved developed and undeveloped reserves additions; and
|
•
|
the CO
2
business segment reports independently of our five remaining reportable business segments.
|
Reserve Quantity Information
|
||||||||
|
Consolidated Companies(a)
|
|||||||
|
Crude Oil
(MBbl)
|
|
NGL
(MBbl) |
|
Natural Gas
(MMcf)(b)
|
|||
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|||
As of December 31, 2011
|
79,447
|
|
|
4,145
|
|
|
3,241
|
|
Revisions of previous estimates(c)
|
15,540
|
|
|
3,285
|
|
|
4,881
|
|
Extensions and discoveries
|
26
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
(239
|
)
|
|
(38
|
)
|
|
(143
|
)
|
Production
|
(12,824
|
)
|
|
(1,416
|
)
|
|
(440
|
)
|
As of December 31, 2012
|
81,950
|
|
|
5,976
|
|
|
7,539
|
|
Revisions of previous estimates(d)
|
(2,573
|
)
|
|
(43
|
)
|
|
(5,063
|
)
|
Purchases of reserves in place(e)
|
41,389
|
|
|
10,347
|
|
|
—
|
|
Production
|
(13,735
|
)
|
|
(1,499
|
)
|
|
(406
|
)
|
As of December 31, 2013
|
107,031
|
|
|
14,781
|
|
|
2,070
|
|
Revisions of previous estimates(f)
|
5,378
|
|
|
(2,419
|
)
|
|
372
|
|
Production
|
(14,852
|
)
|
|
(1,542
|
)
|
|
(373
|
)
|
As of December 31, 2014
|
97,557
|
|
|
10,820
|
|
|
2,069
|
|
|
|
|
|
|
|
|||
Proved developed reserves:
|
|
|
|
|
|
|||
As of December 31, 2012
|
53,006
|
|
|
2,433
|
|
|
7,539
|
|
As of December 31, 2013
|
67,436
|
|
|
6,733
|
|
|
2,070
|
|
As of December 31, 2014
|
60,252
|
|
|
4,584
|
|
|
2,069
|
|
|
|
|
|
|
|
|||
Proved undeveloped reserves:
|
|
|
|
|
|
|||
As of December 31, 2012
|
28,944
|
|
|
3,543
|
|
|
—
|
|
As of December 31, 2013
|
39,595
|
|
|
8,048
|
|
|
—
|
|
As of December 31, 2014
|
37,305
|
|
|
6,236
|
|
|
—
|
|
(a)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries.
|
(b)
|
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
|
(c)
|
Predominantly due to higher CO
2
flood recoveries based on updated performance at the SACROC Unit.
|
(d)
|
Predominantly due to higher operating costs at the Katz Strawn Unit.
|
(e)
|
Represents volumes added with acquisition of the Goldsmith Landreth San Andres Unit in June 2013.
|
(f)
|
Predominately due to the addition of projects and redefined original oil in place values at SACROC, the addition of proved developed nonproducing reserves volumes in the Katz Strawn Unit offset by decreased expected oil recoveries in the Goldsmith Landreth San Andres Unit based on higher operating costs and lower well performance.
|
•
|
the standardized measure includes our estimate of proved crude oil, NGL and natural gas reserves and projected future production volumes based upon year-end economic conditions;
|
•
|
pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for the year;
|
•
|
future development and production costs are determined based upon actual cost at year-end;
|
•
|
the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
|
•
|
a discount factor of 10% per year is applied annually to the future net cash flows.
|
(a)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries.
|
(b)
|
Includes abandonment costs.
|
(c)
|
Standardized Measure of discounted future net cash flows as of December 31, 2013 includes $843 million attributable to the Goldsmith Landreth San Andres Unit acquired in June 2013.
|
(a)
|
Amounts relate to KMCO
2
and its consolidated subsidiaries.
|
(b)
|
Excludes a gain attributable to our hedging contracts of $28 million for the year ended December 31, 2014 and losses of $31 million and $28 million for the years 2013 and 2012, respectively.
|
(c)
|
Primarily due to the extension of the SACROC unit.
|
(d)
|
Sale of the Claytonville field unit.
|
(e)
|
2014 revisions were primarily due to, increases due to the addition of projects and redefined original oil in place values at SACROC, additional proved developed nonproducing reserves volumes in the Katz Strawn Unit offset by decreased oil recoveries and higher operating costs for the Goldsmith Landreth San Andres Unit. 2013 revisions were primarily due to increased operating costs at the Katz Strawn Unit. 2012 revisions were primarily due to higher projected CO
2
flood recoveries resulting from updated performance at SACROC and the addition of proved undeveloped reserve volumes at the Katz Strawn Unit CO
2
flood.
|
(f)
|
Acquisition of the Goldsmith Landreth San Andres Unit in June 2013.
|
|
|
KINDER MORGAN, INC.
Registrant
|
|
|
|
|
|
By: /s/ KIMBERLY A. DANG
|
|
|
Kimberly A. Dang
Vice President and Chief Financial Officer
(principal financial and accounting officer)
|
Date:
|
February 23, 2015
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ KIMBERLY A. DANG
|
|
Vice President and Chief Financial Officer (principal financial officer and principal accounting officer)
|
|
February 23, 2015
|
Kimberly A. Dang
|
|
|
||
|
|
|
|
|
/s/ RICHARD D. KINDER
|
|
Director, Chairman and Chief Executive Officer (principal executive officer)
|
|
February 23, 2015
|
Richard D. Kinder
|
|
|
||
|
|
|
|
|
/s/ TED A. GARDNER
|
|
Director
|
|
February 23, 2015
|
Ted A. Gardner
|
|
|
||
|
|
|
|
|
/s/ ANTHONY W. HALL, JR.
|
|
Director
|
|
February 23, 2015
|
Anthony W. Hall, Jr.
|
|
|
||
|
|
|
|
|
/s/ GARY L. HULTQUIST
|
|
Director
|
|
February 23, 2015
|
Gary L. Hultquist
|
|
|
||
|
|
|
|
|
/s/ STEVEN J. KEAN
|
|
Director
|
|
February 23, 2015
|
Steven J. Kean
|
|
|
||
|
|
|
|
|
/s/ RONALD L. KUEHN, JR.
|
|
Director
|
|
February 23, 2015
|
Ronald L. Kuehn, Jr.
|
|
|
||
|
|
|
|
|
/s/ DEBORAH A. MACDONALD
|
|
Director
|
|
February 23, 2015
|
Deborah A. Macdonald
|
|
|
||
|
|
|
|
|
/s/ MICHAEL J. MILLER
|
|
Director
|
|
February 23, 2015
|
Michael J. Miller
|
|
|
||
|
|
|
|
|
/s/ MICHAEL C. MORGAN
|
|
Director
|
|
February 23, 2015
|
Michael C. Morgan
|
|
|
||
|
|
|
|
|
/s/ ARTHUR C. REICHSTETTER
|
|
Director
|
|
February 23, 2015
|
Arthur C. Reichstetter
|
|
|
||
|
|
|
|
|
/s/ FAYEZ SAROFIM
|
|
Director
|
|
February 23, 2015
|
Fayez Sarofim
|
|
|
||
|
|
|
|
|
/s/ C. PARK SHAPER
|
|
Director
|
|
February 23, 2015
|
C. Park Shaper
|
|
|
||
|
|
|
|
|
/s/ WILLIAM A. SMITH
|
|
Director
|
|
February 23, 2015
|
William A. Smith
|
|
|
||
|
|
|
|
|
/s/ JOEL V. STAFF
|
|
Director
|
|
February 23, 2015
|
Joel V. Staff
|
|
|
||
|
|
|
|
|
/s/ ROBERT F. VAGT
|
|
Director
|
|
February 23, 2015
|
Robert F. Vagt
|
|
|
||
|
|
|
|
|
/s/ PERRY M. WAUGHTAL
|
|
Director
|
|
February 23, 2015
|
Perry M. Waughtal
|
|
|
||
|
|
|
|
|
Series A-1
|
|
$1,601,620,180
|
|
Series A-2
|
|
$396,174,908
|
|
Series A-3
|
|
$1,263,504,879
|
|
Series A-4
|
|
$882,350,016
|
|
Series A-5
|
|
$882,350,016
|
|
Series A-6
|
|
$2,424,000,000
|
|
Series A-7
|
|
$64,500,000
|
|
Series A-8
|
|
$349,018,612
|
|
Series A-9
|
$50,849,302
|
|
Series A-1
|
20.2369
|
%
|
Series A-2
|
5.0058
|
%
|
Series A-3
|
15.9647
|
%
|
Series A-4
|
11.1487
|
%
|
Series A-5
|
11.1487
|
%
|
Series A-6
|
30.6278
|
%
|
Series A-7
|
0.8150
|
%
|
Series A-8
|
4.4099
|
%
|
Series A-9
|
0.6425%
|
|
(i)
|
100% of the amount, if any, by which
|
Series C-1
|
|
$5,579,453.42
|
|
Series C-2
|
|
$1,380,127.12
|
|
Series C-3
|
|
$4,401,584.54
|
|
Series C-4
|
|
$3,073,781.71
|
|
Series C-5
|
|
$3,073,781.71
|
|
Series C-6
|
|
$8,444,321.11
|
|
Series C-7
|
|
$224,694.19
|
|
Series C-8
|
|
$1,215,851.99
|
|
Series C-9
|
|
$177,140.20
|
|
Series A-1
|
|
$303,498,072
|
|
Series A-2
|
|
$77,577,870
|
|
Series A-3
|
|
$233,421,964
|
|
Series A-4
|
|
$163,006,790
|
|
Series A-5
|
|
$163,006,790
|
|
Series A-6
|
|
$413,475,850
|
|
Series A-7
|
|
$11,002,142
|
|
Series A-8
|
|
$59,534,145
|
|
Series A-9
|
|
$8,673,663
|
|
|
|
By:
|
|
/s/ Brandy L. Treadway
|
Name:
|
|
Brandy L. Treadway
|
|
|
|
INCORPORATOR
|
KINDER MORGAN, INC.
