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Oklahoma
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73-1481638
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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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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Common Stock
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New York Stock Exchange
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Large accelerated filer
R
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Accelerated filer
£
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Non-accelerated filer
£
(Do not check if a smaller reporting company)
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Smaller reporting company
£
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Abbreviation
|
Definition
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401(k) Plan
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Qualified defined contribution retirement plan
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APSC
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Arkansas Public Service Commission
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ArcLight group
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Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
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Atoka
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Atoka Midstream LLC joint venture
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BART
|
Best Available Retrofit Technology
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Code
|
Internal Revenue Code of 1986
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Company
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OGE Energy, collectively with its subsidiaries
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Cordillera
|
Cordillera Energy Partners III, LLC
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Crossroads
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OG&E's Crossroads wind farm in Dewey County, Oklahoma
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Dodd-Frank Act
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Dodd-Frank Wall Street Reform and Consumer Protection Act
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Dry Scrubbers
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Dry flue gas desulfurization units with Spray Dryer Absorber
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Enogex
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OGE Holdings, collectively with its subsidiaries
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Enogex LLC
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Enogex LLC, collectively with its subsidiaries
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Enogex Holdings
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Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings
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EPA
|
U.S. Environmental Protection Agency
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Federal Clean Water Act
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Federal Water Pollution Control Act of 1972, as amended
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FERC
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Federal Energy Regulatory Commission
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GAAP
|
Accounting principles generally accepted in the United States
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MEP
|
Midcontinent Express Pipeline, LLC
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MMBtu
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Million British thermal unit
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MMcf/d
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Million cubic feet per day
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MW
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Megawatt
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MWH
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Megawatt-hour
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NAAQS
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National Ambient Air Quality Standards
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NGLs
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Natural gas liquids
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NOX
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Nitrogen oxide
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NYMEX
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New York Mercantile Exchange
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OCC
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Oklahoma Corporation Commission
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ODEQ
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Oklahoma Department of Environmental Quality
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OER
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OGE Energy Resources LLC, wholly-owned subsidiary of Enogex LLC
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Off-system sales
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Sales to other utilities and power marketers
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OG&E
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Oklahoma Gas and Electric Company
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OGE Holdings
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OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings
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OSHA
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Federal Occupational Safety and Health Act of 1970
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Oxbow
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Oxbow Midstream, LLC
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Pension Plan
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Qualified defined benefit retirement plan
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PHMSA
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U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration
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PRM
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Price risk management
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Products
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Enogex Products LLC, wholly-owned subsidiary of Enogex LLC
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PSO
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Public Service Company of Oklahoma
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QF
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Qualified cogeneration facilities
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QF contracts
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Contracts with QFs and small power production producers
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SIP
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State implementation plan
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SO2
|
Sulfur dioxide
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SPP
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Southwest Power Pool
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System sales
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Sales to OG&E's customers
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TBtu/d
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Trillion British thermal units per day
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Windspeed
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OG&E's transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma
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•
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general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
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•
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the ability of the Company and its subsidiaries
to access the capital markets and obtain financing on favorable terms;
|
•
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prices and availability of electricity, coal
,
natural gas
and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee;
|
•
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business conditions in the energy
and natural gas midstream industries;
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•
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competitive factors including the extent and timing of the entry of additional competition in the markets served by
the Company;
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•
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unusual weather;
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•
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availability and prices of raw materials for current and future construction projects;
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•
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Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters
the Company's
markets;
|
•
|
environmental laws and regulations that may impact
the Company's
operations;
|
•
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changes in accounting standards, rules or guidelines;
|
•
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the discontinuance of accounting principles for certain types of rate-regulated activities;
|
•
|
whether OG&E can successfully implement its Smart Grid program to install meters for its customers and integrate the Smart Grid meters with its customer billing and other computer information systems;
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•
|
the cost of protecting assets against, or damage due to, terrorism or cyber attacks;
|
•
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advances in technology;
|
•
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creditworthiness of suppliers, customers and other contractual parties;
|
•
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the higher degree of risk associated with the Company's nonregulated business compared with the Company's regulated utility business; and
|
•
|
other risk factors listed in the reports filed by
the Company
with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to this Form 10-K.
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Year ended December 31
|
2011
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2011 vs. 2010 Increase
|
2010
|
2010 vs. 2009 Increase
|
2009
|
System sales - millions of MWHs
|
28.5
|
3.3%
|
27.6
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6.6%
|
25.9
|
OKLAHOMA GAS AND ELECTRIC COMPANY
|
|||||||||
CERTAIN OPERATING STATISTICS
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|||||||||
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||||||
Year ended December 31
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2011
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2010
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2009
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||||||
ELECTRIC ENERGY
(Millions of MWH)
|
|
|
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||||||
Generation (exclusive of station use)
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26.7
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25.6
|
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25.0
|
|
|||
Purchased
|
4.9
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4.7
|
|
3.9
|
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|||
Total generated and purchased
|
31.6
|
|
30.3
|
|
28.9
|
|
|||
OG&E use, free service and losses
|
(2.1
|
)
|
(2.2
|
)
|
(2.0
|
)
|
|||
Electric energy sold
|
29.5
|
|
28.1
|
|
26.9
|
|
|||
ELECTRIC ENERGY SOLD
(Millions of MWH)
|
|
|
|
||||||
Residential
|
9.9
|
|
9.6
|
|
8.7
|
|
|||
Commercial
|
6.9
|
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6.7
|
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6.4
|
|
|||
Industrial
|
3.9
|
|
3.8
|
|
3.6
|
|
|||
Oilfield
|
3.2
|
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3.1
|
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2.9
|
|
|||
Public authorities and street light
|
3.2
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3.0
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3.0
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|||
Sales for resale
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1.4
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1.4
|
|
1.3
|
|
|||
System sales
|
28.5
|
|
27.6
|
|
25.9
|
|
|||
Off-system sales
|
1.0
|
|
0.5
|
|
1.0
|
|
|||
Total sales
|
29.5
|
|
28.1
|
|
26.9
|
|
|||
ELECTRIC OPERATING REVENUES
(In millions)
|
|
|
|
||||||
Residential
|
$
|
943.5
|
|
$
|
894.8
|
|
$
|
717.9
|
|
Commercial
|
531.3
|
|
521.0
|
|
439.8
|
|
|||
Industrial
|
216.0
|
|
212.5
|
|
172.1
|
|
|||
Oilfield
|
165.1
|
|
162.8
|
|
132.6
|
|
|||
Public authorities and street light
|
207.4
|
|
200.8
|
|
167.7
|
|
|||
Sales for resale
|
65.3
|
|
65.8
|
|
53.6
|
|
|||
Provision for rate refund
|
—
|
|
—
|
|
(0.6
|
)
|
|||
System sales revenues
|
2,128.6
|
|
2,057.7
|
|
1,683.1
|
|
|||
Off-system sales revenues
|
36.2
|
|
21.7
|
|
31.8
|
|
|||
Other
|
46.7
|
|
30.5
|
|
36.3
|
|
|||
Total operating revenues
|
$
|
2,211.5
|
|
$
|
2,109.9
|
|
$
|
1,751.2
|
|
ACTUAL NUMBER OF ELECTRIC CUSTOMERS
(At end of period)
|
|
|
|
||||||
Residential
|
675,806
|
|
670,309
|
|
665,344
|
|
|||
Commercial
|
87,480
|
|
86,496
|
|
85,537
|
|
|||
Industrial
|
2,991
|
|
3,020
|
|
3,056
|
|
|||
Oilfield
|
6,451
|
|
6,418
|
|
6,437
|
|
|||
Public authorities and street light
|
16,374
|
|
16,264
|
|
16,124
|
|
|||
Sales for resale
|
44
|
|
51
|
|
52
|
|
|||
Total
|
789,146
|
|
782,558
|
|
776,550
|
|
|||
AVERAGE RESIDENTIAL CUSTOMER SALES
|
|
|
|
||||||
Average annual revenue
|
$
|
1,401.84
|
|
$
|
1,339.81
|
|
$
|
1,083.50
|
|
Average annual use (kilowatt-hour)
|
14,738
|
|
14,304
|
|
13,197
|
|
|||
Average price per kilowatt-hour (cents)
|
$
|
9.51
|
|
$
|
9.37
|
|
$
|
8.21
|
|
•
|
Fee-based arrangements
. Under these arrangements, Enogex generally is paid a fixed fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through Enogex's system and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in Enogex's fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. At
December 31, 2011
, these arrangements accounted for
31 percent
of Enogex's natural gas processed volumes.
|
•
|
Percent-of-proceeds and percent-of-liquids arrangements
. Under these arrangements, Enogex generally gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system, processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which Enogex shares in specified percentages of the
|
•
|
Keep-whole arrangements
. Enogex processes raw natural gas to extract NGLs and returns to the producer the full gas equivalent British thermal unit value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. Enogex is entitled to retain the processed NGLs and to sell them for its own account. Accordingly, Enogex's margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent of those NGLs. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of Enogex's keep-whole contracts include provisions that reduce its commodity price exposure, including conditioning floors (such as the default processing fee described below) that allow the keep-whole contract to be charged a fee if the NGLs have a lower value than their gas equivalent British thermal unit value in natural gas. At
December 31, 2011
, these arrangements accounted for
25 percent
of Enogex's natural gas processed volumes.
|
(In millions)
|
2012
|
2013
|
2014
|
2015
|
2016
|
||||||||||
OG&E Base Transmission
|
$
|
80
|
|
$
|
50
|
|
$
|
50
|
|
$
|
50
|
|
$
|
50
|
|
OG&E Base Distribution
|
195
|
|
200
|
|
200
|
|
200
|
|
200
|
|
|||||
OG&E Base Generation
|
110
|
|
80
|
|
80
|
|
80
|
|
80
|
|
|||||
OG&E Other
|
30
|
|
30
|
|
30
|
|
30
|
|
30
|
|
|||||
Total OG&E Base Transmission, Distribution, Generation and Other
|
415
|
|
360
|
|
360
|
|
360
|
|
360
|
|
|||||
OG&E Known and Committed Projects:
|
|
|
|
|
|
||||||||||
Transmission Projects:
|
|
|
|
|
|
||||||||||
Sunnyside-Hugo (345 kilovolt)
|
25
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
Sooner-Rose Hill (345 kilovolt)
|
5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
Balanced Portfolio 3E Projects
|
110
|
|
180
|
|
50
|
|
—
|
|
—
|
|
|||||
SPP Priority Projects
|
20
|
|
200
|
|
115
|
|
—
|
|
—
|
|
|||||
Total Transmission Projects
|
160
|
|
380
|
|
165
|
|
—
|
|
—
|
|
|||||
Other Projects:
|
|
|
|
|
|
||||||||||
Smart Grid Program (A)
|
90
|
|
35
|
|
40
|
|
20
|
|
20
|
|
|||||
Crossroads
|
40
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
System Hardening
|
15
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
Total Other Projects
|
145
|
|
35
|
|
40
|
|
20
|
|
20
|
|
|||||
Total OG&E Known and Committed Projects
|
305
|
|
415
|
|
205
|
|
20
|
|
20
|
|
|||||
Total OG&E (B)
|
720
|
|
775
|
|
565
|
|
380
|
|
380
|
|
|||||
Enogex LLC Base Maintenance
|
60
|
|
50
|
|
55
|
|
60
|
|
65
|
|
|||||
Enogex LLC Known and Committed Projects:
|
|
|
|
|
|
||||||||||
Western Oklahoma / Texas Panhandle Gathering Expansion
|
215
|
|
115
|
|
15
|
|
5
|
|
5
|
|
|||||
Other Gathering Expansion
|
25
|
|
25
|
|
20
|
|
20
|
|
20
|
|
|||||
Total Enogex LLC Known and Committed Projects
|
240
|
|
140
|
|
35
|
|
25
|
|
25
|
|
|||||
Total Enogex LLC (C)
|
300
|
|
190
|
|
90
|
|
85
|
|
90
|
|
|||||
OGE Energy
|
20
|
|
20
|
|
20
|
|
20
|
|
20
|
|
|||||
Total capital expenditures
|
$
|
1,040
|
|
$
|
985
|
|
$
|
675
|
|
$
|
485
|
|
$
|
490
|
|
(A)
|
These capital expenditures are net of the
$130 million
Smart Grid grant approved by the U.S. Department of Energy.
|
(B)
|
The capital expenditures above exclude any environmental expenditures associated with pollution control equipment related to regional haze requirements due to the uncertainty regarding the timing and costs for such pollution control equipment. OG&E has committed to install low NOX burners at the affected generating units at a cost preliminarily estimated between $70 million and $130 million, but the timing of the installation of such burners is uncertain. The SO2 emissions standards in the EPA's Federal implementation plan could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. The Federal implementation plan is being challenged by OG&E and the state of Oklahoma. Neither the outcome of the challenge to the Federal implementation plan nor the timing and amount of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. For further information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" below.
|
(C)
|
These capital expenditures represent
100 percent
of Enogex LLC's capital expenditures, of which a portion may be funded by the ArcLight group.
Until the ArcLight group owns
50 percent
of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest. If necessary, the ArcLight group will fund between
50 percent
and
90 percent
of required capital contributions during that period. The remainder of the required capital contributions (i.e., between
10 percent
and
50 percent
)
will be funded by OGE Holdings.
|
Name
|
Age
|
Title
|
Peter B. Delaney
|
58
|
Chairman of the Board, President and Chief Executive Officer - OGE Energy Corp.
|
Sean Trauschke
|
44
|
Vice President and Chief Financial Officer - OGE Energy Corp.
|
E. Keith Mitchell
|
49
|
President and Chief Operating Officer - Enogex Holdings
|
Stephen E. Merrill
|
47
|
Chief Operating Officer of Enogex LLC
|
William J. Bullard
|
63
|
Assistant General Counsel - OGE Energy Corp.
|
Scott Forbes
|
54
|
Controller and Chief Accounting Officer - OGE Energy Corp.
|
Patricia D. Horn
|
53
|
Vice President - Governance, Environmental, Health & Safety; Corporate Secretary - OGE Energy Corp.
|
Gary D. Huneryager
|
61
|
Vice President - Internal Audits - OGE Energy Corp.
|
Jesse B. Langston
|
49
|
Vice President - Retail Energy - OG&E
|
Jean C. Leger, Jr.
|
53
|
Vice President - Utility Operations - OG&E
|
Cristina F. McQuistion
|
47
|
Vice President - Strategy and Performance Improvement - OGE Energy Corp.
|
Max J. Myers
|
37
|
Treasurer - OGE Energy Corp.
|
Reid V. Nuttall
|
54
|
Vice President - Chief Information Officer - OGE Energy Corp.
|
Jerry A. Peace
|
49
|
Chief Risk Officer - OGE Energy Corp.
|
Paul L. Renfrow
|
55
|
Vice President - Public Affairs and Human Resources - OGE Energy Corp.
|
•
|
identify potential threats to the public or environment, including "high consequence areas" on covered pipeline segments where a leak or rupture could do the most harm;
|
•
|
establish a communication plan that addresses safety concerns raised by the U.S. Department of Transportation and state agencies, including the periodic submission of performance documents to the U.S. Department of Transportation.
|
•
|
Increased prices for fuel and fuel transportation as existing contracts expire;
|
•
|
Facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
|
•
|
Operator error or safety related stoppages;
|
•
|
Disruptions in the delivery of electricity; and
|
•
|
Catastrophic events such as fires, explosions, floods or other similar occurrences.
|
•
|
damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, earthquakes, fires and other natural disasters and acts of terrorism;
|
•
|
inadvertent damage from third parties, including construction, farm and utility equipment;
|
•
|
leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and
|
•
|
fires and explosions.
|
•
|
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
|
•
|
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
|
•
|
our debt levels may limit our flexibility in responding to changing business and economic conditions.