|
||
|
|
|
|
|
|
By:
|
|
/s/ David R. DeVeau
|
|
|
David R. DeVeau
|
|
|
Vice President
|
(a)
|
Kinder’s conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under applicable law, other than any motor vehicle violations for which no custodial penalty is imposed;
|
(b)
|
Kinder’s commission of fraud or embezzlement against the Company or any of its Subsidiaries;
|
(c)
|
Kinder’s willful and material breach of the Bylaws, the Charter or the Shareholders Agreement, including, without limitation, by willfully causing the Company or any of its Subsidiaries or Affiliates to take any material action prohibited under these Bylaws, the Charter or the Shareholders Agreement and failing to cure such breach, if curable, within thirty (30) calendar days following written notice thereof, specifically identifying such willful and material breach, having been delivered by a majority of the members of the board of directors to Kinder;
|
(d)
|
a judicial determination that Kinder has breached his fiduciary duties;
|
(e)
|
Kinder’s failure to perform the duties and responsibilities of his office as his primary business activity, provided, that, subject to Section 3.6(f) of the Shareholders Agreement, so long as it does not materially interfere with his duties, nothing herein shall preclude Kinder from accepting appointment to or continuing to serve on any board of directors or as trustee of any business corporation or any charitable organization, from engaging in charitable and community activities, from delivering lectures and fulfilling speaking engagements, or from directing and managing his personal investments and those of his family; or
|
(f)
|
Kinder’s material breach of the provisions of Section 3.6(f) of the Shareholders Agreement that, if curable, is not cured within thirty (30) calendar days after notice of such breach is delivered to Kinder by a majority of the members of the board of directors.
|
(1)
|
the sum of the present values, calculated as of the Redemption Date, of:
|
•
|
each interest payment that, but for the redemption, would have been payable on the Note, or portion of a Note, being redeemed on each interest payment date occurring after the Redemption Date, excluding any accrued interest for the period prior to the Redemption Date; and
|
•
|
the principal amount that, but for the redemption, would have been payable at the stated maturity of the Note, or portion of a Note, being redeemed;
|
(2)
|
the principal amount of the Note, or portion of a Note, being redeemed.
|
NO. [__]
|
U.S.$[________]
|
By:
|
Anthony Ashley Vice President and Treasurer |
(1)
|
the sum of the present values, calculated as of the Redemption Date, of:
|
(2)
|
the principal amount of the Security, or portion of a Security, being redeemed.
|
By:
|
/s/ Anthony B. Ashley
|
By:
|
/s/ Anthony B. Ashley
|
Issuer
|
|
Indebtedness
|
|
Maturity
|
Kinder Morgan, Inc.
|
|
5.15% notes
|
|
March 1, 2015
|
Kinder Morgan, Inc.
|
|
5.70% notes
|
|
January 5, 2016
|
Kinder Morgan, Inc.
|
|
8.25% bonds
|
|
February 15, 2016
|
Kinder Morgan, Inc.
|
|
$100 million Letter of Credit Facility
|
|
June 20, 2016
|
Kinder Morgan, Inc.
|
|
7.00% bonds
|
|
June 15, 2017
|
Kinder Morgan, Inc.
|
|
2.00% notes
|
|
December 1, 2017
|
Kinder Morgan, Inc.
|
|
6.00% notes
|
|
January 15, 2018
|
Kinder Morgan, Inc.
|
|
7.00% bonds (Sonat)
|
|
February 1, 2018
|
Kinder Morgan, Inc.
|
|
7.25% bonds
|
|
June 1, 2018
|
Kinder Morgan, Inc.
|
|
3.05% notes
|
|
December 1, 2019
|
Kinder Morgan, Inc.
|
|
6.50% bonds
|
|
September 15, 2020
|
Kinder Morgan, Inc.
|
|
5.00% notes
|
|
February 15, 2021
|
Kinder Morgan, Inc.
|
|
5.625% notes
|
|
November 15, 2023
|
Kinder Morgan, Inc.
|
|
4.30% notes
|
|
June 1, 2025
|
Kinder Morgan, Inc.
|
|
6.70% bonds (Coastal)
|
|
February 15, 2027
|
Kinder Morgan, Inc.
|
|
6.67% debentures
|
|
November 1, 2027
|
Kinder Morgan, Inc.
|
|
7.25% debentures
|
|
March 1, 2028
|
Kinder Morgan, Inc.
|
|
6.95% bonds (Coastal)
|
|
June 1, 2028
|
Kinder Morgan, Inc.
|
|
8.05% bonds
|
|
October 15, 2030
|
Kinder Morgan, Inc.
|
|
7.80% bonds
|
|
August 1, 2031
|
Kinder Morgan, Inc.
|
|
7.75% bonds
|
|
January 15, 2032
|
Kinder Morgan, Inc.
|
|
5.30% notes
|
|
December 1, 2034
|
Kinder Morgan, Inc.
|
|
7.75% bonds (Coastal)
|
|
October 15, 2035
|
Kinder Morgan, Inc.
|
|
6.40% notes
|
|
January 5, 2036
|
Kinder Morgan, Inc.
|
|
7.42% bonds (Coastal)
|
|
February 15, 2037
|
Kinder Morgan, Inc.
|
|
5.55% notes
|
|
June 1, 2045
|
Kinder Morgan, Inc.
|
|
7.45% debentures
|
|
March 1, 2098
|
Kinder Morgan Energy Partners, L.P.
|
|
5.625% bonds
|
|
February 15, 2015
|
Kinder Morgan Energy Partners, L.P.
|
|
3.50% bonds
|
|
March 1, 2016
|
Kinder Morgan Energy Partners, L.P.
|
|
6.00% bonds
|
|
February 1, 2017
|
Kinder Morgan Energy Partners, L.P.
|
|
5.95% bonds
|
|
February 15, 2018
|
Kinder Morgan Energy Partners, L.P.
|
|
9.00% bonds
|
|
February 1, 2019
|
Kinder Morgan Energy Partners, L.P.
|
|
2.65% bonds
|
|
February 1, 2019
|
Kinder Morgan Energy Partners, L.P.
|
|
6.85% bonds
|
|
February 15, 2020
|
Kinder Morgan Energy Partners, L.P.
|
|
5.30% bonds
|
|
September 15, 2020
|
Kinder Morgan Energy Partners, L.P.
|
|
5.80% bonds
|
|
March 1, 2021
|
Kinder Morgan Energy Partners, L.P.
|
|
3.50% bonds
|
|
March 1, 2021
|
Kinder Morgan Energy Partners, L.P.
|
|
4.15% bonds
|
|
March 1, 2022
|
Kinder Morgan Energy Partners, L.P.
|
|
3.95% bonds
|
|
September 1, 2022
|
Kinder Morgan Energy Partners, L.P.
|
|
3.45% bonds
|
|
February 15, 2023
|
Kinder Morgan Energy Partners, L.P.
|
|
3.50% bonds
|
|
September 1, 2023
|
Kinder Morgan Energy Partners, L.P.
|
|
4.15% bonds
|
|
February 1, 2024
|
|
|
Schedule I
|
||
|
|
(Guaranteed Obligations)
|
||
|
|
|
|
February 13, 2015
|
Issuer
|
|
Indebtedness
|
|
Maturity
|
Kinder Morgan Energy Partners, L.P.
|
|
4.25% bonds
|
|
September 1, 2024
|
Kinder Morgan Energy Partners, L.P.
|
|
7.40% bonds
|
|
March 15, 2031
|
Kinder Morgan Energy Partners, L.P.
|
|
7.75% bonds
|
|
March 15, 2032
|
Kinder Morgan Energy Partners, L.P.
|
|
7.30% bonds
|
|
August 15, 2033
|
Kinder Morgan Energy Partners, L.P.
|
|
5.80% bonds
|
|
March 15, 2035
|
Kinder Morgan Energy Partners, L.P.
|
|
6.50% bonds
|
|
February 1, 2037
|
Kinder Morgan Energy Partners, L.P.
|
|
6.95% bonds
|
|
January 15, 2038
|
Kinder Morgan Energy Partners, L.P.
|
|
6.50% bonds
|
|
September 1, 2039
|
Kinder Morgan Energy Partners, L.P.
|
|
6.55% bonds
|
|
September 15, 2040
|
Kinder Morgan Energy Partners, L.P.
|
|
6.375% bonds
|
|
March 1, 2041
|
Kinder Morgan Energy Partners, L.P.
|
|
5.625% bonds
|
|
September 1, 2041
|
Kinder Morgan Energy Partners, L.P.
|
|
5.00% bonds
|
|
August 15, 2042
|
Kinder Morgan Energy Partners, L.P.
|
|
5.00% bonds
|
|
March 1, 2043
|
Kinder Morgan Energy Partners, L.P.
|
|
5.50% bonds
|
|
March 1, 2044
|
Kinder Morgan Energy Partners, L.P.
|
|
5.40% bonds
|
|
September 1, 2044
|
El Paso Pipeline Partners, L.P.
|
|
4.10% bonds
|
|
November 15, 2015
|
El Paso Pipeline Partners, L.P.
|
|
6.50% bonds
|
|
April 1, 2020
|
El Paso Pipeline Partners, L.P.
|
|
5.00% bonds
|
|
October 1, 2021
|
El Paso Pipeline Partners, L.P.
|
|
4.30% bonds
|
|
May 1, 2024
|
El Paso Pipeline Partners, L.P.
|
|
7.50% bonds
|
|
November 15, 2040
|
El Paso Pipeline Partners, L.P.
|
|
4.70% bonds
|
|
November 1, 2042
|
Tennessee Gas Pipeline Co.
|
|
8.00% bonds
|
|
February 1, 2016
|
Tennessee Gas Pipeline Co.
|
|
7.50% bonds
|
|
April 1, 2017
|
Tennessee Gas Pipeline Co.
|
|
7.00% bonds
|
|
March 15, 2027
|
Tennessee Gas Pipeline Co.
|
|
7.00% bonds
|
|
October 15, 2028
|
Tennessee Gas Pipeline Co.
|
|
8.375% bonds
|
|
June 15, 2032
|
Tennessee Gas Pipeline Co.
|
|
7.625% bonds
|
|
April 1, 2037
|
El Paso Natural Gas Co.
|
|
5.95% bonds
|
|
April 15, 2017
|
El Paso Natural Gas Co.
|
|
8.625% bonds
|
|
January 15, 2022
|
El Paso Natural Gas Co.
|
|
7.50% bonds
|
|
November 15, 2026
|
El Paso Natural Gas Co.
|
|
8.375% bonds
|
|
June 15, 2032
|
Colorado Interstate Gas Co.
|
|
5.95% bonds
|
|
March 15, 2015
|
Colorado Interstate Gas Co.
|
|
6.8% bonds
|
|
November 15, 2015
|
Colorado Interstate Gas Co.
|
|
6.85% bonds
|
|
June 15, 2037
|
Southern Natural Gas Co.
|
|
5.90% bonds
|
|
April 1, 2017
|
Southern Natural Gas Co.
|
|
4.40% bonds
|
|
June 15, 2021
|
Southern Natural Gas Co.
|
|
7.35% bonds
|
|
February 15, 2031
|
Southern Natural Gas Co.
|
|
8.00% bonds
|
|
March 1, 2032
|
Copano Energy LLC
|
|
7.125% bonds
|
|
April 1, 2021
|
El Paso Tennessee Pipeline Co.
|
|
7.25% bonds
|
|
December 15, 2025
|
Other
|
|
6.00% Hamilton notes
|
|
April 21, 2015
|
Other
|
|
KM LQT IRBs-Stolt floating rate bonds
|
|
January 15, 2018
|
Other
|
|
KM LQT IRBs-Stolt floating rate bonds $25,000,000 (plus accrued and unpaid interest) letter of credit
|
|
March 11, 2015
|
Other
|
|
5.50% KM Columbus MBFC notes
|
|
September 1, 2022
|
Other
|
|
Cora industrial revenue bonds
|
|
April 1, 2024
|
Hiland Partners Holdings LLC and
|
|
7.25% notes
|
|
October 1, 2020
|
|
|
Schedule I
|
||
|
|
(Guaranteed Obligations)
|
||
|
|
|
|
February 13, 2015
|
Issuer
|
|
Indebtedness
|
|
Maturity
|
Hiland Partners Finance Corp.
|
|
|
|
|
Hiland Partners Holdings LLC and Hiland Partners Finance Corp.
|
|
5.50% notes
|
|
May 15, 2022
|
Hedging Agreements
1
|
|
|
|
|
Issuer
|
|
Guaranteed Party
|
|
Date
|
Kinder Morgan, Inc.
|
|
Bank of America, N.A.
|
|
August 29, 2001
|
Kinder Morgan, Inc.
|
|
Citibank, N.A.
|
|
March 14, 2002
|
Kinder Morgan, Inc.
|
|
J. Aron & Company
|
|
December 23, 2011
|
Kinder Morgan, Inc.
|
|
SunTrust Bank
|
|
August 29, 2001
|
Kinder Morgan, Inc.
|
|
Barclays Bank PLC
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Bank of Tokyo-Mitsubishi, Ltd., New York Branch
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Canadian Imperial Bank of Commerce
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Credit Agricole Corporate and Investment
Bank
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Credit Suisse International
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Deutsche Bank AG
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
ING Capital Markets LLC
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Mizuho Capital Markets Corporation
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Royal Bank of Canada
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
The Bank of Nova Scotia
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
The Royal Bank of Scotland PLC
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Societe Generale
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
UBS AG
|
|
November 26, 2014
|
Kinder Morgan, Inc.
|
|
Wells Fargo Bank, N.A.
|
|
November 26, 2014
|
Kinder Morgan Energy Partners, L.P.
|
|
Bank of America, N.A.
|
|
April 14, 1999
|
Kinder Morgan Energy Partners, L.P.
|
|
Bank of Tokyo-Mitsubishi, Ltd., New York Branch
|
|
November 23, 2004
|
Kinder Morgan Energy Partners, L.P.
|
|
Barclays Bank PLC
|
|
November 18, 2003
|
Kinder Morgan Energy Partners, L.P.
|
|
Canadian Imperial Bank of Commerce
|
|
August 4, 2011
|
Kinder Morgan Energy Partners, L.P.
|
|
Citibank, N.A.
|
|
March 14, 2002
|
Kinder Morgan Energy Partners, L.P.
|
|
Credit Agricole Corporate and Investment Bank
|
|
June 20, 2014
|
Kinder Morgan Energy Partners, L.P.