|
|
|
|
|
|
|
2011 Capacity Factor (A)
|
|
Unit Capability (MW)
|
Station Capability (MW)
|
|||
|
|
Year Installed
|
|
Fuel Capability
|
Unit Run Type
|
|
||||||
Station & Unit
|
|
Unit Design Type
|
|
|||||||||
Seminole
|
1
|
1971
|
Steam-Turbine
|
Gas
|
Base Load
|
25.6
|
%
|
|
490
|
|
|
|
|
1GT
|
1971
|
Combustion-Turbine
|
Gas
|
Peaking
|
0.2
|
%
|
(B)
|
16
|
|
|
|
|
2
|
1973
|
Steam-Turbine
|
Gas
|
Base Load
|
29.1
|
%
|
|
499
|
|
|
|
|
3
|
1975
|
Steam-Turbine
|
Gas/Oil
|
Base Load
|
21.7
|
%
|
|
496
|
|
1,501
|
|
Muskogee
|
4
|
1977
|
Steam-Turbine
|
Coal
|
Base Load
|
63.3
|
%
|
|
504
|
|
|
|
|
5
|
1978
|
Steam-Turbine
|
Coal
|
Base Load
|
59.6
|
%
|
|
500
|
|
|
|
|
6
|
1984
|
Steam-Turbine
|
Coal
|
Base Load
|
67.9
|
%
|
|
506
|
|
1,510
|
|
Sooner
|
1
|
1979
|
Steam-Turbine
|
Coal
|
Base Load
|
69.0
|
%
|
|
515
|
|
|
|
|
2
|
1980
|
Steam-Turbine
|
Coal
|
Base Load
|
74.0
|
%
|
|
523
|
|
1,038
|
|
Horseshoe Lake
|
6
|
1958
|
Steam-Turbine
|
Gas/Oil
|
Base Load
|
14.0
|
%
|
|
162
|
|
|
|
|
7
|
1963
|
Combined Cycle
|
Gas/Oil
|
Base Load
|
20.0
|
%
|
|
225
|
|
|
|
|
8
|
1969
|
Steam-Turbine
|
Gas
|
Base Load
|
9.2
|
%
|
|
380
|
|
|
|
|
9
|
2000
|
Combustion-Turbine
|
Gas
|
Peaking
|
5.4
|
%
|
(B)
|
46
|
|
|
|
|
10
|
2000
|
Combustion-Turbine
|
Gas
|
Peaking
|
6.1
|
%
|
(B)
|
46
|
|
859
|
|
Redbud (C)
|
1
|
2003
|
Combined Cycle
|
Gas
|
Base Load
|
41.6
|
%
|
|
147
|
|
|
|
|
2
|
2003
|
Combined Cycle
|
Gas
|
Base Load
|
45.5
|
%
|
|
149
|
|
|
|
|
3
|
2003
|
Combined Cycle
|
Gas
|
Base Load
|
47.8
|
%
|
|
147
|
|
|
|
|
4
|
2003
|
Combined Cycle
|
Gas
|
Base Load
|
44.5
|
%
|
|
146
|
|
589
|
|
Mustang
|
1
|
1950
|
Steam-Turbine
|
Gas
|
Peaking
|
6.5
|
%
|
(B)
|
50
|
|
|
|
|
2
|
1951
|
Steam-Turbine
|
Gas
|
Peaking
|
7.2
|
%
|
(B)
|
50
|
|
|
|
|
3
|
1955
|
Steam-Turbine
|
Gas
|
Base Load
|
23.3
|
%
|
|
109
|
|
|
|
|
4
|
1959
|
Steam-Turbine
|
Gas
|
Base Load
|
22.7
|
%
|
|
250
|
|
|
|
|
5A
|
1971
|
Combustion-Turbine
|
Gas/Jet Fuel
|
Peaking
|
2.4
|
%
|
(B)
|
32
|
|
|
|
|
5B
|
1971
|
Combustion-Turbine
|
Gas/Jet Fuel
|
Peaking
|
2.7
|
%
|
(B)
|
32
|
|
523
|
|
McClain (D)
|
1
|
2001
|
Combined Cycle
|
Gas
|
Base Load
|
70.1
|
%
|
|
353
|
|
353
|
|
Woodward
|
1
|
1963
|
Combustion-Turbine
|
Gas
|
Peaking
|
—
|
%
|
(B)(E)
|
—
|
|
—
|
|
Enid
|
1
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
—
|
%
|
(B)(E)
|
—
|
|
|
|
|
2
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
—
|
%
|
(B)(E)
|
—
|
|
|
|
|
3
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
—
|
%
|
(B)(E)
|
—
|
|
|
|
|
4
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
—
|
%
|
(B)(E)
|
—
|
|
—
|
|
Total Generating Capability (all stations, excluding wind stations)
|
6,373
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
2011 Capacity Factor (A)
|
|
Unit Capability (MW)
|
Station Capability (MW)
|
|||
|
|
Year Installed
|
|
Number of Units
|
Fuel Capability
|
|
||||||
Station
|
|
Location
|
|
|||||||||
Crossroads (F)
|
|
2011
|
Woodward, OK
|
85
|
Wind
|
45.9
|
%
|
|
2.3
|
|
196
|
|
Centennial
|
|
2007
|
Woodward, OK
|
80
|
Wind
|
31.0
|
%
|
|
1.5
|
|
120
|
|
OU Spirit
|
|
2009
|
Woodward, OK
|
44
|
Wind
|
37.8
|
%
|
|
2.3
|
|
101
|
|
Total Generating Capability (wind stations)
|
417
|
|
Processing Plant
|
Year Installed
|
Type of Plant
|
Fuel Capability
|
2011 Average Daily Inlet Volumes (MMcf/d)
|
Inlet Capacity (MMcf/d)
|
Calumet (A)
|
1969
|
Lean Oil
|
Gas/Electric
|
178
|
250
|
South Canadian (A) (B)
|
2011
|
Cryogenic
|
Electric
|
74
|
200
|
Cox City (C) (D)
|
1994
|
Cryogenic
|
Gas/Electric
|
155
|
180
|
Thomas (A)
|
1981
|
Cryogenic
|
Gas
|
132
|
135
|
Clinton (A)
|
2009
|
Cryogenic
|
Electric
|
122
|
120
|
Roger Mills (C)
|
2008
|
Refrigeration
|
Electric
|
29
|
100
|
Canute (C)
|
1996
|
Cryogenic
|
Electric
|
51
|
60
|
Wetumka (A)
|
1983
|
Cryogenic
|
Gas/Electric
|
37
|
60
|
Total
|
778
|
1,105
|
(A)
|
These processing plants are located on property that Enogex owns in fee.
|
(B)
|
This plant was placed into service in December 2011.
|
(C)
|
These processing plants are located on easements or leased property as described above.
|
(D)
|
On December 8, 2010, a fire occurred at Enogex's Cox City natural gas processing plant destroying major components of one of the four processing trains, representing 120 MMcf/d of the total 180 MMcf/d of capacity, at that facility. Gas volumes normally processed at the Cox City plant were diverted to other facilities or bypassed around Enogex's system to accommodate
|
|
Dividend Paid
|
Price
|
|||||||
2012
|
High
|
Low
|
|||||||
First Quarter (through February 10)
|
$
|
0.3925
|
|
$
|
57.54
|
|
$
|
52.34
|
|
2011
|
|
|
|
||||||
First Quarter
|
$
|
0.3750
|
|
$
|
50.61
|
|
$
|
44.69
|
|
Second Quarter
|
0.3750
|
|
53.50
|
|
47.64
|
|
|||
Third Quarter
|
0.3750
|
|
52.15
|
|
40.56
|
|
|||
Fourth Quarter
|
0.3750
|
|
57.17
|
|
45.70
|
|
|||
2010
|
|
|
|
||||||
First Quarter
|
$
|
0.3625
|
|
$
|
39.32
|
|
$
|
34.92
|
|
Second Quarter
|
0.3625
|
|
42.25
|
|
33.87
|
|
|||
Third Quarter
|
0.3625
|
|
41.11
|
|
35.38
|
|
|||
Fourth Quarter
|
0.3625
|
|
46.18
|
|
39.93
|
|
•
|
may not exceed 50 percent of OG&E's net income for a prior 12-month period, after deducting dividends on any preferred stock during the period, if the sum of the capital represented by common stock, premiums on common stock (restricted to premiums on common stock only by Securities and Exchange Commission orders), and surplus accounts is less than 20 percent of capitalization;
|
•
|
may not exceed 75 percent of OG&E's net income for such 12-month period, as adjusted, if this capitalization ratio is 20 percent or more, but less than 25 percent; and
|
•
|
if this capitalization ratio exceeds 25 percent, dividends, distributions or acquisitions may not reduce the ratio to less than 25 percent except to the extent permitted by the provisions described in the above two bullet points.
|
|
|
|
Total Number of Shares Purchased as Part of Publicly Announced Plan
|
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
|
||
|
Total Number of Shares Purchased
|
Average Price Paid Per Share
|
||||
Period
|
||||||
10/1/11 – 10/31/11
|
—
|
$
|
—
|
|
N/A
|
N/A
|
11/1/11 – 11/30/11
|
120,000
|
$
|
51.33
|
|
120,000
|
N/A
|
12/1/11 – 12/31/11
|
—
|
$
|
—
|
|
N/A
|
N/A
|
Year ended December 31
|
2011
|
2010
|
2009
|
2008
|
2007
|
||||||||||
SELECTED FINANCIAL DATA
|
|
|
|
|
|
||||||||||
(In millions, except per share data)
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
||||||||||
Results of Operations Data:
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
3,915.9
|
|
$
|
3,716.9
|
|
$
|
2,869.7
|
|
$
|
4,070.7
|
|
$
|
3,797.6
|
|
Cost of goods sold
|
2,277.9
|
|
2,187.4
|
|
1,557.7
|
|
2,818.0
|
|
2,634.7
|
|
|||||
Gross margin on revenues
|
1,638.0
|
|
1,529.5
|
|
1,312.0
|
|
1,252.7
|
|
1,162.9
|
|
|||||
Operating expenses
|
991.3
|
|
935.6
|
|
820.1
|
|
790.6
|
|
707.6
|
|
|||||
Operating income
|
646.7
|
|
593.9
|
|
491.9
|
|
462.1
|
|
455.3
|
|
|||||
Interest income
|
0.5
|
|
—
|
|
1.4
|
|
6.7
|
|
2.1
|
|
|||||
Allowance for equity funds used during construction
|
20.4
|
|
11.4
|
|
15.1
|
|
—
|
|
—
|
|
|||||
Other income
|
19.3
|
|
13.7
|
|
27.5
|
|
15.4
|
|
17.4
|
|
|||||
Other expense
|
21.7
|
|
17.9
|
|
16.3
|
|
25.6
|
|
22.7
|
|
|||||
Interest expense
|
140.9
|
|
139.7
|
|
137.4
|
|
120.0
|
|
90.2
|
|
|||||
Income tax expense
|
160.7
|
|
161.0
|
|
121.1
|
|
101.2
|
|
116.7
|
|
|||||
Net income
|
363.6
|
|
300.4
|
|
261.1
|
|
237.4
|
|
245.2
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
20.7
|
|
5.1
|
|
2.8
|
|
6.0
|
|
1.0
|
|
|||||
Net income attributable to OGE Energy
|
$
|
342.9
|
|
$
|
295.3
|
|
$
|
258.3
|
|
$
|
231.4
|
|
$
|
244.2
|
|
Basic earnings per average common share attributable to OGE Energy common shareholders
|
$
|
3.50
|
|
$
|
3.03
|
|
$
|
2.68
|
|
$
|
2.50
|
|
$
|
2.66
|
|
Diluted earnings per average common share attributable to OGE Energy common shareholders
|
$
|
3.45
|
|
$
|
2.99
|
|
$
|
2.66
|
|
$
|
2.49
|
|
$
|
2.64
|
|
Dividends declared per common share
|
$
|
1.5175
|
|
$
|
1.4625
|
|
$
|
1.4275
|
|
$
|
1.3975
|
|
$
|
1.3675
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
||||||||||
Property, plant and equipment, net
|
$
|
7,474.0
|
|
$
|
6,464.4
|
|
$
|
5,911.6
|
|
$
|
5,249.8
|
|
$
|
4,246.3
|
|
Total assets
|
$
|
8,906.0
|
|
$
|
7,669.1
|
|
$
|
7,266.7
|
|
$
|
6,518.5
|
|
$
|
5,237.8
|
|
Long-term debt
|
$
|
2,737.1
|
|
$
|
2,362.9
|
|
$
|
2,088.9
|
|
$
|
2,161.8
|
|
$
|
1,344.6
|
|
Total stockholders' equity
|
$
|
2,819.3
|
|
$
|
2,400.0
|
|
$
|
2,060.8
|
|
$
|
1,914.0
|
|
$
|
1,691.6
|
|
Capitalization Ratios (A)
|
|
|
|
|
|
||||||||||
Stockholders' equity
|
50.7
|
%
|
50.4
|
%
|
46.4
|
%
|
47.0
|
%
|
55.7
|
%
|
|||||
Long-term debt
|
49.3
|
%
|
49.6
|
%
|
53.6
|
%
|
53.0
|
%
|
44.3
|
%
|
|||||
Ratio of Earnings to Fixed Charges (B)
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
4.12
|
|
4.02
|
|
3.38
|
|
3.55
|
|
4.66
|
|
•
|
an increase in net income at OG&E of
$47.6 million
, or
22.1 percent
, or
$0.47
per diluted share of the Company's common stock,
primarily due to a higher gross margin primarily from warmer weather in OG&E's service territory partially offset by higher other operation and maintenance expense, higher interest expense and higher income tax expense. Income tax expense was higher due to higher pre-tax income which more than offset the effects of
the Medicare Part D subsidy
discussed above;
|
•
|
a decrease in net income at Enogex of
$8.9 million
, or
9.8 percent
, or
$0.09
per diluted share of the Company's common stock, primarily due to higher other operation and maintenance expense and the equity sale of a membership interest in Enogex Holdings to the ArcLight group partially offset by a higher gross margin primarily from increased gathered volumes associated with ongoing expansion projects and higher NGLs prices, the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets, lower interest expense and lower income tax expense related to the Medicare Part D subsidy discussed above; and
|
•
|
an increase in net income at OGE Energy of
$8.9 million
, or
77.4 percent
, or
$0.08
per diluted share of the Company's common stock, primarily due to lower other operation and maintenance expense, a decrease in charitable contributions in
2011
and a higher income tax benefit related to the Medicare Part D subsidy discussed above.
|
•
|
an increase in net income at OG&E of
$15.3 million
or
7.6 percent
, or
$0.12
per diluted share of the Company's common stock,
due to a higher gross margin primarily due to rate increases and riders and warmer weather in OG&E's service territory partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense and higher income tax expense mainly attributable to higher pre-tax income and the elimination of the tax deduction for the Medicare Part D subsidy discussed above
;
|
•
|
an increase in net income at Enogex of
$29.8 million
or
48.6 percent
, or
$0.29
per diluted share of the Company's common stock, due to a higher gross margin primarily due to higher processing spreads, higher NGLs prices, higher natural gas prices and increased volumes partially offset by higher other operation and maintenance expense and higher income tax expense mainly attributable to higher pre-tax income and the elimination of the tax deduction for the Medicare Part D subsidy discussed above; and
|
•
|
an increase in the net loss at OGE Energy of
$8.1 million
, or
$0.08
per diluted share of the Company's common stock, due to higher other expense primarily attributable to an increase in charitable contributions to OGE Energy's charitable giving foundation in
2010
and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy discussed above partially offset by lower interest expense primarily due to lower average commercial paper borrowings and a lower average interest rate in
2010
.
|
•
|
Total Enogex anticipated gross margin of between
$500 million
and
$515 million
. The gross margin assumption includes:
|
•
|
Transportation, storage and marketing gross margin contribution of between
$140 million
and
$155 million
, of which
80 percent
is attributable to the transportation business;
|
•
|
Gathering and processing gross margin contribution of between
$355 million
and
$365 million
, of which
62 percent
is attributable to the processing business;
|
•
|
Key factors affecting the gathering and processing gross margin forecast are:
|
•
|
Assumed increase of
six
to
10 percent
in gathered volumes over
2011
;
|
•
|
Assumed increase of approximately
15 percent
in processable* volumes over
2011
;
|
•
|
At the midpoint of Enogex's gathering and processing assumption Enogex has assumed:
|
•
|
Processing contract mix of
42 percent
fixed-fee,
25 percent
percent-of-liquids,
17 percent
percent-of-proceeds and
16 percent
keep-whole;
|
•
|
Weighted average natural gas price of
$2.70
per MMBtu in
2012
;
|
•
|
Realized weighted average NGLs price of
$1.04
per gallon in
2012
; and
|
•
|
Average price per gallon of condensate of
$2.12
in
2012
;
|
•
|
Enogex has assumed operating expenses of
$295 million
to
$305 million
, with operation and maintenance expenses comprising
58 percent
of the total;
|
•
|
Interest expense of
$31 million
to
$33 million
;
|
•
|
An effective tax rate of
38 percent
; and
|
•
|
ArcLight group will own approximately
19 percent
of Enogex Holdings by the end of
2012
.
|
•
|
Assumed increase of
10
to
15 percent
in gathered volumes over 2012; and
|
•
|
Assumed increase of approximately
15 percent
in processable* volumes over 2012.
|
Year ended December 31
(In millions except per share data)
|
2011
|
2010
|
2009
|
||||||
Operating income
|
$
|
646.7
|
|
$
|
593.9
|
|
$
|
491.9
|
|
Net income attributable to OGE Energy
|
$
|
342.9
|
|
$
|
295.3
|
|
$
|
258.3
|
|
Basic average common shares outstanding
|
97.9
|
|
97.3
|
|
96.2
|
|
|||
Diluted average common shares outstanding
|
99.2
|
|
98.9
|
|
97.2
|
|
|||
Basic earnings per average common share attributable to OGE Energy common shareholders
|
$
|
3.50
|
|
$
|
3.03
|
|
$
|
2.68
|
|
Diluted earnings per average common share attributable to OGE Energy common shareholders
|
$
|
3.45
|
|
$
|
2.99
|
|
$
|
2.66
|
|
Dividends declared per common share
|
$
|
1.5175
|
|
$
|
1.4625
|
|
$
|
1.4275
|
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
OG&E (Electric Utility)
|
$
|
472.3
|
|
$
|
413.7
|
|
$
|
354.1
|
|
Enogex (Natural Gas Midstream Operations)
|
|
|
|
||||||
Transportation and storage
|
74.4
|
|
72.6
|
|
85.7
|
|
|||
Gathering and processing
|
118.7
|
|
123.9
|
|
60.2
|
|
|||
Marketing
|
(18.1
|
)
|
(15.0
|
)
|
(7.5
|
)
|
|||
Other Operations (A)
|
(0.6
|
)
|
(1.3
|
)
|
(0.6
|
)
|
|||
Consolidated operating income
|
$
|
646.7
|
|
$
|
593.9
|
|
$
|
491.9
|
|
(A)
|
Other Operations primarily includes the operations of the holding company and consolidating eliminations.
|
Year ended December 31
(Dollars in millions)
|
2011
|
2010
|
2009
|
||||||
Operating revenues
|
$
|
2,211.5
|
|
$
|
2,109.9
|
|
$
|
1,751.2
|
|
Cost of goods sold
|
1,013.5
|
|
1,000.2
|
|
796.3
|
|
|||
Gross margin on revenues
|
1,198.0
|
|
1,109.7
|
|
954.9
|
|
|||
Other operation and maintenance
|
436.0
|
|
418.1
|
|
348.0
|
|
|||
Depreciation and amortization
|
216.1
|
|
208.7
|
|
187.4
|
|
|||
Impairment of assets
|
—
|
|
—
|
|
0.3
|
|
|||
Taxes other than income
|
73.6
|
|
69.2
|
|
65.1
|
|
|||
Operating income
|
472.3
|
|
413.7
|
|
354.1
|
|
|||
Interest income
|
0.5
|
|
0.1
|
|
1.1
|
|
|||
Allowance for equity funds used during construction
|
20.4
|
|
11.4
|
|
15.1
|
|
|||
Other income
|
8.0
|
|
6.5
|
|
20.4
|
|
|||
Other expense
|
8.4
|
|
1.6
|
|
6.7
|
|
|||
Interest expense
|
111.6
|
|
103.4
|
|
93.6
|
|
|||
Income tax expense
|
117.9
|
|
111.0
|
|
90.0
|
|
|||
Net income
|
$
|
263.3
|
|
$
|
215.7
|
|
$
|
200.4
|
|
Operating revenues by classification
|
|
|
|
||||||
Residential
|
$
|
943.5
|
|
$
|
894.8
|
|
$
|
717.9
|
|
Commercial
|
531.3
|
|
521.0
|
|
439.8
|
|
|||
Industrial
|
216.0
|
|
212.5
|
|
172.1
|
|
|||
Oilfield
|
165.1
|
|
162.8
|
|
132.6
|
|
|||
Public authorities and street light
|
207.4
|
|
200.8
|
|
167.7
|
|
|||
Sales for resale
|
65.3
|
|
65.8
|
|
53.6
|
|
|||
Provision for rate refund
|
—
|
|
—
|
|
(0.6
|
)
|
|||
System sales revenues
|
2,128.6
|
|
2,057.7
|
|
1,683.1
|
|
|||
Off-system sales revenues
|
36.2
|
|
21.7
|
|
31.8
|
|
|||
Other
|
46.7
|
|
30.5
|
|
36.3
|
|
|||
Total operating revenues
|
$
|
2,211.5
|
|
$
|
2,109.9
|
|
$
|
1,751.2
|
|
MWH sales by classification
(In millions)
|
|
|
|
||||||
Residential
|
9.9
|
|
9.6
|
|
8.7
|
|
|||
Commercial
|
6.9
|
|
6.7
|
|
6.4
|
|
|||
Industrial
|
3.9
|
|
3.8
|
|
3.6
|
|
|||
Oilfield
|
3.2
|
|
3.1
|
|
2.9
|
|
|||
Public authorities and street light
|
3.2
|
|
3.0
|
|
3.0
|
|
|||
Sales for resale
|
1.4
|
|
1.4
|
|
1.3
|
|
|||
System sales
|
28.5
|
|
27.6
|
|
25.9
|
|
|||
Off-system sales
|
1.0
|
|
0.5
|
|
1.0
|
|
|||
Total sales
|
29.5
|
|
28.1
|
|
26.9
|
|
|||
Number of customers
|
789,146
|
|
782,558
|
|
776,550
|
|
|||
Weighted-average cost of energy per kilowatt-hour - cents
|
|
|
|
||||||
Natural gas
|
4.328
|
|
4.638
|
|
3.696
|
|
|||
Coal
|
2.064
|
|
1.911
|
|
1.747
|
|
|||
Total fuel
|
2.897
|
|
3.012
|
|
2.474
|
|
|||
Total fuel and purchased power
|
3.215
|
|
3.309
|
|
2.760
|
|
|||
Degree days (A)
|
|
|
|
||||||
Heating - Actual
|
3,359
|
|
3,528
|
|
3,456
|
|
|||
Heating - Normal
|
3,631
|
|
3,631
|
|
3,631
|
|
|||
Cooling - Actual
|
2,776
|
|
2,328
|
|
1,860
|
|
|||
Cooling - Normal
|
1,911
|
|
1,911
|
|
1,911
|
|
(A)
|
Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.