|
|
Credit Suisse International
|
|
May 14, 2010
|
Kinder Morgan Energy Partners, L.P.
|
|
Deutsche Bank AG
|
|
April 2, 2009
|
Kinder Morgan Energy Partners, L.P.
|
|
ING Capital Markets LLC
|
|
September 21, 2011
|
Kinder Morgan Energy Partners, L.P.
|
|
J. Aron & Company
|
|
November 11, 2004
|
Kinder Morgan Energy Partners, L.P.
|
|
JPMorgan Chase Bank
|
|
August 29, 2001
|
_________________________________________________
1
Guaranteed Obligations with respect to Hedging Agreements include International Swaps and
Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to any ISDA listed on this Schedule I.
|
|
|
Schedule I
|
||
|
|
(Guaranteed Obligations)
|
||
|
|
|
|
February 13, 2015
|
Hedging Agreements
1
|
|
|
|
|
Issuer
|
|
Guaranteed Party
|
|
Date
|
Kinder Morgan Energy Partners, L.P.
|
|
Mizuho Capital Markets Corporation
|
|
July 11, 2014
|
Kinder Morgan Energy Partners, L.P.
|
|
Morgan Stanley Capital Services Inc.
|
|
March 10, 2010
|
Kinder Morgan Energy Partners, L.P.
|
|
Royal Bank of Canada
|
|
March 12, 2009
|
Kinder Morgan Energy Partners, L.P.
|
|
The Royal Bank of Scotland PLC
|
|
March 20, 2009
|
Kinder Morgan Energy Partners, L.P.
|
|
The Bank of Nova Scotia
|
|
August 14, 2003
|
Kinder Morgan Energy Partners, L.P.
|
|
Societe Generale
|
|
July 18, 2014
|
Kinder Morgan Energy Partners, L.P.
|
|
SunTrust Bank
|
|
March 14, 2002
|
Kinder Morgan Energy Partners, L.P.
|
|
UBS AG
|
|
February 23, 2011
|
Kinder Morgan Energy Partners, L.P.
|
|
Wells Fargo Bank, N.A.
|
|
July 31, 2007
|
Kinder Morgan Texas Pipeline LLC
|
|
Barclays Bank PLC
|
|
January 10, 2003
|
Kinder Morgan Texas Pipeline LLC
|
|
Canadian Imperial Bank of Commerce
|
|
December 18, 2006
|
Kinder Morgan Texas Pipeline LLC
|
|
Citibank, N.A.
|
|
February 22, 2005
|
Kinder Morgan Texas Pipeline LLC
|
|
Credit Suisse International
|
|
August 31, 2012
|
Kinder Morgan Texas Pipeline LLC
|
|
Deutsche Bank AG
|
|
June 13, 2007
|
Kinder Morgan Texas Pipeline LLC
|
|
ING Capital Markets LLC
|
|
April 17, 2014
|
Kinder Morgan Production Company LP
|
|
J. Aron & Company
|
|
June 12, 2006
|
Kinder Morgan Texas Pipeline LLC
|
|
J. Aron & Company
|
|
June 8, 2000
|
Kinder Morgan Texas Pipeline LLC
|
|
JPMorgan Chase Bank, N.A.
|
|
September 7, 2006
|
Kinder Morgan Texas Pipeline LLC
|
|
Macquarie Bank Limited
|
|
September 20, 2010
|
Kinder Morgan Texas Pipeline LLC
|
|
Merrill Lynch Commodities, Inc.
|
|
October 24, 2001
|
Kinder Morgan Texas Pipeline LLC
|
|
Morgan Stanley Capital Group Inc.
|
|
January 15, 2004
|
Kinder Morgan Texas Pipeline LLC
|
|
Natixis
|
|
June 13, 2011
|
Kinder Morgan Texas Pipeline LLC
|
|
Royal Bank of Canada
|
|
May 6, 2009
|
Kinder Morgan Texas Pipeline LLC
|
|
The Bank of Nova Scotia
|
|
May 8, 2014
|
Kinder Morgan Texas Pipeline LLC
|
|
Shell Trading (US) Company
|
|
November 14, 2011
|
Kinder Morgan Texas Pipeline LLC
|
|
Societe Generale
|
|
January 14, 2003
|
Kinder Morgan Texas Pipeline LLC
|
|
Wells Fargo Bank, N.A.
|
|
June 1, 2013
|
Copano Risk Management, L.P.
|
|
Citibank, N.A.
|
|
July 21, 2008
|
Copano Risk Management, L.P.
|
|
J. Aron & Company
|
|
December 12, 2005
|
Copano Risk Management, L.P.
|
|
Morgan Stanley Capital Group Inc.
|
|
May 4, 2007
|
Copano Risk Management, L.P.
|
|
Wells Fargo Bank, N.A.
|
|
October 19, 2007
|
SCHEDULE II
Guarantors
February 13, 2015
|
||
Agnes B Crane, LLC
|
|
Copano/Webb-Duval Pipeline LLC
|
American Petroleum Tankers II LLC
|
|
CPNO Services LLC
|
American Petroleum Tankers III LLC
|
|
Dakota Bulk Terminal, Inc.
|
American Petroleum Tankers IV LLC
|
|
Delta Terminal Services LLC
|
American Petroleum Tankers LLC
|
|
Eagle Ford Gathering LLC
|
American Petroleum Tankers Parent LLC
|
|
El Paso Cheyenne Holdings, L.L.C.
|
American Petroleum Tankers V LLC
|
|
El Paso Citrus Holdings, Inc.
|
American Petroleum Tankers VI LLC
|
|
El Paso CNG Company, L.L.C.
|
American Petroleum Tankers VII LLC
|
|
El Paso Energy Service Company, L.L.C.
|
APT Florida LLC
|
|
El Paso LLC
|
APT Intermediate Holdco LLC
|
|
El Paso Midstream Group LLC
|
APT New Intermediate Holdco LLC
|
|
El Paso Natural Gas Company, L.L.C.
|
APT Pennsylvania LLC
|
|
El Paso Noric Investments III, L.L.C.
|
APT Sunshine State LLC
|
|
El Paso Ruby Holding Company, L.L.C.
|
Audrey Tug LLC
|
|
El Paso Tennessee Pipeline Co., L.L.C.
|
Bear Creek Storage Company, L.L.C.
|
|
Elba Express Company, L.L.C.
|
Betty Lou LLC
|
|
Elizabeth River Terminals LLC
|
Camino Real Gathering Company, L.L.C.
|
|
Emory B Crane, LLC
|
Cantera Gas Company LLC
|
|
EP Energy Holding Company
|
CDE Pipeline LLC
|
|
EP Ruby LLC
|
Central Florida Pipeline LLC
|
|
EPBGP Contracting Services LLC
|
Cheyenne Plains Gas Pipeline Company, L.L.C.
|
|
EPTP Issuing Corporation
|
CIG Gas Storage Company LLC
|
|
Fernandina Marine Construction Management
|
CIG Pipeline Services Company, L.L.C.
|
|
LLC
|
Cimmarron Gathering LLC
|
|
Frank L. Crane, LLC
|
Colorado Interstate Gas Company, L.L.C.
|
|
General Stevedores GP, LLC
|
Colorado Interstate Issuing Corporation
|
|
General Stevedores Holdings LLC
|
Copano Double Eagle LLC
|
|
Global American Terminals LLC
|
Copano Energy Finance Corporation
|
|
Hampshire LLC
|
Copano Energy Services/Upper Gulf Coast LLC
|
|
Harrah Midstream LLC
|
Copano Energy, L.L.C.
|
|
HBM Environmental, Inc.
|
Copano Field Services GP, L.L.C.
|
|
Hiland Crude, LLC
|
Copano Field Services/North Texas, L.L.C.
|
|
Hiland Operating, LLC
|
Copano Field Services/South Texas LLC
|
|
Hiland Partners, LLC
|
Copano Field Services/Upper Gulf Coast LLC
|
|
Hiland Partners Finance Corp.
|
Copano Liberty, LLC
|
|
Hiland Partners Holdings LLC
|
Copano NGL Services (Markham), L.L.C.
|
|
ICPT, L.L.C
|
Copano NGL Services LLC
|
|
Independent Trading & Transportation
|
Copano Pipelines Group, L.L.C.
|
|
Company I, L.L.C.