|
•
|
warmer weather in OG&E's service territory, which increased the gross margin by
$27.4 million
;
|
•
|
increased price variance, which included revenues from various rate riders, including the Windspeed transmission line rider, the Oklahoma demand program rider, the Smart Grid rider, the system hardening rider, the Oklahoma storm recovery rider, the Crossroads rider and the OU Spirit rider, and higher revenues from sales and customer mix, which increased the gross margin by
$23.9 million
;
|
•
|
higher transmission revenue primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction, which increased the gross margin by
$15.3 million
;
|
•
|
new customer growth in OG&E's service territory, which increased the gross margin by
$13.1 million
;
|
•
|
revenues from the Arkansas rate increase, which increased the gross margin by
$6.0 million
;
|
•
|
higher demand and related revenues by non-residential customers in OG&E's service territory, which increased the gross margin by
$5.0 million
;
and
|
•
|
higher revenues related to the renewal of the Arkansas Valley Electric Cooperative contract (see Note
17
of Notes to
Consolidated
Financial Statements), which increased the gross margin by
$3.1 million
.
|
•
|
an increase of
$15.5 million
allocated from the holding company primarily related to payroll and benefits expense, contract technical and construction services and contract professional services;
|
•
|
an increase of
$12.1 million
in salaries and wages expense primarily due to salary increases in
2011
,
increased incentive compensation expense and increased overtime expense primarily due to storms in April and August 2011
;
|
•
|
an increase of
$4.6 million
in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;
|
•
|
an increase of
$3.1 million
in uncollectible expense;
|
•
|
an increase of
$1.6 million
in fleet transportation expense primarily due to higher fuel costs in
2011
;
|
•
|
an increase of
$1.3 million
in temporary labor expense; and
|
•
|
an increase of
$1.2 million
in SPP administration fees.
|
•
|
a decrease of
$9.8 million
in employee benefits expense primarily due to a decrease in postretirement benefits expense related to amendments to
the Company's
retiree medical plan adopted in January 2011 (see Note
14
of Notes to
Consolidated
Financial Statements) partially offset by a modification to OG&E's pension tracker and a decrease in worker's compensation accruals in
2011
;
|
•
|
a decrease of
$5.0 million
in injuries and damages expense primarily due to higher reserves on claims in
2010
;
and
|
•
|
a decrease of
$2.9 million
related to decreased spending on vegetation management partially related to system hardening, which expenses are being recovered through a rider.
|
•
|
a
$4.9 million
decrease in interest expense due to a higher allowance for borrowed funds used during construction primarily due to construction costs for Crossroads; and
|
•
|
a
$1.4 million
decrease in interest expense in
2011
due to interest to customers related to the fuel over recovery balance in
2010
.
|
•
|
the one-time, non-cash charge in
2010
for the elimination of the tax deduction for the Medicare Part D subsidy;
|
•
|
the write-off of previously recognized Oklahoma investment tax credits in
2010
primarily due to expenditures no longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures; and
|
•
|
higher Oklahoma investment tax credits in
2011
as compared to
2010
.
|
•
|
increased price variance, which included revenues from various rate riders, including the Windspeed rider, the OU Spirit rider, the Oklahoma demand program rider and the Smart Grid rider, and higher revenues from the sales and customer mix, which increased the gross margin by $74.5 million;
|
•
|
warmer weather in OG&E's service territory resulting in a 25 percent increase in cooling degree days, which increased the gross margin by $46.8 million;
|
•
|
revenue from the full year effect of the August 2009 Oklahoma rate increase, which increased the gross margin by $24.1 million;
|
•
|
higher demand and related revenues by non-residential customers in OG&E's service territory, which increased the gross margin by $6.9 million;
|
•
|
new customer growth in OG&E's service territory, which increased the gross margin by $6.7 million; and
|
•
|
revenues from the full year effect of the June 2009 Arkansas rate increase, which increased the gross margin by $3.5 million.
|
•
|
an increase of $16.2 million in contract technical and construction services and an increase of $5.2 million in materials and supplies expense primarily attributable to increased spending for ongoing maintenance at some of OG&E's power plants in 2010 as compared to 2009;
|
•
|
an increase of $16.2 million in employee benefits expense primarily due to an increase in postretirement benefits due to an increase in medical costs and changes in actuarial assumptions in 2010, a reclassification in May 2009 of 2006 and 2007 pension settlement costs to a regulatory asset, as prescribed in the Arkansas rate case settlement, and an increase in pension expense due to an increase in the amount deferred as a pension regulatory liability in OG&E's Oklahoma jurisdiction resulting from OG&E's 2009 Oklahoma rate case;
|
•
|
an increase of $9.7 million in allocations from the holding company primarily due to higher contract professional services expense, materials and supplies expense and communication and media services expense;
|
•
|
an increase of $9.1 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;
|
•
|
an increase of $7.5 million in salaries and wages expense primarily due to salary increases in 2010;
|
•
|
an increase of $4.8 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider;
|
•
|
an increase of $3.4 million in injuries and damages expense primarily due to increased reserves on claims in 2010;
|
•
|
an increase of $1.7 million in temporary labor expense.
|
•
|
a decrease of $10.0 million due to a decreased level of gains recognized in the guaranteed flat bill program in 2010 from higher than expected usage resulting from warmer weather in addition to more customers participating in the guaranteed flat bill program in 2010; and
|
•
|
a decrease of $2.6 million related to the benefit associated with the tax gross-up of allowance for equity funds used during construction.
|
•
|
an $8.2 million increase related to the issuance of $250 million of long-term debt in June 2010; and
|
•
|
a $2.8 million increase due to a lower allowance for borrowed funds used during construction in 2010 as compared to 2009.
|
•
|
higher pre-tax income in 2010 as compared to 2009;
|
•
|
an adjustment for the elimination of the tax deduction for the Medicare Part D subsidy; and
|
•
|
the write-off of previously recognized Oklahoma investment tax credits primarily due to expenditures no longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures.
|
Year ended December 31, 2011
|
Transportation and Storage
|
Gathering and Processing
|
Marketing
|
Eliminations
|
Total
|
||||||||||
(In millions)
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
410.5
|
|
$
|
1,167.1
|
|
$
|
678.0
|
|
$
|
(468.5
|
)
|
$
|
1,787.1
|
|
Cost of goods sold
|
253.3
|
|
870.7
|
|
688.1
|
|
(465.5
|
)
|
1,346.6
|
|
|||||
Gross margin on revenues
|
157.2
|
|
296.4
|
|
(10.1
|
)
|
(3.0
|
)
|
440.5
|
|
|||||
Other operation and maintenance
|
46.5
|
|
111.8
|
|
7.3
|
|
(3.1
|
)
|
162.5
|
|
|||||
Depreciation and amortization
|
21.6
|
|
55.6
|
|
0.4
|
|
—
|
|
77.6
|
|
|||||
Impairment of assets
|
—
|
|
6.3
|
|
—
|
|
—
|
|
6.3
|
|
|||||
Gain on insurance proceeds
|
—
|
|
(3.0
|
)
|
—
|
|
—
|
|
(3.0
|
)
|
|||||
Taxes other than income
|
14.7
|
|
7.0
|
|
0.3
|
|
0.1
|
|
22.1
|
|
|||||
Operating income (loss)
|
$
|
74.4
|
|
$
|
118.7
|
|
$
|
(18.1
|
)
|
$
|
—
|
|
$
|
175.0
|
|
Year ended December 31, 2010
|
Transportation and Storage
|
Gathering and Processing
|
Marketing
|
Eliminations
|
Total
|
||||||||||
(In millions)
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
403.6
|
|
$
|
1,005.6
|
|
$
|
798.5
|
|
$
|
(500.0
|
)
|
$
|
1,707.7
|
|
Cost of goods sold
|
246.4
|
|
733.3
|
|
804.7
|
|
(499.3
|
)
|
1,285.1
|
|
|||||
Gross margin on revenues
|
157.2
|
|
272.3
|
|
(6.2
|
)
|
(0.7
|
)
|
422.6
|
|
|||||
Other operation and maintenance
|
48.9
|
|
91.5
|
|
8.4
|
|
(3.5
|
)
|
145.3
|
|
|||||
Depreciation and amortization
|
21.1
|
|
50.1
|
|
0.1
|
|
—
|
|
71.3
|
|
|||||
Impairment of assets
|
0.7
|
|
0.4
|
|
—
|
|
—
|
|
1.1
|
|
|||||
Taxes other than income
|
13.9
|
|
6.4
|
|
0.3
|
|
—
|
|
20.6
|
|
|||||
Operating income (loss)
|
$
|
72.6
|
|
$
|
123.9
|
|
$
|
(15.0
|
)
|
$
|
2.8
|
|
$
|
184.3
|
|
Year ended December 31, 2009
|
Transportation and Storage
|
Gathering and Processing
|
Marketing
|
Eliminations
|
Total
|
||||||||||
(In millions)
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
401.0
|
|
$
|
657.5
|
|
$
|
619.9
|
|
$
|
(473.3
|
)
|
$
|
1,205.1
|
|
Cost of goods sold
|
239.9
|
|
458.8
|
|
617.7
|
|
(468.9
|
)
|
847.5
|
|
|||||
Gross margin on revenues
|
161.1
|
|
198.7
|
|
2.2
|
|
(4.4
|
)
|
357.6
|
|
|||||
Other operation and maintenance
|
40.9
|
|
87.2
|
|
9.2
|
|
(4.7
|
)
|
132.6
|
|
|||||
Depreciation and amortization
|
20.4
|
|
43.9
|
|
0.1
|
|
—
|
|
64.4
|
|
|||||
Impairment of assets
|
0.9
|
|
1.9
|
|
—
|
|
—
|
|
2.8
|
|
|||||
Taxes other than income
|
13.2
|
|
5.5
|
|
0.4
|
|
—
|
|
19.1
|
|
|||||
Operating income (loss)
|
$
|
85.7
|
|
$
|
60.2
|
|
$
|
(7.5
|
)
|
$
|
0.3
|
|
$
|
138.7
|
|
Year ended December 31
|
2011
|
2010
|
2009
|
||||||
Gathered volumes – TBtu/d
|
1.36
|
|
1.32
|
|
1.25
|
|
|||
Incremental transportation volumes – TBtu/d (A)
|
0.58
|
|
0.40
|
|
0.54
|
|
|||
Total throughput volumes – TBtu/d
|
1.94
|
|
1.72
|
|
1.79
|
|
|||
Natural gas processed – TBtu/d
|
0.79
|
|
0.82
|
|
0.70
|
|
|||
NGLs sold (keep-whole) – million gallons
|
167
|
|
187
|
|
110
|
|
|||
NGLs sold (purchased for resale) – million gallons
|
487
|
|
470
|
|
351
|
|
|||
NGLs sold (percent-of-liquids) – million gallons
|
25
|
|
26
|
|
27
|
|
|||
NGLs sold (percent-of-proceeds) – million gallons
|
6
|
|
5
|
|
5
|
|
|||
Total NGLs sold – million gallons
|
685
|
|
688
|
|
493
|
|
|||
Average NGLs sales price per gallon
|
$
|
1.16
|
|
$
|
0.96
|
|
$
|
0.77
|
|
Average natural gas sales price per MMBtu
|
$
|
4.08
|
|
$
|
4.24
|
|
$
|
3.37
|
|
(A)
|
Incremental transportation volumes consist of natural gas moved only on the transportation pipeline.
|
•
|
increased payroll and benefits costs due to increased headcount to support business growth;
|
•
|
increased contract technical and professional services expense and materials and supplies expense due to an increase in non-capital projects in
2011
;
|
•
|
increased property insurance costs;
|
•
|
increased rental expense due to growing demand for compression as Enogex's business expands; and
|
•
|
increased costs due to soil remediation projects.
|
•
|
higher capacity lease services under the MEP and Gulf Crossing capacity leases in
2011
as a result of pipeline integrity work on an Enogex pipeline in
2010
, which increased the gross margin by
$7.1 million
;
|
•
|
higher firm 311 services due to new contracts with more favorable rates in
2011
, which increased the gross margin by
$5.4 million
;
|
•
|
higher interruptible transportation fees due to new contracts with more favorable rates in
2011
, which increased the gross margin by
$1.6 million
; and
|
•
|
higher crosshaul revenues in
2011
resulting from the reversal of a previously recognized reserve of
$3.0 million
associated with the settlement of Enogex's 2009 FERC Section 311 rate case partially offset by decreased utilization of
$2.5 million
in
2011
due to shippers utilizing crosshaul service in
2010
as a result of pipeline integrity work, which increased the
2011
gross margin by
$0.5 million
; and
|
•
|
lower volumes and realized margin on sales of physical natural gas long positions associated with transportation operations in
2011
. Gross margin in
2011
included the under recovery of fuel positions as compared to
2010
that included the recovery of prior year's under-recovered fuel positions, which reduced the gross margin in
2011
by
$12.1 million
, net of imbalance and fuel tracker obligations.
|
•
|
an increase in condensate revenues associated with higher condensate prices and volumes, which increased the gross margin by
$11.1 million
; and
|
•
|
an increase in gathering fees associated with ongoing expansion projects, which increased the gross margin by
$10.7 million
.
|
•
|
an increase in the utilization of third-party processing as a result of the reduced capacity related to the Cox City processing plant being out of service until September
2011
and the Atoka processing plant being taken out of service in August 2011, which decreased the gross margin by
$3.4 million
; and
|
•
|
lower volumes and realized margin on sales of physical natural gas long positions associated with gathering operations, which decreased the gross margin in
2011
by
$2.7 million
, net of imbalance and fuel tracker obligations.
|
•
|
increased payroll and benefits costs due to increased headcount to support business growth;
|
•
|
increased contract technical and professional services expense and materials and supplies expense due to an increase in non-capital projects in
2011
;
|
•
|
increased rental expense due to growing demand for compression as Enogex's business expands; and
|
•
|
increased costs due to soil remediation projects.
|
•
|
lower of cost or market adjustments on the natural gas storage inventory reflective of higher inventory volumes in
2011
, which decreased the gross margin by
$3.6 million
; and
|
•
|
lower realized margin on sale of natural gas inventory from storage due to a reduction in the realized natural gas market spreads, which decreased the gross margin by
$2.8 million
.
|
•
|
an increase of
$6.1 million
in capitalized interest related to increased construction activity in
2011
; and
|
•
|
a decrease of
$1.0 million
in interest expense in
2011
due to the retirement of long-term debt in January 2010.
|
•
|
lower pre-tax income in
2011
as compared to
2010
; and
|
•
|
the one-time, non-cash charge in
2010
for the elimination of the tax deduction for the Medicare Part D subsidy.
|
•
|
lower revenues resulting from refunds associated with lease services under the MEP and Gulf Crossing capacity leases and the firm 311 services due to pipeline integrity work, which decreased the gross margin by $9.2 million;
|
•
|
lower crosshaul volumes as fewer customers moved natural gas to eastern markets in 2010 as there were smaller differences in natural gas prices at various U.S. market locations partially offset by customers utilizing crosshaul services due to pipeline integrity work on an Enogex pipeline, which decreased the gross margin by $5.7 million;
|
•
|
lower realized margins on operational storage hedges as the result of lower transacted volumes in 2010 as compared to 2009, which decreased the gross margin by $2.3 million;
|
•
|
lower storage fees due to a reduction in the market value of storage capacity, which decreased the gross margin by $2.0 million; and
|
•
|
decreased interruptible transportation revenues due to gathering customers shipping production through the firm capacity leases and firm 311 East side service, which decreased the gross margin by $1.6 million.
|
•
|
lease services under the MEP and Gulf Crossing capacity leases and firm 311 services due to these services being available beginning in the second quarter 2009, which increased the gross margin by $9.0 million;
|
•
|
no adjustment of natural gas storage inventory in 2010 as compared to $5.8 million lower of cost or market adjustment to the natural gas storage inventory in 2009 due to lower natural gas prices;
|
•
|
a decrease in the imbalance liability, net of fuel recoveries and natural gas length positions, which increased the gross margin by $1.2 million; and
|
•
|
higher transportation demand fees due to new contracts which began in 2010, which increased the gross margin by $1.1 million.
|
•
|
increased gross margin on keep-whole processing of $35.8 million;
|
•
|
increased fixed processing fees of $13.8 million; and
|
•
|
increased gross margin on NGLs retained under percent-of-liquids contracts of $11.4 million.
|
•
|
an increase in condensate revenues associated with the gathering and processing operations as a result of increased volumes associated with new expansion projects with a higher gallons per million cubic foot of natural gas and higher condensate prices, which increased the gross margin by $11.6 million; and
|
•
|
increased gathered volumes associated with expansion projects, which increased the gross margin by $4.3 million.
|
•
|
lower volumes and realized margin on sales of physical natural gas long/short positions associated with gathering operations, which decreased the gross margin by $1.3 million, net of imbalance and fuel tracker obligations; and
|
•
|
increased processing fees associated with the increased utilization of a third-party processing plant for processing natural gas associated with Atoka, which decreased the gross margin by $1.2 million.
|
•
|
smaller differences in natural gas prices at various U.S. market locations which resulted in a reduced spread that OER was able to realize from delivering gas under its transportation contracts, which decreased the gross margin by $5.5 million;
|
•
|
timing of the withdrawal and sale of natural gas inventory from OER's storage contracts, which decreased the gross margin by $1.9 million; and
|
•
|
selective deal execution to limit credit and commodity price risks in the current market environment, as well as lack of spreads and volatility in the natural gas commodity markets, resulted in limited opportunities for OER in its customer-focused risk management services and natural gas marketing activities, which decreased the gross margin by $1.0 million.
|
•
|
a decrease of $7.0 million in interest expense in 2010 as compared to 2009 due to a lower interest rate on long-term debt issued in 2009 as compared to the interest rate on long-term debt that was retired in January 2010; and
|
•
|
a $2.8 million tender payment on the tender offer Enogex completed in July 2009 related to the retirement of $110.8 million of senior notes.