|
Copano Pipelines/North Texas, L.L.C.
|
|
J.R. Nicholls LLC
|
Copano Pipelines/Rocky Mountains, LLC
|
|
Javelina Tug LLC
|
Copano Pipelines/South Texas LLC
|
|
Jeannie Brewer LLC
|
Copano Pipelines/Upper Gulf Coast LLC
|
|
JV Tanker Charterer LLC
|
Copano Processing LLC
|
|
Kinder Morgan (Delaware), Inc.
|
Copano Risk Management LLC
|
|
Kinder Morgan 2-Mile LLC
|
Kinder Morgan Administrative Services Tampa
|
|
Kinder Morgan Petcoke LP LLC
|
LLC
|
|
Kinder Morgan Petcoke, L.P.
|
Kinder Morgan Altamont LLC
|
|
Kinder Morgan Petroleum Tankers LLC
|
Kinder Morgan Amory LLC
|
|
Kinder Morgan Pipeline LLC
|
Kinder Morgan Arrow Terminals Holdings, Inc.
|
|
Kinder Morgan Port Manatee Terminal LLC
|
Kinder Morgan Arrow Terminals, L.P.
|
|
Kinder Morgan Port Sutton Terminal LLC
|
Kinder Morgan Baltimore Transload Terminal
|
|
Kinder Morgan Port Terminals USA LLC
|
LLC
|
|
Kinder Morgan Production Company LLC
|
Kinder Morgan Battleground Oil LLC
|
|
Kinder Morgan Rail Services LLC
|
Kinder Morgan Border Pipeline LLC
|
|
Kinder Morgan Resources II LLC
|
Kinder Morgan Bulk Terminals, Inc.
|
|
Kinder Morgan Resources III LLC
|
Kinder Morgan Carbon Dioxide Transportation
|
|
Kinder Morgan Resources LLC
|
Company
|
|
Kinder Morgan River Terminals LLC
|
Kinder Morgan CO2 Company, L.P.
|
|
Kinder Morgan Services LLC
|
Kinder Morgan Cochin LLC
|
|
Kinder Morgan Seven Oaks LLC
|
Kinder Morgan Columbus LLC
|
|
Kinder Morgan Southeast Terminals LLC
|
Kinder Morgan Commercial Services LLC
|
|
Kinder Morgan Scurry Connector LLC
|
Kinder Morgan Crude & Condensate LLC
|
|
Kinder Morgan Tank Storage Terminals LLC
|
Kinder Morgan Crude Oil Pipelines LLC
|
|
Kinder Morgan Tejas Pipeline LLC
|
Kinder Morgan Crude to Rail LLC
|
|
Kinder Morgan Terminals, Inc.
|
Kinder Morgan Cushing LLC
|
|
Kinder Morgan Texas Pipeline LLC
|
Kinder Morgan Dallas Fort Worth Rail Terminal
|
|
Kinder Morgan Texas Terminals, L.P.
|
LLC
|
|
Kinder Morgan Transmix Company, LLC
|
Kinder Morgan Endeavor LLC
|
|
Kinder Morgan Treating LP
|
Kinder Morgan Energy Partners, L.P.
|
|
Kinder Morgan Urban Renewal, L.L.C.
|
Kinder Morgan EP Midstream LLC
|
|
Kinder Morgan Utica LLC
|
Kinder Morgan Finance Company LLC
|
|
Kinder Morgan Virginia Liquids Terminals LLC
|
Kinder Morgan Fleeting LLC
|
|
Kinder Morgan Wink Pipeline LLC
|
Kinder Morgan Freedom Pipeline LLC
|
|
KinderHawk Field Services LLC
|
Kinder Morgan, Inc.
|
|
KM Crane LLC
|
Kinder Morgan Keystone Gas Storage LLC
|
|
KM Decatur, Inc.
|
Kinder Morgan KMAP LLC
|
|
KM Eagle Gathering LLC
|
Kinder Morgan Las Vegas LLC
|
|
KM Gathering LLC
|
Kinder Morgan Linden Transload Terminal LLC
|
|
KM Kaskaskia Dock LLC
|
Kinder Morgan Liquids Terminals LLC
|
|
KM Liquids Terminals LLC
|
Kinder Morgan Liquids Terminals St. Gabriel
|
|
KM North Cahokia Land LLC
|
LLC
|
|
KM North Cahokia Special Project LLC
|
Kinder Morgan Marine Services LLC
|
|
KM North Cahokia Terminal Project LLC
|
Kinder Morgan Materials Services, LLC
|
|
KM Ship Channel Services LLC
|
Kinder Morgan Mid Atlantic Marine Services
|
|
KM Treating GP LLC
|
LLC
|
|
KM Treating Production LLC
|
Kinder Morgan NatGas O&M LLC
|
|
KMBT LLC
|
Kinder Morgan North Texas Pipeline LLC
|
|
KMGP Contracting Services LLC
|
Kinder Morgan Operating L.P. “ A”
|
|
KMGP Services Company, Inc.
|
Kinder Morgan Operating L.P. “ B”
|
|
KN Telecommunications, Inc.
|
Kinder Morgan Operating L.P. “ C”
|
|
Knight Power Company LLC
|
Kinder Morgan Operating L.P. “ D”
|
|
Lomita Rail Terminal LLC
|
Kinder Morgan Pecos LLC
|
|
Milwaukee Bulk Terminals LLC
|
Kinder Morgan Pecos Valley LLC
|
|
MJR Operating LLC
|
Kinder Morgan Petcoke GP LLC
|
|
Mojave Pipeline Company, L.L.C.
|
Mojave Pipeline Operating Company, L.L.C.
|
|
|
Mr. Bennett LLC
|
|
|
Mr. Vance LLC
|
|
|
Nassau Terminals LLC
|
|
|
NGPL Holdco Inc.
|
|
|
Paddy Ryan Crane, LLC
|
|
|
Palmetto Products Pipe Line LLC
|
|
|
PI 2 Pelican State LLC
|
|
|
Pinney Dock & Transport LLC
|
|
|
Queen City Terminals LLC
|
|
|
Rahway River Land LLC
|
|
|
Razorback Tug LLC
|
|
|
RCI Holdings, Inc.
|
|
|
River Terminals Properties GP LLC
|
|
|
River Terminal Properties, L.P.
|
|
|
ScissorTail Energy, LLC
|
|
|
SNG Pipeline Services Company, L.L.C.
|
|
|
Southern Gulf LNG Company, L.L.C.
|
|
|
Southern Liquefaction Company LLC
|
|
|
Southern LNG Company, L.L.C.
|
|
|
Southern Natural Gas Company, L.L.C.
|
|
|
Southern Natural Issuing Corporation
|
|
|
SouthTex Treaters LLC
|
|
|
Southwest Florida Pipeline LLC
|
|
|
SRT Vessels LLC
|
|
|
Stevedore Holdings, L.P.
|
|
|
Tajon Holdings, Inc.
|
|
|
Tejas Gas, LLC
|
|
|
Tejas Natural Gas, LLC
|
|
|
Tennessee Gas Pipeline Company, L.L.C.
|
|
|
Tennessee Gas Pipeline Issuing Corporation
|
|
|
Texan Tug LLC
|
|
|
TGP Pipeline Services Company, L.L.C.
|
|
|
Trans Mountain Pipeline (Puget Sound) LLC
|
|
|
TransColorado Gas Transmission Company LLC
|
|
|
Transload Services, LLC
|
|
|
Utica Marcellus Texas Pipeline LLC
|
|
|
Western Plant Services, Inc.
|
|
|
Wyoming Interstate Company, L.L.C.
|
|
|
SCHEDULE III
Excluded Subsidiaries |
||
ANR Real Estate Corporation
|
|
|
Coastal Eagle Point Oil Company
|
|
|
Coastal Oil New England, Inc.
|
|
|
Colton Processing Facility
|
|
|
Coscol Petroleum Corporation
|
|
|
El Paso CGP Company, L.L.C.
|
|
|
El Paso Energy Capital Trust I
|
|
|
El Paso Energy E.S.T. Company
|
|
|
El Paso Energy International Company
|
|
|
El Paso Marketing Company, L.L.C.
|
|
|
El Paso Merchant Energy North America Company, L.L.C.