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Net cash provided from operating activities
|
$
|
833.9
|
|
$
|
782.5
|
|
$
|
654.5
|
|
Net cash used in investing activities
|
(1,395.8
|
)
|
(846.1
|
)
|
(808.5
|
)
|
|||
Net cash provided from financing activities
|
564.2
|
|
7.8
|
|
37.7
|
|
•
|
an increase in cash receipts for sales at Enogex due to an increase in natural gas prices and NGLs prices and volumes in
2010
as compared to
2009
;
|
•
|
income tax refunds received in
2010
related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repair expenditures and accelerated tax bonus depreciation;
|
•
|
a cash collateral payment to counterparties of OER related to OER's NGLs hedge positions in
2009
; and
|
•
|
cash received in
2010
from the implementation of rate increases and riders at OG&E.
|
•
|
an increase in payments for purchases at Enogex due to an increase in natural gas prices and NGLs prices and volumes in
2010
as compared to
2009
; and
|
•
|
higher fuel refunds at OG&E in
2010
as compared to
2009
.
|
•
|
repayment in
2010
of the remaining balance of Enogex LLC's $400 million 8.125% senior notes which matured on January 15, 2010;
|
•
|
an increase in short-term debt borrowings in
2011
as compared to
2010
;
|
•
|
contributions from the noncontrolling interest partners in
2011
;
|
•
|
higher borrowings under Enogex LLC's revolving credit agreement in 2011; and
|
•
|
a decrease in repayments of borrowings under Enogex LLC's revolving credit agreement in
2011
as compared to
2010
.
|
•
|
repayment of the remaining balance of Enogex LLC's $400 million 8.125% senior notes which matured on January 15, 2010 partially offset by the retirement of $110.8 million of senior notes related to the tender offer Enogex completed in July 2009;
|
•
|
proceeds received from the issuance of $450 million of long-term debt at Enogex LLC in June 2009; and
|
•
|
a decrease in the issuance of common stock in
2010
.
|
•
|
proceeds received from the issuance of $250 million of long-term debt
at OG&E
in June 2010
;
|
•
|
proceeds received from the ArcLight group for the equity investment in Enogex Holdings in November 2010;
|
•
|
lower repayments of short-term debt borrowings in
2010
;
|
•
|
a higher level of proceeds received from borrowings on Enogex LLC's line of credit in
2010
; and
|
•
|
a higher level of repayments made on Enogex LLC's line of credit in
2009
.
|
(In millions)
|
2012
|
2013
|
2014
|
2015
|
2016
|
||||||||||
OG&E Base Transmission
|
$
|
80
|
|
$
|
50
|
|
$
|
50
|
|
$
|
50
|
|
$
|
50
|
|
OG&E Base Distribution
|
195
|
|
200
|
|
200
|
|
200
|
|
200
|
|
|||||
OG&E Base Generation
|
110
|
|
80
|
|
80
|
|
80
|
|
80
|
|
|||||
OG&E Other
|
30
|
|
30
|
|
30
|
|
30
|
|
30
|
|
|||||
Total OG&E Base Transmission, Distribution, Generation and Other
|
415
|
|
360
|
|
360
|
|
360
|
|
360
|
|
|||||
OG&E Known and Committed Projects:
|
|
|
|
|
|
||||||||||
Transmission Projects:
|
|
|
|
|
|
||||||||||
Sunnyside-Hugo (345 kilovolt)
|
25
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
Sooner-Rose Hill (345 kilovolt)
|
5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
Balanced Portfolio 3E Projects
|
110
|
|
180
|
|
50
|
|
—
|
|
—
|
|
|||||
SPP Priority Projects
|
20
|
|
200
|
|
115
|
|
—
|
|
—
|
|
|||||
Total Transmission Projects
|
160
|
|
380
|
|
165
|
|
—
|
|
—
|
|
|||||
Other Projects:
|
|
|
|
|
|
||||||||||
Smart Grid Program (A)
|
90
|
|
35
|
|
40
|
|
20
|
|
20
|
|
|||||
Crossroads
|
40
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
System Hardening
|
15
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||
Total Other Projects
|
145
|
|
35
|
|
40
|
|
20
|
|
20
|
|
|||||
Total OG&E Known and Committed Projects
|
305
|
|
415
|
|
205
|
|
20
|
|
20
|
|
|||||
Total OG&E (B)
|
720
|
|
775
|
|
565
|
|
380
|
|
380
|
|
|||||
Enogex LLC Base Maintenance
|
60
|
|
50
|
|
55
|
|
60
|
|
65
|
|
|||||
Enogex LLC Known and Committed Projects:
|
|
|
|
|
|
||||||||||
Western Oklahoma / Texas Panhandle Gathering Expansion
|
215
|
|
115
|
|
15
|
|
5
|
|
5
|
|
|||||
Other Gathering Expansion
|
25
|
|
25
|
|
20
|
|
20
|
|
20
|
|
|||||
Total Enogex LLC Known and Committed Projects
|
240
|
|
140
|
|
35
|
|
25
|
|
25
|
|
|||||
Total Enogex LLC (C)
|
300
|
|
190
|
|
90
|
|
85
|
|
90
|
|
|||||
OGE Energy
|
20
|
|
20
|
|
20
|
|
20
|
|
20
|
|
|||||
Total capital expenditures
|
$
|
1,040
|
|
$
|
985
|
|
$
|
675
|
|
$
|
485
|
|
$
|
490
|
|
(A)
|
These capital expenditures are net of the
$130 million
Smart Grid grant approved by the U.S. Department of Energy.
|
(B)
|
The capital expenditures above exclude any environmental expenditures associated with pollution control equipment related to regional haze requirements due to the uncertainty regarding the timing and costs for such pollution control equipment. OG&E has committed to install low NOX burners at the affected generating units at a cost preliminarily estimated between $70 million and $130 million, but the timing of the installation of such burners is uncertain. The SO2 emissions standards in the EPA's Federal implementation plan could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. The Federal implementation plan is being challenged by OG&E and the state of Oklahoma. Neither the outcome of the challenge to the Federal implementation plan nor the timing and amount of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. For further information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" below.
|
(C)
|
These capital expenditures represent
100 percent
of Enogex LLC's capital expenditures, of which a portion may be funded by the ArcLight group.
Until the ArcLight group owns
50 percent
of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest. If necessary, the ArcLight group will fund between
50 percent
and
90 percent
of required capital contributions during that period. The remainder of the required capital contributions (i.e., between
10 percent
and
50 percent
)
will be funded by OGE Holdings.
|
(In millions)
|
2012
|
2013-2014
|
2015-2016
|
After 2016
|
Total
|
||||||||||
Maturities of long-term debt (A)
|
$
|
—
|
|
$
|
300.0
|
|
$
|
260.0
|
|
$
|
2,185.4
|
|
$
|
2,745.4
|
|
Operating lease obligations
|
|
|
|
|
|
||||||||||
OG&E railcars
|
2.9
|
|
5.7
|
|
30.1
|
|
—
|
|
38.7
|
|
|||||
Enogex noncancellable operating leases
|
3.9
|
|
5.4
|
|
4.6
|
|
0.6
|
|
14.5
|
|
|||||
Total operating lease obligations
|
6.8
|
|
11.1
|
|
34.7
|
|
0.6
|
|
53.2
|
|
|||||
Other purchase obligations and commitments
|
|
|
|
|
|
||||||||||
OG&E cogeneration capacity and fixed operation and maintenance payments
|
90.3
|
|
176.7
|
|
168.5
|
|
401.1
|
|
836.6
|
|
|||||
OG&E expected cogeneration energy payments
|
59.3
|
|
150.2
|
|
161.0
|
|
600.8
|
|
971.3
|
|
|||||
OG&E minimum fuel purchase commitments
|
380.2
|
|
280.3
|
|
90.4
|
|
—
|
|
750.9
|
|
|||||
OG&E expected wind purchase commitments
|
32.4
|
|
66.1
|
|
68.7
|
|
492.0
|
|
659.2
|
|
|||||
OG&E long-term service agreement commitments
|
4.5
|
|
40.3
|
|
10.1
|
|
59.8
|
|
114.7
|
|
|||||
OER Cheyenne Plains commitments
|
5.3
|
|
13.0
|
|
1.6
|
|
—
|
|
19.9
|
|
|||||
OER MEP commitments
|
2.1
|
|
3.3
|
|
—
|
|
—
|
|
5.4
|
|
|||||
OER other commitments
|
4.9
|
|
6.2
|
|
3.8
|
|
—
|
|
14.9
|
|
|||||
Total other purchase obligations and commitments
|
579.0
|
|
736.1
|
|
504.1
|
|
1,553.7
|
|
3,372.9
|
|
|||||
Total contractual obligations
|
585.8
|
|
1,047.2
|
|
798.8
|
|
3,739.7
|
|
6,171.5
|
|
|||||
Amounts recoverable through fuel adjustment clause (B)
|
(474.8
|
)
|
(502.3
|
)
|
(350.2
|
)
|
(1,092.8
|
)
|
(2,420.1
|
)
|
|||||
Total contractual obligations, net
|
$
|
111.0
|
|
$
|
544.9
|
|
$
|
448.6
|
|
$
|
2,646.9
|
|
$
|
3,751.4
|
|
(A)
|
Maturities of
the Company's
long-term debt during the next five years consist of
$300 million
and
$260 million
in years
2014
and
2016
,
respectively.
There are
no
maturities of
the Company's
long-term debt in years
2012
,
2013
or
2015
.
|
(B)
|
Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's cogeneration expected energy payments, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.
|
|
Pension Plan
|
Restoration of Retirement
Income Plan |
Postretirement
Benefit Plans |
|||||||||||||||
December 31
(In millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Benefit obligations
|
$
|
(697.7
|
)
|
$
|
(640.9
|
)
|
$
|
(13.3
|
)
|
$
|
(10.8
|
)
|
$
|
(280.6
|
)
|
$
|
(337.1
|
)
|
Fair value of plan assets
|
589.8
|
|
574.0
|
|
—
|
|
—
|
|
61.0
|
|
58.5
|
|
||||||
Funded status at end of year
|
$
|
(107.9
|
)
|
$
|
(66.9
|
)
|
$
|
(13.3
|
)
|
$
|
(10.8
|
)
|
$
|
(219.6
|
)
|
$
|
(278.6
|
)
|
|
Moody’s Investors Services
|
Standard & Poor's Ratings Services
|
Fitch Ratings
|
OG&E Senior Notes
|
A2
|
BBB+
|
A+
|
Enogex LLC Notes
|
Baa3
|
BBB-
|
BBB
|
OGE Energy Senior Notes
|
Baa1
|
BBB
|
A
|
OGE Energy Commercial Paper
|
P2
|
A2
|
F1
|
|
Change
|
Impact on Funded Status
|
Actual plan asset returns
|
+/- 5 percent
|
+/- $29.5 million
|
Discount rate
|
+/- 0.25 percent
|
+/- $20.3 million
|
Contributions
|
+/- $10 million
|
+/- $10 million
|
Year ended December 31
(Dollars in millions)
|
2012
|
2013
|
2014
|
2015
|
2016
|
Thereafter
|
Total
|
12/31/11 Fair Value
|
||||||||||||||||
Fixed-rate debt (A)
|
|
|
|
|
|
|
|
|
||||||||||||||||
Principal amount
|
$
|
—
|
|
$
|
—
|
|
$
|
300.0
|
|
$
|
—
|
|
$
|
110.0
|
|
$
|
2,050.0
|
|
$
|
2,460.0
|
|
$
|
2,990.2
|
|
Weighted-average interest rate
|
—
|
|
—
|
|
6.25
|
%
|
—
|
|
5.15
|
%
|
6.40
|
%
|
6.32
|
%
|
|
|||||||||
Variable-rate debt (B)
|
|
|
|
|
|
|
|
|
||||||||||||||||
Principal amount
|
—
|
|
—
|
|
—
|
|
—
|
|
150.0
|
|
$
|
135.4
|
|
$
|
285.4
|
|
$
|
285.4
|
|
|||||
Weighted-average interest rate
|
—
|
|
—
|
|
—
|
|
—
|
|
1.65
|
%
|
0.22
|
%
|
0.97
|
%
|
|
Year ended December 31
(In millions except per share data)
|
2011
|
2010
|
2009
|
||||||
OPERATING REVENUES
|
|
|
|
||||||
Electric Utility operating revenues
|
$
|
2,211.5
|
|
$
|
2,109.9
|
|
$
|
1,751.2
|
|
Natural Gas Midstream Operations operating revenues
|
1,704.4
|
|
1,607.0
|
|
1,118.5
|
|
|||
Total operating revenues
|
3,915.9
|
|
3,716.9
|
|
2,869.7
|
|
|||
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
|
|
|
|
||||||
Electric Utility cost of goods sold
|
966.0
|
|
952.6
|
|
748.7
|
|
|||
Natural Gas Midstream Operations cost of goods sold
|
1,311.9
|
|
1,234.8
|
|
809.0
|
|
|||
Total cost of goods sold
|
2,277.9
|
|
2,187.4
|
|
1,557.7
|
|
|||
Gross margin on revenues
|
1,638.0
|
|
1,529.5
|
|
1,312.0
|
|
|||
OPERATING EXPENSES
|
|
|
|
||||||
Other operation and maintenance
|
581.2
|
|
549.8
|
|
466.8
|
|
|||
Depreciation and amortization
|
307.1
|
|
291.3
|
|
262.6
|
|
|||
Impairment of assets
|
6.3
|
|
1.1
|
|
3.1
|
|
|||
Gain on insurance proceeds
|
(3.0
|
)
|
—
|
|
—
|
|
|||
Taxes other than income
|
99.7
|
|
93.4
|
|
87.6
|
|
|||
Total operating expenses
|
991.3
|
|
935.6
|
|
820.1
|
|
|||
OPERATING INCOME
|
646.7
|
|
593.9
|
|
491.9
|
|
|||
OTHER INCOME (EXPENSE)
|
|
|
|
||||||
Interest income
|
0.5
|
|
—
|
|
1.4
|
|
|||
Allowance for equity funds used during construction
|
20.4
|
|
11.4
|
|
15.1
|
|
|||
Other income
|
19.3
|
|
13.7
|
|
27.5
|
|
|||
Other expense
|
(21.7
|
)
|
(17.9
|
)
|
(16.3
|
)
|
|||
Net other income
|
18.5
|
|
7.2
|
|
27.7
|
|
|||
INTEREST EXPENSE
|
|
|
|
||||||
Interest on long-term debt
|
146.1
|
|
139.3
|
|
137.3
|
|
|||
Allowance for borrowed funds used during construction
|
(10.4
|
)
|
(5.5
|
)
|
(8.3
|
)
|
|||
Interest on short-term debt and other interest charges
|
5.2
|
|
5.9
|
|
8.4
|
|
|||
Interest expense
|
140.9
|
|
139.7
|
|
137.4
|
|
|||
INCOME BEFORE TAXES
|
524.3
|
|
461.4
|
|
382.2
|
|
|||
INCOME TAX EXPENSE
|
160.7
|
|
161.0
|
|
121.1
|
|
|||
NET INCOME
|
363.6
|
|
300.4
|
|
261.1
|
|
|||
Less: Net income attributable to noncontrolling interests
|
20.7
|
|
5.1
|
|
2.8
|
|
|||
NET INCOME ATTRIBUTABLE TO OGE ENERGY
|
$
|
342.9
|
|
$
|
295.3
|
|
$
|
258.3
|
|
BASIC AVERAGE COMMON SHARES OUTSTANDING
|
97.9
|
|
97.3
|
|
96.2
|
|
|||
DILUTED AVERAGE COMMON SHARES OUTSTANDING
|
99.2
|
|
98.9
|
|
97.2
|
|
|||
BASIC EARNINGS PER AVERAGE COMMON SHARE
|
|
|
|
||||||
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
|
$
|
3.50
|
|
$
|
3.03
|
|
$
|
2.68
|
|
DILUTED EARNINGS PER AVERAGE COMMON SHARE
|
|
|
|
||||||
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
|
$
|
3.45
|
|
$
|
2.99
|
|
$
|
2.66
|
|
DIVIDENDS DECLARED PER COMMON SHARE
|
$
|
1.5175
|
|
$
|
1.4625
|
|
$
|
1.4275
|
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Net income
|
$
|
363.6
|
|
$
|
300.4
|
|
$
|
261.1
|
|
Other comprehensive income (loss), net of tax
|
|
|
|
||||||
Pension Plan and Restoration of Retirement Income Plan:
|
|
|
|
||||||
Amortization of deferred net loss, net of tax of $1.4 million, $1.2 million and $2.0 million, respectively
|
2.5
|
|
1.3
|
|
3.2
|
|
|||
Net gain (loss) arising during the period, net of tax of ($6.7) million, $4.4 million and $0.4 million, respectively
|
(13.5
|
)
|
7.6
|
|
0.6
|
|
|||
Amortization of prior service cost, net of tax of $0.2 million, $0.1 million and $0.1 million, respectively
|
0.4
|
|
0.2
|
|
0.1
|
|
|||
Prior service cost arising during the period, net of tax of $0, $0 and ($0.2) million, respectively
|
—
|
|
—
|
|
(0.3
|
)
|
|||
Postretirement plans:
|
|
|
|
||||||
Amortization of deferred net loss, net of tax of ($1.6) million, $0.6 million and $0.7 million, respectively
|
1.8
|
|
1.2
|
|
0.9
|
|
|||
Net loss arising during the period, net of tax of ($3.1) million, ($2.4) million and ($4.1) million, respectively
|
(3.6
|
)
|
(4.1
|
)
|
(6.3
|
)
|
|||
Amortization of deferred net transition obligation, net of tax of $0.1 million, $0.1 million and $0.1 million, respectively
|
0.2
|
|
0.1
|
|
0.1
|
|
|||
Amortization of prior service cost, net of tax of ($1.6) million, $0.1 million and $0.1 million, respectively
|
(1.8
|
)
|
—
|
|
0.2
|
|
|||
Prior service cost arising during the period, net of tax of $9.5 million, $0 and $0, respectively
|
10.8
|
|
—
|
|
—
|
|
|||
Deferred commodity contracts hedging losses reclassified in net income, net of tax of $12.6 million, $9.9 million and $4.7 million, respectively
|
27.6
|
|
18.5
|
|
7.5
|
|
|||
Deferred commodity contracts hedging gains (losses), net of tax of ($1.7) million, ($8.5) million and ($42.6) million, respectively
|
(4.8
|
)
|
(16.3
|
)
|
(67.3
|
)
|
|||
Deferred interest rate swaps hedging gains, net of tax of $0.2 million, $0.2 million and $0.2 million, respectively
|
0.3
|
|
0.2
|
|
0.3
|
|
|||
Other comprehensive income (loss), net of tax
|
19.9
|
|
8.7
|
|
(61.0
|
)
|
|||
Comprehensive income (loss)
|
383.5
|
|
309.1
|
|
200.1
|
|
|||
Less: Comprehensive income attributable to noncontrolling interest for sale of equity investment
|
(3.2
|
)
|
(6.2
|
)
|
—
|
|
|||
Less: Comprehensive income attributable to noncontrolling interests
|
24.2
|
|
5.5
|
|
2.8
|
|
|||
Total comprehensive income (loss) attributable to OGE Energy
|
$
|
362.5
|
|
$
|
309.8
|
|
$
|
197.3
|
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
||||||
Net income
|
$
|
363.6
|
|
$
|
300.4
|
|
$
|
261.1
|
|
Adjustments to reconcile net income to net cash provided from operating activities
|
|
|
|
||||||
Depreciation and amortization
|
307.1
|
|
291.3
|
|
262.6
|
|
|||
Impairment of assets
|
6.3
|
|
1.1
|
|
3.1
|
|
|||
Deferred income taxes and investment tax credits, net
|
166.0
|
|
146.4
|
|
269.8
|
|
|||
Allowance for equity funds used during construction
|
(20.4
|
)
|
(11.4
|
)
|
(15.1
|
)
|
|||
Gain on disposition and abandonment of assets
|
(2.7
|
)
|
—
|
|
—
|
|
|||
Gain on insurance proceeds
|
(3.0
|
)
|
—
|
|
—
|
|
|||
Stock-based compensation expense
|
7.8
|
|
7.4
|
|
4.1
|
|
|||
Excess tax benefit on stock-based compensation
|
—
|
|
(0.7
|
)
|
(3.3
|
)
|
|||
Price risk management assets
|
(1.7
|
)
|
3.9
|
|
27.8
|
|
|||
Price risk management liabilities
|
19.0
|
|
8.5
|
|
(88.7
|
)
|
|||
Regulatory assets
|
14.0
|
|
24.1
|
|
20.2
|
|
|||
Regulatory liabilities
|
(1.9
|
)
|
(12.4
|
)
|
(17.5
|
)
|
|||
Other assets
|
(7.0
|
)
|
6.3
|
|
(3.5
|
)
|
|||
Other liabilities
|
(37.4
|
)
|
(37.0
|
)
|
(37.7
|
)
|
|||
Change in certain current assets and liabilities
|
|
|
|
||||||
Accounts receivable, net
|
(48.0
|
)
|
11.9
|
|
(3.3
|
)
|
|||
Accrued unbilled revenues
|
(2.5
|
)
|
0.4
|
|
(10.2
|
)
|
|||
Income taxes receivable
|
(3.6
|
)
|
153.0
|
|
(157.7
|
)
|
|||
Fuel, materials and supplies inventories
|
54.2
|
|
(45.2
|
)
|
(36.1
|
)
|
|||
Gas imbalance assets
|
0.7
|
|
0.7
|
|
3.0
|
|
|||
Fuel clause under recoveries
|
(0.8
|
)
|
(0.7
|
)
|
23.7
|
|
|||
Other current assets
|
(7.2
|
)
|
(5.9
|
)
|
(1.4
|
)
|
|||
Accounts payable
|
34.5
|
|
59.2
|
|
(17.2
|
)
|
|||
Gas imbalance liabilities
|
3.1
|
|
(5.3
|
)
|
(12.9
|
)
|
|||
Fuel clause over recoveries
|
(22.2
|
)
|
(157.6
|
)
|
178.9
|
|
|||
Other current liabilities
|
16.0
|
|
44.1
|
|
4.8
|
|
|||
Net Cash Provided from Operating Activities
|
833.9
|
|
782.5
|
|
654.5
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
||||||
Capital expenditures (less allowance for equity funds used during construction)
|
(1,270.4
|
)
|
(879.9
|
)
|
(847.8
|
)
|
|||
Acquisition of gathering assets
|
(200.4
|
)
|
—
|
|
—
|
|
|||
Reimbursement of capital expenditures
|
49.6
|
|
31.5
|
|
38.8
|
|
|||
Proceeds from sale of assets
|
18.0
|
|
2.3
|
|
—
|
|
|||
Proceeds from insurance
|
7.4
|
|
—
|
|
—
|
|
|||
Other investing activities
|
—
|
|
—
|
|
0.5
|
|
|||
Net Cash Used in Investing Activities
|
(1,395.8
|
)
|
(846.1
|
)
|
(808.5
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
||||||
Proceeds from long-term debt
|
246.3
|
|
246.2
|
|
444.8
|
|
|||
Contributions from noncontrolling interest partners
|
216.4
|
|
183.2
|
|
—
|
|
|||
Proceeds from line of credit
|
150.0
|
|
115.0
|
|
80.0
|
|
|||
Increase (decrease) in short-term debt
|
132.1
|
|
(30.0
|
)
|
(123.0
|
)
|
|||
Issuance of common stock
|
14.8
|
|
16.9
|
|
79.6
|
|
|||
Excess tax benefit on stock-based compensation
|
—
|
|
0.7
|
|
3.3
|
|
|||
Retirement of long-term debt
|
—
|
|
(289.2
|
)
|
(110.8
|
)
|
|||
Purchase of treasury stock
|
(6.2
|
)
|
—
|
|
—
|
|
|||
Distributions to noncontrolling interest partners
|
(17.4
|
)
|
(4.0
|
)
|
—
|
|
|||
Repayment of line of credit
|
(25.0
|
)
|
(90.0
|
)
|
(200.0
|
)
|
|||
Dividends paid on common stock
|
(146.8
|
)
|
(141.0
|
)
|
(136.2
|
)
|
|||
Net Cash Provided from Financing Activities
|
564.2
|
|
7.8
|
|
37.7
|
|
|||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
2.3
|
|
(55.8
|
)
|
(116.3
|
)
|
|||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
|
2.3
|
|
58.1
|
|
174.4
|
|
|||
CASH AND CASH EQUIVALENTS AT END OF PERIOD
|
$
|
4.6
|
|
$
|
2.3
|
|
$
|
58.1
|
|
December 31
(In millions)
|
2011
|
2010
|
||||
ASSETS
|
|
|
||||
CURRENT ASSETS
|
|
|
||||
Cash and cash equivalents
|
$
|
4.6
|
|
$
|
2.3
|
|
Accounts receivable, less reserve of $3.8 and $1.9, respectively
|
322.5
|
|
277.9
|
|
||
Accrued unbilled revenues
|
59.3
|
|
56.8
|
|
||
Income taxes receivable
|
8.3
|
|
4.7
|
|
||
Fuel inventories
|
100.7
|
|
158.8
|
|
||
Materials and supplies, at average cost
|
87.2
|
|
83.3
|
|
||
Price risk management
|
3.5
|
|
1.4
|
|
||
Gas imbalances
|
1.8
|
|
2.5
|
|
||
Deferred income taxes
|
32.1
|
|
18.7
|
|
||
Fuel clause under recoveries
|
1.8
|
|
1.0
|
|
||
Other
|
30.9
|
|
24.7
|
|
||
Total current assets
|
652.7
|
|
632.1
|
|
||
OTHER PROPERTY AND INVESTMENTS, at cost
|
46.7
|
|
44.9
|
|
||
PROPERTY, PLANT AND EQUIPMENT
|
|
|
||||
In service
|
10,315.9
|
|
9,188.0
|
|
||
Construction work in progress
|
499.0
|
|
460.0
|
|
||
Total property, plant and equipment
|
10,814.9
|
|
9,648.0
|
|
||
Less accumulated depreciation
|
3,340.9
|
|
3,183.6
|
|
||
Net property, plant and equipment
|
7,474.0
|
|
6,464.4
|
|
||
DEFERRED CHARGES AND OTHER ASSETS
|
|
|
||||
Regulatory assets
|
507.9
|
|
489.4
|
|
||
Intangible assets, net
|
137.0
|
|
2.8
|
|
||
Goodwill
|
39.4
|
|
—
|
|
||
Price risk management
|
0.3
|
|
0.8
|
|
||
Other
|
48.0
|
|
34.7
|
|
||
Total deferred charges and other assets
|
732.6
|
|
527.7
|
|
||
TOTAL ASSETS
|
$
|
8,906.0
|
|
$
|
7,669.1
|
|
December 31
(In millions)
|
2011
|
2010
|
||||
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
||||
CURRENT LIABILITIES
|
|
|
||||
Short-term debt
|
$
|
277.1
|
|
$
|
145.0
|
|
Accounts payable
|
388.0
|
|
321.7
|
|
||
Dividends payable
|
38.5
|
|
36.6
|
|
||
Customer deposits
|
67.6
|
|
67.0
|
|
||
Accrued taxes
|
42.3
|
|
39.3
|
|
||
Accrued interest
|
54.8
|
|
53.1
|
|
||
Accrued compensation
|
47.8
|
|
43.3
|
|
||
Price risk management
|
0.4
|
|
16.8
|
|
||
Gas imbalances
|
9.8
|
|
6.7
|
|
||
Fuel clause over recoveries
|
7.7
|
|
29.9
|
|
||
Other
|
64.5
|
|
55.1
|
|
||
Total current liabilities
|
998.5
|
|
814.5
|
|
||
LONG-TERM DEBT
|
2,737.1
|
|
2,362.9
|
|
||
DEFERRED CREDITS AND OTHER LIABILITIES
|
|
|
||||
Accrued benefit obligations
|
360.8
|
|
372.4
|
|
||
Deferred income taxes
|
1,651.4
|
|
1,434.8
|
|
||
Deferred investment tax credits
|
6.1
|
|
9.4
|
|
||
Regulatory liabilities
|
230.7
|
|
193.1
|
|
||
Price risk management
|
0.1
|
|
—
|
|
||
Deferred revenues
|
40.8
|
|
36.7
|
|
||
Other
|
61.2
|
|
45.3
|
|
||
Total deferred credits and other liabilities
|
2,351.1
|
|
2,091.7
|
|
||
Total liabilities
|
6,086.7
|
|
5,269.1
|
|
||
COMMITMENTS AND CONTINGENCIES (NOTE 16)
|
|
|
||||
STOCKHOLDERS' EQUITY
|
|
|
||||
Common stockholders' equity
|
1,035.3
|
|
969.2
|
|
||
Retained earnings
|
1,574.8
|
|
1,380.6
|
|
||
Accumulated other comprehensive loss, net of tax
|
(40.6
|
)
|
(60.2
|
)
|
||
Treasury stock, at cost
|
(6.2
|
)
|
—
|
|
||
Total OGE Energy stockholders' equity
|
2,563.3
|
|
2,289.6
|
|
||
Noncontrolling interests
|
256.0
|
|
110.4
|
|
||
Total stockholders' equity
|
2,819.3
|
|
2,400.0
|
|
||
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
8,906.0
|
|
$
|
7,669.1
|
|
December 31
(In millions)
|
2011
|
2010
|
|||||
STOCKHOLDERS' EQUITY
|
|
|
|||||
Common stock, par value $0.01 per share; authorized 225.0 shares; and outstanding 98.1 and 97.6 shares, respectively
|
$
|
1.0
|
|
$
|
1.0
|
|
|
Premium on common stock
|
1,034.3
|
|
968.2
|
|
|||
Retained earnings
|
1,574.8
|
|
1,380.6
|
|
|||
Accumulated other comprehensive loss, net of tax
|
(40.6
|
)
|
(60.2
|
)
|
|||
Treasury stock, at cost, 0.1 and 0 shares, respectively
|
(6.2
|
)
|
—
|
|
|||
Total OGE Energy stockholders' equity
|
2,563.3
|
|
2,289.6
|
|
|||
Noncontrolling interest
|
256.0
|
|
110.4
|
|
|||
Total stockholders' equity
|
2,819.3
|
|
2,400.0
|
|
|||
|
|
|
|||||
LONG-TERM DEBT
|
|
|
|||||
SERIES
|
DUE DATE
|
|
|
||||
Senior Notes - OGE Energy
|
|
|
|||||
5.00%
|
Senior Notes, Series Due November 15, 2014
|
100.0
|
|
100.0
|
|
||
Unamortized discount
|
(0.2
|
)
|
(0.3
|
)
|
|||
Senior Notes - OG&E
|
|
|
|||||
5.15%
|
Senior Notes, Series Due January 15, 2016
|
110.0
|
|
110.0
|
|
||
6.50%
|
Senior Notes, Series Due July 15, 2017
|
125.0
|
|
125.0
|
|
||
6.35%
|
Senior Notes, Series Due September 1, 2018
|
250.0
|
|
250.0
|
|
||
8.25%
|
Senior Notes, Series Due January 15, 2019
|
250.0
|
|
250.0
|
|
||
6.65%
|
Senior Notes, Series Due July 15, 2027
|
125.0
|
|
125.0
|
|
||
6.50%
|
Senior Notes, Series Due April 15, 2028
|
100.0
|
|
100.0
|
|
||
6.50%
|
Senior Notes, Series Due August 1, 2034
|
140.0
|
|
140.0
|
|
||
5.75%
|
Senior Notes, Series Due January 15, 2036
|
110.0
|
|
110.0
|
|
||
6.45%
|
Senior Notes, Series Due February 1, 2038
|
200.0
|
|
200.0
|
|
||
5.85%
|
Senior Notes, Series Due June 1, 2040
|
250.0
|
|
250.0
|
|
||
5.25%
|
Senior Notes, Series Due May 15, 2041
|
250.0
|
|
—
|
|
||
Other Bonds - OG&E
|
|
|
|||||
0.22% - 0.44%
|
Garfield Industrial Authority, January 1, 2025
|
47.0
|
|
47.0
|
|
||
0.20% - 0.44%
|
Muskogee Industrial Authority, January 1, 2025
|
32.4
|
|
32.4
|
|
||
0.24% - 0.50%
|
Muskogee Industrial Authority, June 1, 2027
|
56.0
|
|
56.0
|
|
||
Unamortized discount
|
(6.2
|
)
|
(5.0
|
)
|
|||
Enogex
|
|
|
|
||||
1.65%
|
Enogex LLC Revolving Credit Agreement Due December 13, 2016
|
150.0
|
|
25.0
|
|
||
6.875%
|
Senior Notes, Series Due July 15, 2014
|
200.0
|
|
200.0
|
|
||
6.25%
|
Senior Notes, Series Due March 15, 2020
|
250.0
|
|
250.0
|
|
||
Unamortized discount
|
(1.9
|
)
|
(2.2
|
)
|
|||
Total long-term debt
|
2,737.1
|
|
2,362.9
|
|
|||
Total Capitalization
|
$
|
5,556.4
|
|
$
|
4,762.9
|
|
(In millions)
|
Common Stock
|
Premium on Common Stock
|
Retained Earnings
|
Accumulated Other Comprehensive Income (Loss)
|
Noncontrolling Interest
|
Treasury Stock
|
Total
|
||||||||||||||
Balance at December 31, 2008
|
$
|
0.9
|
|
$
|
802.0
|
|
$
|
1,107.6
|
|
$
|
(13.7
|
)
|
$
|
17.2
|
|
$
|
—
|
|
$
|
1,914.0
|
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
||||||||||||||
Net income
|
—
|
|
—
|
|
258.3
|
|
—
|
|
2.8
|
|
—
|
|
261.1
|
|
|||||||
Other comprehensive income (loss), net of tax
|
—
|
|
—
|
|
—
|
|
(61.0
|
)
|
—
|
|
—
|
|
(61.0
|
)
|
|||||||
Comprehensive income (loss)
|
—
|
|
—
|
|
258.3
|
|
(61.0
|
)
|
2.8
|
|
—
|
|
200.1
|
|
|||||||
Dividends declared on common stock
|
—
|
|
—
|
|
(138.1
|
)
|
—
|
|
—
|
|
—
|
|
(138.1
|
)
|
|||||||
Issuance of common stock
|
0.1
|
|
79.5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
79.6
|
|
|||||||
Stock-based compensation
|
—
|
|
5.2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5.2
|
|
|||||||
Balance at December 31, 2009
|
$
|
1.0
|
|
$
|
886.7
|
|
$
|
1,227.8
|
|
$
|
(74.7
|
)
|
$
|
20.0
|
|
$
|
—
|
|
$
|
2,060.8
|
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
||||||||||||||
Net income
|
—
|
|
—
|
|
295.3
|
|
—
|
|
5.1
|
|
—
|
|
300.4
|
|
|||||||
Other comprehensive income (loss), net of tax
|
—
|
|
—
|
|
—
|
|
14.5
|
|
(5.8
|
)
|
—
|
|
8.7
|
|
|||||||
Comprehensive income (loss)
|
—
|
|
—
|
|
295.3
|
|
14.5
|
|
(0.7
|
)
|
—
|
|
309.1
|
|
|||||||
Dividends declared on common stock
|
—
|
|
—
|
|
(142.5
|
)
|
—
|
|
—
|
|
—
|
|
(142.5
|
)
|
|||||||
Issuance of common stock
|
—
|
|
17.0
|
|
—
|
|
—
|
|
—
|
|
—
|
|
17.0
|
|
|||||||
Stock-based compensation
|
—
|
|
10.4
|
|
—
|
|
—
|
|
—
|
|
—
|
|
10.4
|
|
|||||||
Contributions from noncontrolling interest partner
|
—
|
|
88.1
|
|
—
|
|
—
|
|
95.1
|
|
—
|
|
183.2
|
|
|||||||
Deferred income taxes attributable to contributions from noncontrolling interest partner
|
—
|
|
(34.0
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(34.0
|
)
|
|||||||
Distributions to noncontrolling interest partner
|
—
|
|
—
|
|
—
|
|
—
|
|
(4.0
|
)
|
—
|
|
(4.0
|
)
|
|||||||
Balance at December 31, 2010
|
$
|
1.0
|
|
$
|
968.2
|
|
$
|
1,380.6
|
|
$
|
(60.2
|
)
|
$
|
110.4
|
|
$
|
—
|
|
$
|
2,400.0
|
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
||||||||||||||
Net income
|
—
|
|
—
|
|
342.9
|
|
—
|
|
20.7
|
|
—
|
|
363.6
|
|
|||||||
Other comprehensive income (loss), net of tax
|
—
|
|
—
|
|
—
|
|
19.6
|
|
0.3
|
|
—
|
|
19.9
|
|
|||||||
Comprehensive income (loss)
|
—
|
|
—
|
|
342.9
|
|
19.6
|
|
21.0
|
|
—
|
|
383.5
|
|
|||||||
Dividends declared on common stock
|
—
|
|
—
|
|
(148.7
|
)
|
—
|
|
—
|
|
—
|
|
(148.7
|
)
|
|||||||
Issuance of common stock
|
—
|
|
14.8
|
|
—
|
|
—
|
|
—
|
|
—
|
|
14.8
|
|
|||||||
Stock-based compensation
|
—
|
|
5.8
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5.8
|
|
|||||||
Contributions from noncontrolling interest partners
|
—
|
|
74.4
|
|
—
|
|
—
|
|
142.0
|
|
—
|
|
216.4
|
|
|||||||
Distributions to noncontrolling interest partners
|
—
|
|
—
|
|
—
|
|
—
|
|
(17.4
|
)
|
—
|
|
(17.4
|
)
|
|||||||
Deferred income taxes attributable to contributions from noncontrolling interest partners
|
—
|
|
(28.9
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(28.9
|
)
|
|||||||
Purchase of treasury stock
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(6.2
|
)
|
(6.2
|
)
|
|||||||
Balance at December 31, 2011
|
$
|
1.0
|
|
$
|
1,034.3
|
|
$
|
1,574.8
|
|
$
|
(40.6
|
)
|
$
|
256.0
|
|
$
|
(6.2
|
)
|
$
|
2,819.3
|
|
1.