|
|
|
El Paso Merchant Energy-Petroleum Company
|
|
|
El Paso Reata Energy Company, L.L.C.
|
|
|
El Paso Remediation Company
|
|
|
El Paso Services Holding Company
|
|
|
EPEC Corporation
|
|
|
EPEC Oil Company Liquidating Trust
|
|
|
EPEC Polymers, Inc.
|
|
|
EPED Holding Company
|
|
|
Kinder Morgan Louisiana Pipeline Holding LLC
|
|
|
Kinder Morgan Louisiana Pipeline LLC
|
|
|
KN Capital Trust I
|
|
|
KN Capital Trust III
|
|
|
Mesquite Investors, L.L.C.
|
|
|
|
|
|
Note: The Excluded Subsidiaries listed on this Schedule III may also be Excluded Subsidiaries pursuant to other exceptions set forth in the definition of “Excluded Subsidiary”.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
||||||||||
Pre-tax income from continuing operations before cumulative effect of a change in accounting principle and before adjustment for noncontrolling interests and equity earnings (including amortization of excess cost of equity investments) per statements of income
|
$
|
2,730
|
|
|
$
|
3,150
|
|
|
$
|
1,213
|
|
|
$
|
591
|
|
|
$
|
510
|
|
Add:
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
1,921
|
|
|
1,785
|
|
|
1,486
|
|
|
766
|
|
|
704
|
|
|||||
Amortization of capitalized interest
|
5
|
|
|
6
|
|
|
5
|
|
|
5
|
|
|
4
|
|
|||||
Distributed income of equity investees
|
381
|
|
|
398
|
|
|
311
|
|
|
200
|
|
|
132
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest capitalized from continuing operations
|
(75
|
)
|
|
(52
|
)
|
|
(27
|
)
|
|
(15
|
)
|
|
(13
|
)
|
|||||
Noncontrolling interest in pre-tax income of subsidiaries with no fixed charges
|
(377
|
)
|
|
(390
|
)
|
|
17
|
|
|
(22
|
)
|
|
(107
|
)
|
|||||
Income as adjusted
|
$
|
4,585
|
|
|
$
|
4,897
|
|
|
$
|
3,005
|
|
|
$
|
1,525
|
|
|
$
|
1,230
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest)
|
$
|
1,882
|
|
|
$
|
1,742
|
|
|
$
|
1,454
|
|
|
$
|
718
|
|
|
$
|
681
|
|
Add:
|
|
|
|
|
|
|
|
|
|
||||||||||
Portion of rents representative of the interest factor
|
39
|
|
|
43
|
|
|
32
|
|
|
48
|
|
|
23
|
|
|||||
Fixed charges
|
$
|
1,921
|
|
|
$
|
1,785
|
|
|
$
|
1,486
|
|
|
$
|
766
|
|
|
$
|
704
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
2.39
|
|
|
2.74
|
|
|
2.02
|
|
|
1.99
|
|
|
1.75
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
Agnes B Crane, LLC
|
|
Agua del Cajon (Cayman) Company
|
|
American Petroleum Tankers II LLC
|
|
American Petroleum Tankers III LLC
|
|
American Petroleum Tankers IV LLC
|
|
American Petroleum Tankers LLC
|
|
American Petroleum Tankers Parent LLC
|
|
American Petroleum Tankers V LLC
|
|
American Petroleum Tankers VI LLC
|
|
American Petroleum Tankers VII LLC
|
|
ANR Advance Holdings, Inc.
|
|
ANR Real Estate Corporation
|
|
APT Florida LLC
|
|
APT Intermediate Holdco LLC
|
|
APT New Intermediate Holdco LLC
|
|
APT Pennsylvania LLC
|
|
APT Sunshine State LLC
|
|
Aquamarine Power Holdings, L.L.C.
|
|
Audrey Tug LLC
|
|
Battleground Oil Specialty Terminal Company LLC
|
|
Bear Creek Storage Company, L.L.C.
|
|
Berkshire Feedline Acquisition Limited Partnership
|
|
BetaGen Power LLC
|
|
Betty Lou LLC
|
|
BHP Billiton Petroleum (Eagle Ford Gathering) LLC
|
|
Bighorn Gas Gathering, L.L.C.
|
|
Calnev Pipe Line LLC
|
|
Camino Real Gathering Company, L.L.C.
|
|
Coyote Gas Treating Limited Liability Company
|
|
CDE Pipeline LLC
|
|
Central Florida Pipeline LLC
|
|
Cheyenne Plains Gas Pipeline Company, L.L.C.
|
|
CIG Gas Storage Company LLC
|
|
CIG Pipeline Services Company, L.L.C.
|
|
Cimmarron Gathering LLC
|
|
Citrus Energy Services, Inc.
|
|
Citrus LLC
|
|
Cliffside Helium, LLC
|
|
Cliffside Refiners, L.P.
|
|
Coastal Eagle Point Oil Company
|
|
Coastal Energy Resources Ltd.
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
Coastal Oil New England, Inc.
|
|
Coastal Wartsila Petroleum Private Limited
|
|
Colbourne Insurance Company Limited
|
|
Colorado Interstate Gas Company, L.L.C.
|
|
Colorado Interstate Issuing Corporation
|
|
Colton Processing Facility
|
|
Copano Double Eagle LLC
|
|
Copano Energy Finance Corporation
|
|
Copano Energy L.L.C.
|
|
Copano Energy Services/Upper Gulf Coast LLC
|
|
Copano Field Services GP, L.L.C.
|
|
Copano Field Services/North Texas, L.L.C.
|
|
Copano Field Services/South Texas LLC
|
|
Copano Field Services/Upper Gulf Coast LLC
|
|
Copano Liberty, LLC
|
|
Copano NGL Services (Markham), L.L.C.
|
|
Copano NGL Services LLC
|
|
Copano Pipelines Group, L.L.C.
|
|
Copano Pipelines/North Texas, L.L.C.
|
|
Copano Pipelines/Rocky Mountains, LLC
|
|
Copano Pipelines/SouthTexas LLC
|
|
Copano Pipelines/Upper Gulf Coast LLC
|
|
Copano Processing LLC
|
|
Copano Risk Management LLC
|
|
Copano/Webb-Duval Pipeline LLC
|
|
Cortez Capital Corporation
|
|
Cortez Expansion Capital Corporation
|
|
Cortez Pipeline Company
|
|
Coscol Petroleum Corporation
|
|
CPNO Services LLC
|
|
Cross Country Development L.L.C.
|
|
Cypress Interstate Pipeline LLC
|
|
Dakota Bulk Terminal, Inc.
|
|
Deeprock Development, LLC
|
|
Deeprock North, LLC
|
|
Delta Terminal Services LLC
|
|
Devco USA, L.L.C.
|
|
Dietze Products LLC
|
|
Double Eagle Pipeline LLC
|
|
Eagle Ford Gathering LLC
|
|
Eastern Insurance Company Limited
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
El Paso Amazonas Energia Ltda.
|
|
El Paso Cayger III Company
|
|
El Paso Cayger IV Company
|
|
El Paso CGP Company, L.L.C.
|
|
El Paso Cheyenne Holdings, L.L.C.
|
|
El Paso Citrus Holdings, Inc.
|
|
El Paso CNG Company, L.L.C.
|
|
El Paso Corporate Foundation
|
|
El Paso Energia do Brasil Ltda.
|
|
El Paso Energy Argentina Services Company
|
|
El Paso Energy Capital Trust I
|
|
El Paso Energy Cayger II Company
|
|
El Paso Energy E.S.T. Company
|
|
El Paso Energy International Company
|
|
El Paso Energy Marketing de Mexico, S de RL de CV
|
|
El Paso Energy Service Company, L.L.C.
|
|
El Paso Fife I Company
|
|
El Paso LLC
|
|
El Paso Marketing Company, L.L.C.
|
|
El Paso Merchant Energy North America Company, L.L.C.
|
|
El Paso Merchant Energy-Petroleum Company
|
|
El Paso Mexico Holding B.V.
|
|
El Paso Midstream Group, Inc.
|
|
El Paso Natural Gas Company, L.L.C.
|
|
El Paso Neuquen Holding Company
|
|
El Paso Noric Investments III, L.L.C.
|
|
El Paso Pipeline Corporation
|
|
El Paso Pipeline GP Company, L.L.C.