|
Summary of Significant Accounting Policies
|
December 31
(In millions)
|
2011
|
2010
|
||||
Regulatory Assets
|
|
|
||||
Current
|
|
|
||||
Fuel clause under recoveries
|
$
|
1.8
|
|
$
|
1.0
|
|
Other (A)
|
14.2
|
|
4.9
|
|
||
Total Current Regulatory Assets
|
$
|
16.0
|
|
$
|
5.9
|
|
Non-Current
|
|
|
|
|
||
Benefit obligations regulatory asset
|
$
|
359.2
|
|
$
|
365.5
|
|
Income taxes recoverable from customers, net
|
54.0
|
|
43.3
|
|
||
Smart Grid
|
37.2
|
|
14.2
|
|
||
Deferred storm expenses
|
23.8
|
|
28.6
|
|
||
Unamortized loss on reacquired debt
|
14.2
|
|
15.3
|
|
||
Deferred Pension expenses
|
9.1
|
|
13.5
|
|
||
Other
|
10.4
|
|
9.0
|
|
||
Total Non-Current Regulatory Assets
|
$
|
507.9
|
|
$
|
489.4
|
|
Regulatory Liabilities
|
|
|
|
|
||
Current
|
|
|
|
|
||
Smart Grid rider over collections (B)
|
$
|
24.3
|
|
$
|
10.4
|
|
Fuel clause over recoveries
|
7.7
|
|
29.9
|
|
||
Other (B)
|
13.7
|
|
10.5
|
|
||
Total Current Regulatory Liabilities
|
$
|
45.7
|
|
$
|
50.8
|
|
Non-Current
|
|
|
|
|
||
Accrued removal obligations, net
|
$
|
208.2
|
|
$
|
184.9
|
|
Pension tracker
|
22.5
|
|
8.2
|
|
||
Total Non-Current Regulatory Liabilities
|
$
|
230.7
|
|
$
|
193.1
|
|
(A)
|
Included in Other Current Assets on the
Consolidated
Balance Sheets.
|
(B)
|
Included in Other Current Liabilities on the
Consolidated
Balance Sheets.
|
December 31
(In millions)
|
2011
|
2010
|
||||
Pension Plan and Restoration of Retirement Income Plan:
|
|
|
||||
Net loss
|
$
|
266.3
|
|
$
|
215.0
|
|
Prior service cost
|
7.0
|
|
9.7
|
|
||
Postretirement plans:
|
|
|
||||
Net loss
|
144.2
|
|
135.7
|
|
||
Prior service cost
|
(60.8
|
)
|
—
|
|
||
Net transition obligation
|
2.5
|
|
5.1
|
|
||
Total
|
$
|
359.2
|
|
$
|
365.5
|
|
December 31, 2011
(In millions)
|
Percentage Ownership
|
Total Property, Plant and Equipment
|
|
Accumulated Depreciation
|
|
Net Property, Plant and Equipment
|
|||||||
McClain Plant
|
77
|
%
|
$
|
207.2
|
|
|
$
|
73.7
|
|
|
$
|
133.5
|
|
Redbud Plant
|
51
|
%
|
$
|
461.1
|
|
(A)
|
$
|
54.3
|
|
(B)
|
$
|
406.8
|
|
December 31, 2011
(In millions)
|
Total Property, Plant and Equipment
|
Accumulated Depreciation
|
Net Property, Plant and Equipment
|
||||||
OGE Energy (holding company)
|
|
|
|
||||||
Property, plant and equipment
|
$
|
124.6
|
|
$
|
90.6
|
|
$
|
34.0
|
|
OGE Energy property, plant and equipment
|
124.6
|
|
90.6
|
|
34.0
|
|
|||
OG&E
|
|
|
|
||||||
Distribution assets
|
2,981.3
|
|
920.3
|
|
2,061.0
|
|
|||
Electric generation assets
|
3,360.6
|
|
1,215.8
|
|
2,144.8
|
|
|||
Transmission assets
|
1,464.2
|
|
339.6
|
|
1,124.6
|
|
|||
Intangible plant
|
43.2
|
|
20.3
|
|
22.9
|
|
|||
Other property and equipment
|
293.9
|
|
96.3
|
|
197.6
|
|
|||
OG&E property, plant and equipment
|
8,143.2
|
|
2,592.3
|
|
5,550.9
|
|
|||
Enogex
|
|
|
|
||||||
Transportation and storage assets
|
956.9
|
|
271.0
|
|
685.9
|
|
|||
Gathering and processing assets
|
1,580.1
|
|
381.0
|
|
1,199.1
|
|
|||
Marketing assets
|
10.1
|
|
6.0
|
|
4.1
|
|
|||
Enogex property, plant and equipment
|
2,547.1
|
|
658.0
|
|
1,889.1
|
|
|||
Total property, plant and equipment
|
$
|
10,814.9
|
|
$
|
3,340.9
|
|
$
|
7,474.0
|
|
December 31, 2010 (In millio
ns)
|
Total Property, Plant and Equipment
|
Accumulated Depreciation
|
Net Property, Plant and Equipment
|
||||||
OGE Energy (holding company)
|
|
|
|
||||||
Property, plant and equipment
|
$
|
111.1
|
|
$
|
77.5
|
|
$
|
33.6
|
|
OGE Energy property, plant and equipment
|
111.1
|
|
77.5
|
|
33.6
|
|
|||
OG&E
|
|
|
|
||||||
Distribution assets
|
2,833.4
|
|
897.4
|
|
1,936.0
|
|
|||
Electric generation assets
|
3,047.1
|
|
1,164.6
|
|
1,882.5
|
|
|||
Transmission assets
|
1,221.3
|
|
325.6
|
|
895.7
|
|
|||
Intangible plant
|
26.5
|
|
20.7
|
|
5.8
|
|
|||
Other property and equipment
|
243.4
|
|
86.1
|
|
157.3
|
|
|||
OG&E property, plant and equipment
|
7,371.7
|
|
2,494.4
|
|
4,877.3
|
|
|||
Enogex
|
|
|
|
||||||
Transportation and storage assets
|
924.7
|
|
250.0
|
|
674.7
|
|
|||
Gathering and processing assets
|
1,230.8
|
|
354.6
|
|
876.2
|
|
|||
Marketing assets
|
9.7
|
|
7.1
|
|
2.6
|
|
|||
Enogex property, plant and equipment
|
2,165.2
|
|
611.7
|
|
1,553.5
|
|
|||
Total property, plant and equipment
|
$
|
9,648.0
|
|
$
|
3,183.6
|
|
$
|
6,464.4
|
|
December 31
(In millions)
|
2011
|
2010
|
||||
Pension Plan and Restoration of Retirement Income Plan:
|
|
|
||||
Net loss
|
$
|
(42.1
|
)
|
$
|
(31.1
|
)
|
Prior service cost
|
(0.1
|
)
|
(0.5
|
)
|
||
Postretirement plans:
|
|
|
||||
Net loss
|
(15.4
|
)
|
(13.6
|
)
|
||
Prior service cost
|
9.0
|
|
—
|
|
||
Net transition obligation
|
(0.1
|
)
|
(0.3
|
)
|
||
Deferred commodity contracts hedging losses
|
3.3
|
|
(19.5
|
)
|
||
Deferred interest rate swaps hedging losses
|
(0.7
|
)
|
(1.0
|
)
|
||
Total accumulated other comprehensive loss
|
(46.1
|
)
|
(66.0
|
)
|
||
Less: Accumulated other comprehensive loss attributable to noncontrolling interests
|
(5.5
|
)
|
(5.8
|
)
|
||
Accumulated other comprehensive loss, net of tax
|
$
|
(40.6
|
)
|
$
|
(60.2
|
)
|
(In millions)
|
|
||
Pension Plan and Restoration of Retirement Income Plan:
|
|
||
Net loss
|
$
|
2.7
|
|
Prior service cost
|
0.3
|
|
|
Postretirement plans:
|
|
||
Net loss
|
1.9
|
|
|
Prior service cost
|
(1.8
|
)
|
|
Net transition obligation
|
0.1
|
|
|
Total, net of tax
|
$
|
3.2
|
|
2.
|
Accounting Pronouncement
s
|
3.
|
Business Combination
|
4.
|
Noncontrolling Interest Owner
|
(In millions)
|
OGE Holdings
|
ArcLight group
|
Total
|
|||
Balance at December 31, 2010 (units)
|
90.1
|
|
9.9
|
|
100.0
|
|
Ownership percentage at December 31, 2010
|
90.1
|
%
|
9.9
|
%
|
100.0
|
%
|
|
|
|
|
|||
Sale of 100,000 units of Enogex Holdings (A)
|
(0.1
|
)
|
0.1
|
|
—
|
|
Issuance of 4,303,007 units of Enogex Holdings (B)
|
0.4
|
|
3.9
|
|
4.3
|
|
Issuance of 5,405,405 units of Enogex Holdings (C)
|
0.5
|
|
4.9
|
|
5.4
|
|
Issuance of 5,725,190 units of Enogex Holdings (D)
|
2.9
|
|
2.8
|
|
5.7
|
|
|
|
|
|
|||
Balance at December 31, 2011 (units)
|
93.8
|
|
21.6
|
|
115.4
|
|
Ownership percentage at December 31, 2011
|
81.3
|
%
|
18.7
|
%
|
100.0
|
%
|
(In millions)
|
OGE Holdings Portion
|
ArcLight group's Portion
|
Total Distribution
|
|
|||||
First quarter 2011
|
$
|
7.5
|
|
$
|
0.8
|
|
$
|
8.3
|
|
Second quarter 2011
|
34.3
|
|
5.3
|
|
39.6
|
|
|||
Third quarter 2011
|
43.4
|
|
6.6
|
|
50.0
|
|
|||
Fourth quarter 2011
|
30.4
|
|
4.7
|
|
35.1
|
|
|||
Total
|
$
|
115.6
|
|
$
|
17.4
|
|
$
|
133.0
|
|
5.
|
Impairment of Assets
|
6.
|
Fair Value Measurements
|
December 31, 2011
|
||||||||||||
(In millions)
|
Commodity Contracts
|
Gas Imbalances (A)
|
||||||||||
|
Assets
|
Liabilities
|
Assets
|
Liabilities (B)
|
||||||||
Quoted market prices in active market for identical assets (Level 1)
|
$
|
57.1
|
|
$
|
52.3
|
|
$
|
—
|
|
$
|
—
|
|
Significant other observable inputs (Level 2)
|
4.2
|
|
1.2
|
|
1.8
|
|
7.8
|
|
||||
Total fair value
|
61.3
|
|
53.5
|
|
1.8
|
|
7.8
|
|
||||
Netting adjustments
|
(57.5
|
)
|
(53.0
|
)
|
—
|
|
—
|
|
||||
Total
|
$
|
3.8
|
|
$
|
0.5
|
|
$
|
1.8
|
|
$
|
7.8
|
|
|
|
|
|
|
||||||||
December 31, 2010
|
||||||||||||
(In millions)
|
Commodity Contracts
|
Gas Imbalances (A)
|
||||||||||
|
Assets
|
Liabilities
|
Assets
|
Liabilities (B)
|
||||||||
Quoted market prices in active market for identical assets (Level 1)
|
$
|
20.6
|
|
$
|
20.2
|
|
$
|
—
|
|
$
|
—
|
|
Significant other observable inputs (Level 2)
|
2.7
|
|
30.7
|
|
2.5
|
|
2.8
|
|
||||
Significant unobservable inputs (Level 3)
|
13.3
|
|
—
|
|
—
|
|
—
|
|
||||
Total fair value
|
36.6
|
|
50.9
|
|
2.5
|
|
2.8
|
|
||||
Netting adjustments
|
(34.4
|
)
|
(34.1
|
)
|
—
|
|
—
|
|
||||
Total
|
$
|
2.2
|
|
$
|
16.8
|
|
$
|
2.5
|
|
$
|
2.8
|
|
(A)
|
The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.
|
(B)
|
Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of
$2.0 million
and
$3.9 million
at
December 31, 2011
and
2010
, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
|
|
Commodity Contracts
|
|||||||||||
|
Assets
|
Liabilities
|
||||||||||
(In millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||
Balance at January 1
|
$
|
13.3
|
|
$
|
49.0
|
|
$
|
—
|
|
$
|
14.7
|
|
Total gains or losses
|
|
|
|
|
||||||||
Included in other comprehensive income
|
(5.4
|
)
|
(10.0
|
)
|
—
|
|
—
|
|
||||
Settlements
|
(7.9
|
)
|
(25.7
|
)
|
—
|
|
(14.7
|
)
|
||||
Balance at December 31
|
$
|
—
|
|
$
|
13.3
|
|
$
|
—
|
|
$
|
—
|
|
|
2011
|
2010
|
||||||||||
December 31
(In millions)
|
Carrying Amount
|
Fair
Value |
Carrying Amount
|
Fair
Value |
||||||||
Price Risk Management Assets
|
|
|
|
|
||||||||
Energy Derivative Contracts
|
$
|
3.8
|
|
$
|
3.8
|
|
$
|
2.2
|
|
$
|
2.2
|
|
Price Risk Management Liabilities
|
|
|
|
|
||||||||
Energy Derivative Contracts
|
$
|
0.5
|
|
$
|
0.5
|
|
$
|
16.8
|
|
$
|
16.8
|
|
Long-Term Debt
|
|
|
|
|
||||||||
OG&E Senior Notes
|
$
|
1,903.8
|
|
$
|
2,383.8
|
|
$
|
1,655.0
|
|
$
|
1,831.5
|
|
OGE Energy Senior Notes
|
99.8
|
|
108.5
|
|
99.7
|
|
106.4
|
|
||||
OG&E Industrial Authority Bonds
|
135.4
|
|
135.4
|
|
135.4
|
|
135.4
|
|
||||
Enogex LLC Senior Notes
|
448.1
|
|
497.9
|
|
447.8
|
|
480.7
|
|
||||
Enogex LLC Revolving Credit Agreement
|
150.0
|
|
150.0
|
|
25.0
|
|
25.0
|
|
7.
|
Derivative Instruments and Hedging Activities
|
•
|
NGLs put options and NGLs swaps are used to manage Enogex's NGLs exposure associated with its processing agreements;
|
•
|
natural gas swaps are used to manage Enogex's keep-whole natural gas exposure associated with its processing operations and Enogex's natural gas exposure associated with operating its gathering, transportation and storage assets;
|
•
|
natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OER's natural gas exposure associated with its storage and transportation contracts; and
|
•
|
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OER's marketing and trading activities.
|
(In millions)
|
2011 Gross Notional Volume (A)
|
|
Enogex marketing hedges
|
|
|
Natural gas sales
|
3.2
|
|
(A)
|
Natural gas in MMBtu's.
|
(A)
|
Natural gas in MMBtu's.
|
(B)
|
88.0 percent
of the natural gas contracts have durations of one year or less,
5.5 percent
have durations of more than one year and less than two years and
6.5 percent
have durations of more than two years.
|
(C)
|
Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.
|
(D)
|
Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.
|
|
|
Fair Value
|
|||||
Instrument
|
Balance Sheet Location
|
Assets
|
Liabilities
|
||||
|
|
(In millions)
|
|||||
Derivatives Designated as Hedging Instruments
|
|
|
|
||||
Natural Gas
|
|
|
|
||||
Financial Futures/Swaps
|
Other Current Assets
|
$
|
5.2
|
|
$
|
0.3
|
|
Total
|
$
|
5.2
|
|
$
|
0.3
|
|
|
|
|
|
|
||||
Derivatives Not Designated as Hedging Instruments
|
|
|
|
||||
Natural Gas
|
|
|
|
||||
Financial Futures/Swaps
|
Current PRM
|
$
|
0.4
|
|
$
|
—
|
|
|
Other Current Assets
|
49.9
|
|
49.9
|
|
||
Physical Purchases/Sales
|
Current PRM
|
3.1
|
|
0.4
|
|
||
|
Non-Current PRM
|
0.3
|
|
0.1
|
|
||
Financial Options
|
Other Current Assets
|
2.4
|
|
2.8
|
|
||
Total
|
$
|
56.1
|
|
$
|
53.2
|
|
|
Total Gross Derivatives (A)
|
$
|
61.3
|
|
$
|
53.5
|
|
(A)
|
See Note 6 for a reconciliation of the Company's total derivatives fair value to the Company's Consolidated Balance Sheet at
December 31, 2011
.
|
|
|
Fair Value
|
|||||
Instrument
|
Balance Sheet Location
|
Assets
|
Liabilities
|
||||
|
|
(In millions)
|
|||||
Derivatives Designated as Hedging Instruments
|
|
|
|
||||
NGLs
|
|
|
|
||||
Financial Options
|
Current PRM
|
$
|
13.3
|
|
$
|
—
|
|
Natural Gas
|
|
|
|
||||
Financial Futures/Swaps
|
Current PRM
|
—
|
|
28.8
|
|
||
|
Other Current Assets
|
0.6
|
|
0.3
|
|
||
Total
|
$
|
13.9
|
|
$
|
29.1
|
|
|
|
|
|
|
||||
Derivatives Not Designated as Hedging Instruments
|
|
|
|
||||
Natural Gas
|
|
|
|
||||
Financial Futures/Swaps
|
Current PRM
|
$
|
—
|
|
$
|
0.1
|
|
|
Other Current Assets
|
20.0
|
|
19.8
|
|
||
Physical Purchases/Sales
|
Current PRM
|
1.4
|
|
1.2
|
|
||
|
Non-Current PRM
|
0.8
|
|
—
|
|
||
Financial Options
|
Other Current Assets
|
0.5
|
|
0.7
|
|
||
Total
|
$
|
22.7
|
|
$
|
21.8
|
|
|
Total Gross Derivatives (A)
|
$
|
36.6
|
|
$
|
50.9
|
|
(A)
|
See Note 6 for a reconciliation of the Company's total derivatives fair value to the Company's Consolidated Balance Sheet at
December 31, 2010
.
|
(In millions)
|
Amount Recognized in Other Comprehensive Income (A) |
Amount Reclassified from Accumulated Other Comprehensive Income into Income
|
Amount Recognized in Income |
||||||
NGLs Financial Options
|
$
|
(8.4
|
)
|
$
|
(9.8
|
)
|
$
|
—
|
|
Natural Gas Financial Futures/Swaps
|
2.9
|
|
(30.4
|
)
|
—
|
|
|||
Total
|
$
|
(5.5
|
)
|
$
|
(40.2
|
)
|
$
|
—
|
|
(A)
|
The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at
December 31, 2011
that is expected to be reclassified into income within the next 12 months is a loss of
$4.9 million
.
|
(In millions)
|
Amount Recognized in Income
|
||
Natural Gas Physical Purchases/Sales
|
$
|
(10.0
|
)
|
Natural Gas Financial Futures/Swaps
|
0.4
|
|
|
Total
|
$
|
(9.6
|
)
|
(In millions)
|
Amount Recognized in Other Comprehensive Income |
Amount Reclassified from Accumulated Other Comprehensive Income into Income
|
Amount Recognized in Income |
||||||
NGLs Financial Options
|
$
|
(9.7
|
)
|
$
|
1.2
|
|
$
|
—
|
|
NGLs Financial Futures/Swaps
|
1.7
|
|
(3.7
|
)
|
—
|
|
|||
Natural Gas Financial Futures/Swaps
|
(14.9
|
)
|
(25.9
|
)
|
0.2
|
|
|||
Total
|
$
|
(22.9
|
)
|
$
|
(28.4
|
)
|
$
|
0.2
|
|
(In millions)
|
Amount Recognized in Income
|
||
Natural Gas Physical Purchases/Sales
|
$
|
(11.7
|
)
|
Natural Gas Financial Futures/Swaps
|
3.2
|
|
|
Total
|
$
|
(8.5
|
)
|
(In millions)
|
Amount Recognized in Other Comprehensive Income |
Amount Reclassified from Accumulated Other Comprehensive Income into Income
|
Amount Recognized in Income |
||||||
NGLs Financial Options
|
$
|
(56.4
|
)
|
$
|
1.7
|
|
$
|
—
|
|
NGLs Financial Futures/Swaps
|
(33.7
|
)
|
12.6
|
|
—
|
|
|||
Natural Gas Financial Futures/Swaps
|
(19.8
|
)
|
(26.5
|
)
|
(0.2
|
)
|
|||
Total
|
$
|
(109.9
|
)
|
$
|
(12.2
|
)
|
$
|
(0.2
|
)
|
(In millions)
|
Amount Recognized in Income
|
||
Natural Gas Physical Purchases/Sales
|
$
|
(24.3
|
)
|
Natural Gas Financial Futures/Swaps
|
17.7
|
|
|
NGLs Financial Futures/Swaps
|
(0.2
|
)
|
|
Total
|
$
|
(6.8
|
)
|
8.
|
Stock-Based Compensation
|
|
2011
|
2010
|
2009
|
||||||
Number of units granted
|
213,721
|
|
214,750
|
|
316,513
|
|
|||
Fair value of units granted
|
$
|
46.09
|
|
$
|
39.43
|
|
$
|
25.55
|
|
Expected dividend yield
|
3.2
|
%
|
3.9
|
%
|
4.5
|
%
|
|||
Expected price volatility
|
33.0
|
%
|
34.0
|
%
|
31.0
|
%
|
|||
Risk-free interest rate
|
1.40
|
%
|
1.42
|
%
|
1.25
|
%
|
|||
Expected life of units (in years)
|
2.87
|
|
2.87
|
|
2.88
|
|
|
2011
|
2010
|
2009
|
||||||
Number of units granted
|
71,238
|
|
71,585
|
|
105,504
|
|
|||
Fair value of units granted
|
$
|
41.61
|
|
$
|
32.44
|
|
$
|
20.02
|
|
|
2011
|
2010
|
2009
|
||||||
Shares of restricted stock granted
|
17,902
|
|
26,653
|
|
6,226
|
|
|||
Fair value of restricted stock granted
|
$
|
48.82
|
|
$
|
40.78
|
|
$
|
33.38
|
|
|
Performance Units
|
|
|
||||||||||||||
|
Total Shareholder Return
|
Earnings Per Share
|
Restricted Stock
|
||||||||||||||
|
Number
of Units |
|
Weighted-Average
Grant Date Fair Value |
Number
of Units |
|
Weighted-Average
Grant Date Fair Value |
Number
of Shares |
Weighted-Average
Grant Date Fair Value |
|||||||||
Units/Shares Non-Vested at 12/31/10
|
507,154
|
|
|
$
|
31.40
|
|
169,054
|
|
|
$
|
25.26
|
|
47,739
|
|
$
|
36.46
|
|
Granted
|
213,721
|
|
(A)
|
$
|
46.09
|
|
71,238
|
|
(A)
|
$
|
41.61
|
|
17,902
|
|
$
|
48.82
|
|
Vested
|
(291,294
|
)
|
|
$
|
25.55
|
|
(97,099
|
)
|
|
$
|
20.02
|
|
(28,397
|
)
|
$
|
34.05
|
|
Forfeited
|
(14,751
|
)
|
|
$
|
40.53
|
|
(4,916
|
)
|
|
$
|
34.91
|
|
—
|
|
$
|
—
|
|
Units/Shares Non-Vested at 12/31/11
|
414,830
|
|
|
$
|
42.75
|
|
138,277
|
|
|
$
|
37.01
|
|
37,244
|
|
$
|
44.24
|
|
Units/Shares Expected to Vest
|
357,974
|
|
|
|
119,325
|
|
|
|
37,244
|
|
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Performance units
|
|
|
|
||||||
Total shareholder return
|
$
|
7.4
|
|
$
|
5.4
|
|
$
|
1.9
|
|
Earnings per share
|
3.9
|
|
1.9
|
|
0.5
|
|
|||
Restricted stock
|
1.0
|
|
0.6
|
|
0.6
|
|
December 31, 2011
|
Unrecognized Compensation Cost
(in millions)
|
Weighted Average to be Recognized
(in years)
|
|||
Performance units
|
|
|
|||
Total shareholder return
|
$
|
7.8
|
|
1.70
|
|
Earnings per share
|
3.0
|
|
1.56
|
|
|
Total performance units
|
10.8
|
|
|
||
Restricted stock
|
0.9
|
|
2.33
|
|
|
Total
|
$
|
11.7
|
|
|
(dollars in millions)
|
Number of Options
|
Weighted-Average Exercise Price
|
Aggregate Intrinsic Value
|
Weighted-Average Remaining Contractual Term
|
|||||||
Options Outstanding at 12/31/10
|
100,344
|
|
$
|
22.19
|
|
|
|
|
|
|
|
Exercised
|
(44,544
|
)
|
$
|
20.94
|
|
$
|
2.2
|
|
|
|
|
Options Outstanding at 12/31/11
|
55,800
|
|
$
|
23.19
|
|
$
|
1.9
|
|
1.96
|
|
years
|
Options Fully Vested and Exercisable at 12/31/11
|
55,800
|
|
$
|
23.19
|
|
$
|
1.9
|
|
1.96
|
|
years
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Intrinsic value (A)
|
$
|
2.2
|
|
$
|
2.5
|
|
$
|
1.7
|
|
Cash received from stock options exercised
|
1.3
|
|
3.2
|
|
3.5
|
|
|||
Income tax benefit realized for the tax deductions from exercised stock options (B)
|
—
|
|
1.0
|
|
0.7
|
|
(A)
|
The difference between the market value on the date of exercise and the option exercise price.
|
(B)
|
The Company did not realize an income tax benefit for the tax deductions from the exercised stock options in
2011
due to the Company being in a tax net operating loss position in
2011
.
|
9.
|
Supplemental Cash Flow Information
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
NON-CASH INVESTING AND FINANCING ACTIVITIES
|
|
|
|
||||||
Power plant long-term service agreement
|
$
|
1.7
|
|
$
|
2.7
|
|
$
|
—
|
|
Future installment payments to wind farm developer
|
—
|
|
2.3
|
|
3.9
|
|
|||
|
|
|
|
||||||
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
||||||
Cash Paid During the Period for
|
|
|
|
||||||
Interest (net of interest capitalized) (A)
|
$
|
138.9
|
|
$
|
144.6
|
|
$
|
125.8
|
|
Income taxes (net of income tax refunds)
|
4.7
|
|
(139.5
|
)
|
2.0
|
|
10.
|
Income Taxes
|
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Provision (Benefit) for Current Income Taxes
|
|
|
|
||||||
Federal
|
$
|
(6.4
|
)
|
$
|
15.8
|
|
$
|
(145.3
|
)
|
State
|
—
|
|
2.3
|
|
(4.8
|
)
|
|||
Total Provision (Benefit) for Current Income Taxes
|
(6.4
|
)
|
18.1
|
|
(150.1
|
)
|
|||
Provision for Deferred Income Taxes, net
|
|
|
|
||||||
Federal
|
160.3
|
|
134.5
|
|
256.7
|
|
|||
State
|
2.9
|
|
9.3
|
|
8.1
|
|
|||
Total Provision for Deferred Income Taxes, net
|
163.2
|
|
143.8
|
|
264.8
|
|
|||
Deferred Federal Investment Tax Credits, net
|
(3.3
|
)
|
(3.7
|
)
|
(4.2
|
)
|
|||
Income Taxes Relating to Other Income and Deductions
|
7.2
|
|
2.8
|
|
10.6
|
|
|||
Total Income Tax Expense
|
$
|
160.7
|
|
$
|
161.0
|
|
$
|
121.1
|
|
Year ended December 31
|
2011
|
2010
|
2009
|
|||
Statutory Federal tax rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
Amortization of net unfunded deferred taxes
|
0.7
|
|
0.7
|
|
0.7
|
|
State income taxes, net of Federal income tax benefit
|
0.6
|
|
1.7
|
|
1.0
|
|
Medicare Part D subsidy
|
0.2
|
|
2.6
|
|
(1.1
|
)
|
Qualified production activities
|
—
|
|
(0.2
|
)
|
—
|
|
401(k) dividends
|
(0.5
|
)
|
(0.6
|
)
|
(0.7
|
)
|
Federal investment tax credits, net
|
(0.7
|
)
|
(0.8
|
)
|
(1.1
|
)
|
Income attributable to noncontrolling interest
|
(1.3
|
)
|
(0.4
|
)
|
—
|
|
Federal renewable energy credit (A)
|
(3.4
|
)
|
(3.4
|
)
|
(2.2
|
)
|
Other
|
0.1
|
|
0.3
|
|
0.1
|
|
Effective income tax rate
|
30.7
|
%
|
34.9
|
%
|
31.7
|
%
|
December 31
(In millions)
|
2011
|
2010
|
||||
Current Deferred Income Tax Assets
|
|
|
||||
Net operating losses
|
$
|
15.8
|
|
$
|
—
|
|
Accrued liabilities
|
13.2
|
|
8.2
|
|
||
Accrued vacation
|
4.2
|
|
6.1
|
|
||
Uncollectible accounts
|
1.4
|
|
0.6
|
|
||
Other
|
—
|
|
2.8
|
|
||
Total Current Deferred Income Tax Assets
|
34.6
|
|
17.7
|
|
||
Current Accrued Income Tax Liabilities
|
|
|
||||
Derivative instruments
|
(2.5
|
)
|
1.0
|
|
||
Total Current Accrued Income Tax Liabilities
|
(2.5
|
)
|
1.0
|
|
||
Current Deferred Income Tax Assets, net
|
$
|
32.1
|
|
$
|
18.7
|
|
|
|
|
||||
Non-Current Deferred Income Tax Liabilities
|
|
|
||||
Accelerated depreciation and other property related differences
|
$
|
1,449.6
|
|
$
|
1,071.4
|
|
Investment in Enogex Holdings
|
571.8
|
|
376.1
|
|
||
Company pension plan
|
67.5
|
|
71.4
|
|
||
Regulatory asset
|
21.2
|
|
17.2
|
|
||
Income taxes refundable to customers, net
|
15.9
|
|
16.8
|
|
||
Bond redemption-unamortized costs
|
4.4
|
|
4.8
|
|
||
Derivative instruments
|
—
|
|
22.4
|
|
||
Total Non-Current Deferred Income Tax Liabilities
|
2,130.4
|
|
1,580.1
|
|
||
Non-Current Deferred Income Tax Assets
|
|
|
||||
Net operating losses
|
(225.2
|
)
|
—
|
|
||
Regulatory liabilities
|
(65.3
|
)
|
(43.7
|
)
|
||
State tax credits
|
(63.0
|
)
|
(35.5
|
)
|
||
Postretirement medical and life insurance benefits
|
(50.2
|
)
|
(39.0
|
)
|
||
Federal tax credits
|
(49.7
|
)
|
(21.5
|
)
|
||
Derivative instruments
|
(12.8
|
)
|
—
|
|
||
Deferred Federal investment tax credits
|
(2.3
|
)
|
(3.6
|
)
|
||
Other
|
(10.5
|
)
|
(2.0
|
)
|
||
Total Non-Current Deferred Income Tax Assets
|
(479.0
|
)
|
(145.3
|
)
|
||
Non-Current Deferred Income Tax Liabilities, net
|
$
|
1,651.4
|
|
$
|
1,434.8
|
|
(In millions)
|
Carry Forward Amount
|
Deferred Tax Asset
|
Earliest Expiration Date
|
||||
Net operating losses
|
|
|
|
||||
State operating loss
|
$
|
772.9
|
|
$
|
28.4
|
|
2030
|
Federal operating loss
|
607.2
|
|
212.6
|
|
2030
|
||
Federal tax credits
|
49.7
|
|
49.7
|
|
2029
|
||
State tax credits
|
|
|
|
||||
Oklahoma investment tax credits
|
76.3
|
|
49.7
|
|
N/A
|
||
Oklahoma capital investment board credits (A)
|
7.3
|
|
7.3
|
|
2015
|
||
Oklahoma zero emission tax credits
|
8.4
|
|
6.0
|
|
2020
|
11.
|
Common Equity
|
(In millions)
|
2011
|
2010
|
2009
|
||||||
Net Income Attributable to OGE Energy
|
$
|
342.9
|
|
$
|
295.3
|
|
$
|
258.3
|
|
Average Common Shares Outstanding
|
|
|
|
||||||
Basic average common shares outstanding
|
97.9
|
|
97.3
|
|
96.2
|
|
|||
Effect of dilutive securities:
|
|
|
|
||||||
Contingently issuable shares (performance units)
|
1.3
|
|
1.6
|
|
1.0
|
|
|||
Diluted average common shares outstanding
|
99.2
|
|
98.9
|
|
97.2
|
|
|||
Basic Earnings Per Average Common Share
|
|
|
|
||||||
Attributable to OGE Energy Common Shareholders
|
$
|
3.50
|
|
$
|
3.03
|
|
$
|
2.68
|
|
Diluted Earnings Per Average Common Share
|
|
|
|
||||||
Attributable to OGE Energy Common Shareholders
|
$
|
3.45
|
|
$
|
2.99
|
|
$
|
2.66
|
|
Anti-dilutive shares excluded from earnings per share calculation
|
—
|
|
—
|
|
—
|
|
12.
|
Long-Term Debt
|
SERIES
|
DATE DUE
|
AMOUNT
|
||
|
|
(In millions)
|
||
0.22% - 0.44%
|
Garfield Industrial Authority, January 1, 2025
|
$
|
47.0
|
|
0.20% - 0.44%
|
Muskogee Industrial Authority, January 1, 2025
|
32.4
|
|
|
0.24% - 0.50%
|
Muskogee Industrial Authority, June 1, 2027
|
56.0
|
|
|
Total (redeemable during next 12 months)
|
$
|
135.4
|
|
13.
|
Short-Term Debt and Credit
Facilities
|
(A)
|
Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at
December 31, 2011
.
|
(B)
|
This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At
December 31, 2011
, there was
$277.1 million
in outstanding commercial paper borrowings.
|
(C)
|
This bank facility is
available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.
At
December 31, 2011
,
there was
$2.2 million
supporting letters of credit
.
|
(D)
|
Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
|
(E)
|
This bank facility is available to provide revolving credit borrowings for Enogex LLC.
As Enogex LLC's credit agreement matures on December 13, 2016, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Consolidated Balance Sheets.
|
(F)
|
In December 2011, the Company, OG&E and Enogex LLC each entered into new unsecured five-year revolving credit facilities totaling in the aggregate
$1,550 million
(
$750 million
for the Company,
$400 million
for OG&E and
$400 million
for Enogex LLC).