|
|
El Paso Pipeline Holding Company, L.L.C.
|
|
El Paso Pipeline LP Holdings, L.L.C.
|
|
El Paso Pipeline Partners Operating Company, L.L.C.
|
|
El Paso Pipeline Partners, L.P.
|
|
El Paso Reata Energy Company, L.L.C.
|
|
El Paso Remediation Company
|
|
El Paso Rio Negro Energia Ltda.
|
|
El Paso Ruby Holding Company, L.L.C.
|
|
El Paso Services Holding Company
|
|
El Paso Tennessee Pipeline Co.
|
|
Elba Express Company, L.L.C.
|
|
Elba Liquefaction Company, L.L.C.
|
|
Elizabeth River Terminals LLC
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
Emory B Crane, LLC
|
|
Endeavor Gathering LLC
|
|
EP Production International Cayman Company
|
|
EP Ruby LLC
|
|
EPBGP Contracting Services LLC
|
|
EPC Building LLC
|
|
EPC Property Holdings, Inc.
|
|
EPEC Corporation
|
|
EPEC Oil Company Liquidating Trust
|
|
EPEC Polymers, Inc.
|
|
EPEC Realty, Inc.
|
|
EPED B Company
|
|
EPED Holding Company
|
|
EPIC Gas International Servicos do Brasil Ltda.
|
|
EPTP Issuing Corporation
|
|
Fayetteville Express Pipeline LLC
|
|
Fernandina Marine Construction Management LLC
|
|
Fife Power
|
|
Florida Gas Transmission Company, LLC
|
|
Fort Union Gas Gathering, L.L.C.
|
|
Frank L Crane, LLC
|
|
GEBF, L.L.C.
|
|
General Stevedores GP, LLC
|
|
General Stevedores Holdings LLC
|
|
GLE Channel Improvement, LLC
|
|
Global American Terminals LLC
|
|
Greens Bayou Fleeting, LLC
|
|
Greens Port CBR, LLC
|
|
Guilford County Terminal Company, LLC
|
|
Gulf LNG Energy (Port), LLC
|
|
Gulf LNG Energy, LLC
|
|
Gulf LNG Holdings Group, LLC
|
|
Gulf LNG Liquefaction Company, LLC
|
|
Gulf LNG Pipeline, LLC
|
|
Hampshire LLC
|
|
Harrah Midstream LLC
|
|
HBM Environmental, Inc.
|
|
Horizon Pipeline Company, L.L.C.
|
|
I.M.T. Land Corp.
|
|
ICPT, L.L.C.
|
|
Interenergy Company
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
International Marine Terminals Partnership
|
|
J.R. Nicholls LLC
|
|
Javelina Tug LLC
|
|
Jeannie Brewer LLC
|
|
Johnston County Terminal, LLC
|
|
JV Tanker Charterer LLC
|
|
Kellogg Terminal, LLC
|
|
Kinder Morgan (Delaware), LLC
|
|
Kinder Morgan 2-Mile LLC
|
|
Kinder Morgan Administrative Services Tampa LLC
|
|
Kinder Morgan Altamont LLC
|
|
Kinder Morgan Amory LLC
|
|
Kinder Morgan Arrow Terminals Holdings, Inc.
|
|
Kinder Morgan Arrow Terminals, L.P.
|
|
Kinder Morgan Arrow Terminals, L.P.
|
|
Kinder Morgan Baltimore Transload Terminal LLC
|
|
Kinder Morgan Battleground Oil LLC
|
|
Kinder Morgan Border Pipeline LLC
|
|
Kinder Morgan Bulk Terminals, Inc.
|
|
Kinder Morgan Canada Company
|
|
Kinder Morgan Carbon Dioxide Transportation Company
|
|
Kinder Morgan CO2 Company, L.P.
|
|
Kinder Morgan Cochin LLC
|
|
Kinder Morgan Columbus LLC
|
|
Kinder Morgan Commercial Services LLC
|
|
Kinder Morgan Crude & Condensate LLC
|
|
Kinder Morgan Crude Oil Pipelines LLC
|
|
Kinder Morgan Crude to Rail LLC
|
|
Kinder Morgan Cushing LLC
|
|
Kinder Morgan Dallas Fort Worth Rail Terminal LLC
|
|
Kinder Morgan Endeavor LLC
|
|
Kinder Morgan Energy Partners, L.P.
|
|
Kinder Morgan EP Midstream LLC
|
|
Kinder Morgan Finance Company LLC
|
|
Kinder Morgan Fleeting LLC
|
|
Kinder Morgan Foundation
|
|
Kinder Morgan Freedom Pipeline LLC
|
|
Kinder Morgan G.P., Inc.
|
|
Kinder Morgan Gas Natural de Mexico, S. de R.L. de C.V.
|
|
Kinder Morgan Illinois Pipeline LLC
|
|
Kinder Morgan, Inc.
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
Kinder Morgan Insurance Ltd.
|
|
Kinder Morgan Keystone Gas Storage LLC
|
|
Kinder Morgan KMAP LLC
|
|
Kinder Morgan Las Vegas LLC
|
|
Kinder Morgan Linden Transload Terminal LLC
|
|
Kinder Morgan Liquids Terminals LLC
|
|
Kinder Morgan Liquids Terminals St. Gabriel LLC
|
|
Kinder Morgan Louisiana Pipeline Holding LLC
|
|
Kinder Morgan Louisiana Pipeline LLC
|
|
Kinder Morgan Marine Services LLC
|
|
Kinder Morgan Materials Services, LLC
|
|
Kinder Morgan Mid Atlantic Marine Services LLC
|
|
Kinder Morgan NatGas O & M LLC
|
|
Kinder Morgan Operating L.P. "A"
|
|
Kinder Morgan Operating L.P. "B"
|
|
Kinder Morgan Operating L.P. "C"
|
|
Kinder Morgan Operating L.P. "D"
|
|
Kinder Morgan Pecos LLC
|
|
Kinder Morgan Pecos Valley LLC
|
|
Kinder Morgan Petcoke GP LLC
|
|
Kinder Morgan Petcoke LP LLC
|
|
Kinder Morgan Petcoke, L.P.
|
|
Kinder Morgan Petroleum Tankers LLC
|
|
Kinder Morgan Pipeline LLC
|
|
Kinder Morgan Pipeline Servicios de Mexico S. de R.L. de C.V.
|
|
Kinder Morgan Port Sutton Terminal LLC
|
|
Kinder Morgan Port Terminals USA LLC
|
|
Kinder Morgan Production Company LLC
|
|
Kinder Morgan Rail Services LLC
|
|
Kinder Morgan Resources II LLC
|
|
Kinder Morgan Resources III LLC
|
|
Kinder Morgan Resources LLC
|
|
Kinder Morgan River Terminals LLC
|
|
Kinder Morgan Scurry Connector LLC
|
|
Kinder Morgan Services LLC
|
|
Kinder Morgan Seven Oaks LLC
|
|
Kinder Morgan Southeast Terminals LLC
|
|
Kinder Morgan Tank Storage Terminals LLC
|
|
Kinder Morgan Tejas Pipeline GP LLC
|
|
Kinder Morgan Tejas Pipeline LLC
|
|
Kinder Morgan Terminals, Inc.
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
Kinder Morgan Texas Pipeline LLC
|
|
Kinder Morgan Texas Terminals, L.P.
|
|
Kinder Morgan Transmix Company, LLC
|
|
Kinder Morgan Treating LP
|
|
Kinder Morgan Urban Renewal, L.L.C.
|
|
Kinder Morgan Utica LLC
|
|
Kinder Morgan Virginia Liquids Terminals LLC
|
|
Kinder Morgan Wink Pipeline LLC
|
|
Kinder Morgan, Inc.
|
|
KinderHawk Field Services LLC
|
|
KM Canada Terminals ULC
|
|
KM Crane LLC
|
|
KM Decatur, Inc.
|
|
KM Eagle Gathering LLC
|
|
KM Gathering LLC
|
|
KM Kaskaskia Dock LLC
|
|
KM Liquids Terminals LLC
|
|
KM North Cahokia Land LLC
|
|
KM North Cahokia Special Project LLC
|
|
KM North Cahokia Terminal Project LLC
|
|
KM Ship Channel Services LLC
|
|
KM Treating GP LLC
|
|
KM Treating Production LLC
|
|
KMBT LLC
|
|
KMGP Contracting Services LLC
|
|
KMGP Services Company, Inc.
|
|
KN Telecommunications, Inc.
|
|
Knight Power Company LLC
|
|
KW Express, LLC
|
|
Liberty Pipeline Group, LLC
|
|
Lomita Rail Terminal LLC
|
|
Mesquite Investors, L.L.C.
|
|
Midco LLC
|
|
Mid-Ship Group LLC
|
|
Milwaukee Bulk Terminals LLC
|
|
MJR Operating LLC
|
|
Mojave Pipeline Company, L.L.C.
|
|
Mojave Pipeline Operating Company, L.L.C.
|
|
Mr. Bennett LLC
|
|
Mr. Vance LLC
|
|
Mt. Franklin Insurance Ltd.
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
Nassau Terminals LLC
|
|
Natural Gas Pipeline Company of America LLC
|
|
NGPL HoldCo Inc.
|
|
NGPL Holdco LLC
|
|
NGPL PipeCo LLC
|
|
North Cahokia Industrial, LLC
|
|
North Cahokia Real Estate, LLC
|
|
North Cahokia Terminal, LLC
|
|
North Denton Pipeline, L.L.C.
|
|
Northeast Expansion LLC
|
|
Paddy Ryan Crane, LLC
|
|
Palmetto Products Pipe Line LLC
|
|
Parkway Pipeline LLC
|
|
Pecos Carbon Dioxide Transportation Company
|
|
PI 2 Pelican State LLC
|
|
Pinney Dock & Transport LLC
|
|
Plantation Pipe Line Company
|
|
Plantation Services LLC
|
|
Queen City Terminals LLC
|
|
Rahway River Land LLC
|
|
Razorback Tug LLC
|
|
RCI Holdings, Inc.
|
|
Red Cedar Gathering Company
|
|
Reno Pipeline, L.L.C.
|
|
River Consulting, LLC
|
|
River Terminals Properties GP LLC
|
|
River Terminals Properties L.P.
|
|
Ruby Investment Company, L.L.C.
|
|
Ruby Pipeline Holding Company, L.L.C.
|
|
Ruby Pipeline, L.L.C.
|
|
ScissorTail Energy, LLC
|
|
SFPP, L.P.
|
|
Sierrita Gas Pipeline LLC
|
|
SNG Pipeline Services Company, L.L.C.
|
|
Sonoran Pipeline LLC
|
|
Southern Dome, LLC
|
|
Southern Gulf LNG Company, L.L.C.
|
|
Southern Liquefaction Company LLC
|
|
Southern LNG Company, L.L.C.
|
|
Southern Natural Gas Company, L.L.C.
|
|
Southern Natural Issuing Corporation
|
|
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2014
|
|
SouthTex Treaters LLC
|
|
Southwest Florida Pipeline LLC
|
|
SRT Vessels LLC
|
|
Stevedore Holdings, L.P.
|
|
Tajon Holdings, Inc.
|
|
Tejas Gas, LLC
|
|
Tejas Natural Gas, LLC
|
|
Tennessee Gas Pipeline Company, L.L.C.
|
|
Texan Tug LLC
|
|
TGP Pipeline Services Company, L.L.C.
|
|
Trans Mountain Pipeline (Puget Sound) LLC
|
|
TransColorado Gas Transmission Company LLC
|
|
Transload Services, LLC
|
|
Transport USA, Inc.
|
|
Utica Marcellus Texas Pipeline LLC
|
|
Webb/Duval Gatherers
|
|
Western Plant Services, Inc.
|
|
WYCO Development LLC
|
|
Wyoming Interstate Company, L.L.C.
|
|
Young Gas Storage Company, Ltd.
|
|
Entities part of the Canadian Structure as of December 31, 2014
|
|
Trans Mountain Pipeline (Puget Sound) LLC
|
|
Kinder Morgan Canada Company
|
|
KM Express Limited
|
|
Express GP Holdings Ltd.
|
|
6048935 Canada Inc.
|
|
Kinder Morgan Bison ULC
|
|
Kinder Morgan Heartland ULC
|
|
Kinder Morgan CO2 ULC
|
|
Trans Mountain (Jet Fuel) Inc.
|
|
Kinder Morgan Canada Inc.
|
|
Trans Mountain Pipeline ULC
|
|
Kinder Morgan Cochin ULC
|
|
KM Canada Terminals ULC
|
|
KM Crude by Rail Canada Corp
|
|
KW Express Canada GP Limited
|
|
KM Canada Rail Holdings GP Limited
|
|
* Canadian structure does not include the partnerships and their subsidiaries: Trans Mountain Pipeline LP.; Kinder Morgan Canada Terminals Limited Partnership and its subsidiary, KM Canada Edmonton South Rail Terminal Corp; KM Canada Edmonton South Rail Terminals LP; KM Canada Edmonton North Rail Terminal LP; KW Express Canada LP
|
|
1.
|
I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States;
|
c)
|
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 23, 2015
|
/s/ RICHARD D. KINDER
|
|
|
__________________________________________________
|
|
|
Richard D. Kinder
Chairman and Chief Executive Officer |
1.
|
I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States;
|
c.
|
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 23, 2015
|
|
/s/ KIMBERLY A. DANG
|
|
|
|
Kimberly A. Dang
Vice President and Chief Financial Officer |
Date:
|
February 23, 2015
|
|
/s/ RICHARD D. KINDER
|
|
|
|
Richard D. Kinder
Chairman and Chief Executive Officer
|
Date:
|
February 23, 2015
|
|
/s/ KIMBERLY A. DANG
|
|
|
|
Kimberly A. Dang
Vice President and Chief Financial Officer
|
Mine or Operating Name/MSHA Identification Number
|
Section 104 S&S Citations
(#)
|
Section 104(b) Orders
(#)
|
Section 104(d) Citations and Orders
(#)
|
Section 110(b)(2) Violations
(#)
|
Section 107(a) Orders
(#)
|
Total Dollar Value of MSHA Assessments Proposed
($)
|
Total Number of Mining Related Fatalities
(#)
|
Received Notice of Pattern of Violations Under Section 104(e)
(yes/no)
|
Received Notice of Potential to Have Pattern under Section 104(e)
(yes/no)
|
Legal Actions Pending as of Last Day of Period
(#)
|
Legal Actions Initiated During Period
(#)
|
Legal Actions Resolved During Period
(#)
|
||
1103225 Cahokia
|
—
|
—
|
—
|
—
|
—
|
$
|
—
|
|
—
|
No
|
No
|
—
|
—
|
—
|
1518234
Grand Rivers
|
—
|
—
|
—
|
—
|
—
|
$
|
—
|
|
—
|
No
|
No
|
—
|
—
|
—
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
57,034.8
|
|
4,583.6
|
|
2,069.3
|
|
2,191,510.9
|
|
1,677,258.9
|
Proved Developed Non-Producing
|
|
3,217.7
|
|
0.0
|
|
0.0
|
|
50,679.7
|
|
29,635.1
|
Proved Undeveloped
|
|
37,304.7
|
|
6,235.9
|
|
0.0
|
|
756,555.7
|
|
203,205.7
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
97,557.2
|
|
10,819.5
|
|
2,069.3
|
|
2,998,746.3
|
|
1,910,099.7
|
|
|
|
Sincerely,
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
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|
|
Texas Registered Engineering Firm F-2699
|
||
|
|
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|
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|
|
|
|
/s/ C.H. (Scott) Rees III
|
|
|
|
|
By:
|
|
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
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|
Chairman and Chief Executive Officer
|
|
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/s/ Derek F. Newton
|
|
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/s/ Mike K. Norton
|
|
By:
|
|
|
By:
|
|
|
|
Derek F. Newton, P.E. 97689
|
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|
Mike K. Norton, P.G. 441
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|
|
Vice President
|
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Senior Vice President
|
|
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|
|
Date Signed: January 8, 2015
|
|
Date Signed: January 8, 2015
|
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
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(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
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(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
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(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
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(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
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The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
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b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
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Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
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(vi)
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Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
|
●
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
|
●
The company's historical record at completing development of comparable long-term projects;
|
●
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
|
●
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
|
●
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|