Each of the credit facilities contain an option, which may be exercised up to two times, to extend the term for an additional year.
|
14.
|
Retirement Plans and Postretirement Benefit Plans
|
|
Pension Plan
|
Restoration of Retirement
Income Plan |
||||||||||
December 31
(In millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||
Benefit obligations
|
$
|
(697.7
|
)
|
$
|
(640.9
|
)
|
$
|
(13.3
|
)
|
$
|
(10.8
|
)
|
Fair value of plan assets
|
589.8
|
|
574.0
|
|
—
|
|
—
|
|
||||
Funded status at end of year
|
$
|
(107.9
|
)
|
$
|
(66.9
|
)
|
$
|
(13.3
|
)
|
$
|
(10.8
|
)
|
Projected Benefit Obligation Funded Status Thresholds
|
<90%
|
95%
|
100%
|
105%
|
110%
|
115%
|
120%
|
Fixed income
|
50%
|
58%
|
65%
|
73%
|
80%
|
85%
|
90%
|
Equity
|
50%
|
42%
|
35%
|
27%
|
20%
|
15%
|
10%
|
Total
|
100%
|
100%
|
100%
|
100%
|
100%
|
100%
|
100%
|
Asset Class
|
Target Allocation
|
Minimum
|
Maximum
|
Domestic All-Cap/Large Cap Equity
|
50%
|
50%
|
60%
|
Domestic Mid-Cap Equity
|
15%
|
5%
|
25%
|
Domestic Small-Cap Equity
|
15%
|
5%
|
25%
|
International Equity
|
20%
|
10%
|
30%
|
(In millions)
|
December 31, 2011
|
Level 1
|
Level 2
|
||||||
Common stocks
|
|
|
|
||||||
U.S. common stocks
|
$
|
179.7
|
|
$
|
179.7
|
|
$
|
—
|
|
Foreign common stocks
|
59.5
|
|
59.5
|
|
—
|
|
|||
Bonds, debentures and notes (A)
|
|
|
|
|
|
|
|||
Corporate fixed income and other securities
|
95.3
|
|
—
|
|
95.3
|
|
|||
Mortgage-backed securities
|
17.2
|
|
—
|
|
17.2
|
|
|||
U.S. Government obligations
|
|
|
|
|
|
|
|||
U.S. treasury notes and bonds (B)
|
118.8
|
|
118.8
|
|
—
|
|
|||
Mortgage-backed securities
|
72.0
|
|
—
|
|
72.0
|
|
|||
Other securities
|
1.0
|
|
—
|
|
1.0
|
|
|||
Commingled fund (C)
|
38.5
|
|
—
|
|
38.5
|
|
|||
Common/collective trust (D)
|
29.6
|
|
—
|
|
29.6
|
|
|||
Foreign government bonds
|
2.9
|
|
—
|
|
2.9
|
|
|||
Interest-bearing cash
|
2.1
|
|
2.1
|
|
—
|
|
|||
U.S. municipal bonds
|
1.7
|
|
—
|
|
1.7
|
|
|||
Preferred stocks (foreign)
|
0.6
|
|
0.6
|
|
—
|
|
|||
Total Plan investments
|
$
|
618.9
|
|
$
|
360.7
|
|
$
|
258.2
|
|
Receivable from broker for securities sold
|
4.8
|
|
|
|
|
|
|||
Interest and dividends receivable
|
3.1
|
|
|
|
|
|
|||
Payable to broker for securities purchased
|
(37.0
|
)
|
|
|
|
|
|||
Total Plan assets
|
$
|
589.8
|
|
|
|
|
|
(In millions)
|
December 31, 2010
|
Level 1
|
Level 2
|
||||||
Common stocks
|
|
|
|
||||||
U.S. common stocks
|
$
|
189.0
|
|
$
|
189.0
|
|
$
|
—
|
|
Foreign common stocks
|
75.9
|
|
75.9
|
|
—
|
|
|||
Bonds, debentures and notes (A)
|
|
|
|
|
|
|
|||
Corporate fixed income and other securities
|
104.1
|
|
—
|
|
104.1
|
|
|||
Mortgage-backed securities
|
26.6
|
|
—
|
|
26.6
|
|
|||
U.S. Government obligations
|
|
|
|
|
|
|
|||
Mortgage-backed securities
|
76.5
|
|
—
|
|
76.5
|
|
|||
U.S. treasury notes and bonds (B)
|
35.7
|
|
35.7
|
|
—
|
|
|||
Other securities
|
2.4
|
|
—
|
|
2.4
|
|
|||
Commingled fund (C)
|
37.7
|
|
—
|
|
37.7
|
|
|||
Common/collective trust (D)
|
23.1
|
|
—
|
|
23.1
|
|
|||
Mutual funds
|
|
|
|
||||||
Global equity mutual fund
|
1.8
|
|
1.8
|
|
—
|
|
|||
U.S equity mutual fund
|
1.6
|
|
1.6
|
|
—
|
|
|||
Foreign equity mutual fund
|
1.0
|
|
1.0
|
|
—
|
|
|||
U.S. municipal bonds
|
4.3
|
|
—
|
|
4.3
|
|
|||
Foreign government bonds
|
3.9
|
|
—
|
|
3.9
|
|
|||
Repurchase agreement
|
3.7
|
|
—
|
|
3.7
|
|
|||
Preferred stocks (foreign)
|
0.7
|
|
0.7
|
|
—
|
|
|||
Interest-bearing cash
|
0.2
|
|
0.2
|
|
—
|
|
|||
Total Plan investments
|
$
|
588.2
|
|
$
|
305.9
|
|
$
|
282.3
|
|
Receivable from broker for securities sold
|
5.5
|
|
|
|
|
|
|||
Interest and dividends receivable
|
2.8
|
|
|
|
|
|
|||
Payable to broker for securities purchased
|
(22.5
|
)
|
|
|
|
|
|||
Total Plan assets
|
$
|
574.0
|
|
|
|
|
|
(In millions)
|
December 31, 2011
|
Level 1
|
Level 3
|
||||||
Group retiree medical insurance contract (A)
|
$
|
54.3
|
|
$
|
—
|
|
$
|
54.3
|
|
Mutual funds investment
|
|
|
|
||||||
U.S. equity investments
|
5.3
|
|
5.3
|
|
—
|
|
|||
Money market funds investment
|
0.7
|
|
0.7
|
|
—
|
|
|||
Cash
|
0.7
|
|
0.7
|
|
—
|
|
|||
Total Plan investments
|
$
|
61.0
|
|
$
|
6.7
|
|
$
|
54.3
|
|
(In millions)
|
December 31, 2010
|
Level 1
|
Level 3
|
||||||
Group retiree medical insurance contract (A)
|
$
|
52.4
|
|
$
|
—
|
|
$
|
52.4
|
|
Mutual funds investment
|
|
|
|
||||||
U.S. equity investments
|
5.5
|
|
5.5
|
|
—
|
|
|||
Money market funds investment
|
0.6
|
|
0.6
|
|
—
|
|
|||
Total Plan investments
|
$
|
58.5
|
|
$
|
6.1
|
|
$
|
52.4
|
|
Year ended December 31
(In millions)
|
2011
|
||
Group retiree medical insurance contract
|
|
||
Beginning balance
|
$
|
52.4
|
|
Interest income
|
1.3
|
|
|
Net unrealized gains related to instruments held at the reporting date
|
0.9
|
|
|
Dividend income
|
0.8
|
|
|
Realized gains
|
0.1
|
|
|
Administrative expenses and charges
|
(0.1
|
)
|
|
Claims paid
|
(1.1
|
)
|
|
Ending balance
|
$
|
54.3
|
|
December 31
(In millions)
|
2011
|
2010
|
||||
Benefit obligations
|
$
|
(280.6
|
)
|
$
|
(337.1
|
)
|
Fair value of plan assets
|
61.0
|
|
58.5
|
|
||
Funded status at end of year
|
$
|
(219.6
|
)
|
$
|
(278.6
|
)
|
ONE-PERCENTAGE POINT INCREASE
|
|||||||||
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Effect on aggregate of the service and interest cost components
|
$
|
—
|
|
$
|
3.1
|
|
$
|
2.4
|
|
Effect on accumulated postretirement benefit obligations
|
0.1
|
|
0.7
|
|
40.3
|
|
ONE-PERCENTAGE POINT DECREASE
|
|||||||||
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
||||||
Effect on aggregate of the service and interest cost components
|
$
|
0.1
|
|
$
|
2.5
|
|
$
|
1.9
|
|
Effect on accumulated postretirement benefit obligations
|
0.6
|
|
1.6
|
|
32.9
|
|
(In millions)
|
Gross Projected
Postretirement Benefit Payments |
||
2012
|
$
|
15.4
|
|
2013
|
16.0
|
|
|
2014
|
16.9
|
|
|
2015
|
17.7
|
|
|
2016
|
18.3
|
|
|
2017 and Beyond
|
97.0
|
|
|
Pension Plan
|
Restoration of Retirement
Income Plan |
Postretirement
Benefit Plans |
|||||||||||||||
December 31
(In millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Change in Benefit Obligation
|
|
|
|
|
|
|
||||||||||||
Beginning obligations
|
$
|
(640.9
|
)
|
$
|
(610.9
|
)
|
$
|
(10.8
|
)
|
$
|
(8.3
|
)
|
$
|
(337.1
|
)
|
$
|
(288.0
|
)
|
Service cost
|
(17.6
|
)
|
(16.7
|
)
|
(1.0
|
)
|
(0.9
|
)
|
(3.5
|
)
|
(4.3
|
)
|
||||||
Interest cost
|
(33.3
|
)
|
(31.8
|
)
|
(0.6
|
)
|
(0.5
|
)
|
(12.5
|
)
|
(17.0
|
)
|
||||||
Plan amendments
|
—
|
|
—
|
|
—
|
|
—
|
|
91.4
|
|
—
|
|
||||||
Participants' contributions
|
—
|
|
—
|
|
—
|
|
—
|
|
(8.1
|
)
|
(7.3
|
)
|
||||||
Medicare subsidies received
|
—
|
|
—
|
|
—
|
|
—
|
|
(2.0
|
)
|
(1.4
|
)
|
||||||
Actuarial gains (losses)
|
(48.3
|
)
|
(15.9
|
)
|
(1.0
|
)
|
(1.5
|
)
|
(25.7
|
)
|
(36.6
|
)
|
||||||
Benefits paid
|
42.4
|
|
34.4
|
|
0.1
|
|
0.4
|
|
16.9
|
|
17.5
|
|
||||||
Ending obligations
|
$
|
(697.7
|
)
|
$
|
(640.9
|
)
|
$
|
(13.3
|
)
|
$
|
(10.8
|
)
|
$
|
(280.6
|
)
|
$
|
(337.1
|
)
|
|
|
|
|
|
|
|
||||||||||||
Change in Plans' Assets
|
|
|
|
|
|
|
||||||||||||
Beginning fair value
|
$
|
574.0
|
|
$
|
496.3
|
|
$
|
—
|
|
$
|
—
|
|
$
|
58.5
|
|
$
|
55.0
|
|
Actual return on plans' assets
|
8.2
|
|
62.1
|
|
—
|
|
—
|
|
2.7
|
|
5.2
|
|
||||||
Employer contributions
|
50.0
|
|
50.0
|
|
0.1
|
|
0.4
|
|
6.6
|
|
7.1
|
|
||||||
Participants' contributions
|
—
|
|
—
|
|
—
|
|
—
|
|
8.1
|
|
7.3
|
|
||||||
Medicare subsidies received
|
—
|
|
—
|
|
—
|
|
—
|
|
2.0
|
|
1.4
|
|
||||||
Benefits paid
|
(42.4
|
)
|
(34.4
|
)
|
(0.1
|
)
|
(0.4
|
)
|
(16.9
|
)
|
(17.5
|
)
|
||||||
Ending fair value
|
589.8
|
|
574.0
|
|
—
|
|
—
|
|
61.0
|
|
58.5
|
|
||||||
Funded status at end of year
|
$
|
(107.9
|
)
|
$
|
(66.9
|
)
|
$
|
(13.3
|
)
|
$
|
(10.8
|
)
|
$
|
(219.6
|
)
|
$
|
(278.6
|
)
|
|
Pension Plan
|
Restoration of Retirement
Income Plan |
Postretirement
Benefit Plans |
||||||||||||||||||||||||
Year ended December 31
(In millions)
|
2011
|
2010
|
2009
|
2011
|
2010
|
2009
|
2011
|
2010
|
2009
|
||||||||||||||||||
Service cost
|
$
|
17.6
|
|
$
|
16.7
|
|
$
|
18.1
|
|
$
|
1.0
|
|
$
|
0.9
|
|
$
|
0.7
|
|
$
|
3.5
|
|
$
|
4.3
|
|
$
|
3.3
|
|
Interest cost
|
33.3
|
|
31.8
|
|
31.4
|
|
0.6
|
|
0.5
|
|
0.4
|
|
12.5
|
|
17.0
|
|
14.1
|
|
|||||||||
Expected return on plan assets
|
(45.5
|
)
|
(42.4
|
)
|
(33.0
|
)
|
—
|
|
—
|
|
—
|
|
(5.1
|
)
|
(6.9
|
)
|
(6.5
|
)
|
|||||||||
Amortization of transition obligation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2.7
|
|
2.7
|
|
2.7
|
|
|||||||||
Amortization of net loss
|
19.2
|
|
21.3
|
|
23.5
|
|
0.4
|
|
0.3
|
|
0.3
|
|
18.3
|
|
12.1
|
|
5.0
|
|
|||||||||
Amortization of unrecognized prior service cost (A)
|
2.4
|
|
2.4
|
|
0.8
|
|
0.7
|
|
0.7
|
|
0.6
|
|
(16.5
|
)
|
—
|
|
1.0
|
|
|||||||||
Net periodic benefit cost (B)
|
$
|
27.0
|
|
$
|
29.8
|
|
$
|
40.8
|
|
$
|
2.7
|
|
$
|
2.4
|
|
$
|
2.0
|
|
$
|
15.4
|
|
$
|
29.2
|
|
$
|
19.6
|
|
•
|
an increase in pension expense in
2011
and
2010
of
$10.8 million
and
$8.1 million
,
respectively, and a reduction in pension expense in
2009
of
$2.2 million
to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);
|
•
|
a reduction in pension expense in
2009
of
$3.2 million
in the Arkansas jurisdiction to reflect the approval of recovery of OG&E's
2006
and
2007
pension settlement costs in the May
2009
Arkansas rate order which are included in the Pension tracker regulatory liability) (see Note 1); and
|
•
|
an increase in postretirement medical expense in
2011
of
$3.5 million
to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
|
|
Pension Plan and
Restoration of Retirement Income Plan |
Postretirement
Benefit Plans |
||||||||||
Year ended December 31
|
2011
|
2010
|
2009
|
2011
|
2010
|
2009
|
||||||
Discount rate
|
4.50
|
%
|
5.30
|
%
|
5.30
|
%
|
4.50
|
%
|
5.30
|
%
|
6.00
|
%
|
Rate of return on plans' assets
|
8.00
|
%
|
8.50
|
%
|
8.50
|
%
|
6.50
|
%
|
8.50
|
%
|
8.50
|
%
|
Compensation increases
|
4.40
|
%
|
4.40
|
%
|
4.50
|
%
|
N/A
|
|
N/A
|
|
N/A
|
|
Assumed health care cost trend:
|
|
|
|
|
|
|
|
|
|
|
|
|
Initial trend
|
N/A
|
|
N/A
|
|
N/A
|
|
8.75
|
%
|
8.99
|
%
|
9.49
|
%
|
Ultimate trend rate
|
N/A
|
|
N/A
|
|
N/A
|
|
4.48
|
%
|
5.00
|
%
|
5.00
|
%
|
Ultimate trend year
|
N/A
|
|
N/A
|
|
N/A
|
|
2028
|
|
2020
|
|
2018
|
|
15.
|
Report of Business Segments
|
2011
|
Electric Utility
|
Transportation and
Storage |
Gathering and Processing
|
Marketing
|
Other Operations
|
Eliminations
|
Total
|
||||||||||||||
(In millions)
|
|
|
|
|
|
|
|
||||||||||||||
Operating revenues
|
$
|
2,211.5
|
|
$
|
410.5
|
|
$
|
1,167.1
|
|
$
|
678.0
|
|
$
|
—
|
|
$
|
(551.2
|
)
|
$
|
3,915.9
|
|
Cost of goods sold
|
1,013.5
|
|
253.3
|
|
870.7
|
|
688.1
|
|
—
|
|
(547.7
|
)
|
2,277.9
|
|
|||||||
Gross margin on revenues
|
1,198.0
|
|
157.2
|
|
296.4
|
|
(10.1
|
)
|
—
|
|
(3.5
|
)
|
1,638.0
|
|
|||||||
Other operation and maintenance
|
436.0
|
|
46.5
|
|
111.8
|
|
7.3
|
|
(17.3
|
)
|
(3.1
|
)
|
581.2
|
|
|||||||
Depreciation and amortization
|
216.1
|
|
21.6
|
|
55.6
|
|
0.4
|
|
13.4
|
|
—
|
|
307.1
|
|
|||||||
Impairment of assets
|
—
|
|
—
|
|
6.3
|
|
—
|
|
—
|
|
—
|
|
6.3
|
|
|||||||
Gain on insurance proceeds
|
—
|
|
—
|
|
(3.0
|
)
|
—
|
|
—
|
|
—
|
|
(3.0
|
)
|
|||||||
Taxes other than income
|
73.6
|
|
14.7
|
|
7.0
|
|
0.3
|
|
4.1
|
|
—
|
|
99.7
|
|
|||||||
Operating income (loss)
|
$
|
472.3
|
|
$
|
74.4
|
|
$
|
118.7
|
|
$
|
(18.1
|
)
|
$
|
(0.2
|
)
|
$
|
(0.4
|
)
|
$
|
646.7
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Total assets
|
$
|
6,620.9
|
|
$
|
1,805.5
|
|
$
|
1,483.8
|
|
$
|
74.5
|
|
$
|
166.6
|
|
$
|
(1,245.3
|
)
|
$
|
8,906.0
|
|
Capital expenditures (A)
|
$
|
844.5
|
|
$
|
39.3
|
|
$
|
572.0
|
|
$
|
1.8
|
|
$
|
13.8
|
|
$
|
(0.6
|
)
|
$
|
1,470.8
|
|
2010
|
Electric Utility
|
Transportation and
Storage |
Gathering and Processing
|
Marketing
|
Other Operations
|
Eliminations
|
Total
|
||||||||||||||
(In millions)
|
|
|
|
|
|
|
|
||||||||||||||
Operating revenues
|
$
|
2,109.9
|
|
$
|
403.6
|
|
$
|
1,005.6
|
|
$
|
798.5
|
|
$
|
—
|
|
$
|
(600.7
|
)
|
$
|
3,716.9
|
|
Cost of goods sold
|
1,000.2
|
|
246.4
|
|
733.3
|
|
804.7
|
|
—
|
|
(597.2
|
)
|
2,187.4
|
|
|||||||
Gross margin on revenues
|
1,109.7
|
|
157.2
|
|
272.3
|
|
(6.2
|
)
|
—
|
|
(3.5
|
)
|
1,529.5
|
|
|||||||
Other operation and maintenance
|
418.1
|
|
48.9
|
|
91.5
|
|
8.4
|
|
(13.6
|
)
|
(3.5
|
)
|
549.8
|
|
|||||||
Depreciation and amortization
|
208.7
|
|
21.1
|
|
50.1
|
|
0.1
|
|
11.3
|
|
—
|
|
291.3
|
|
|||||||
Impairment of assets
|
—
|
|
0.7
|
|
0.4
|
|
—
|
|
—
|
|
—
|
|
1.1
|
|
|||||||
Taxes other than income
|
69.2
|
|
13.9
|
|
6.4
|
|
0.3
|
|
3.6
|
|
—
|
|
93.4
|
|
|||||||
Operating income (loss)
|
$
|
413.7
|
|
$
|
72.6
|
|
$
|
123.9
|
|
$
|
(15.0
|
)
|
$
|
(1.3
|
)
|
$
|
—
|
|
$
|
593.9
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Total assets
|
$
|
5,898.1
|
|
$
|
1,246.1
|
|
$
|
973.8
|
|
$
|
94.5
|
|
$
|
135.4
|
|
$
|
(678.8
|
)
|
$
|
7,669.1
|
|
Capital expenditures
|
$
|
631.6
|
|
$
|
70.2
|
|
$
|
164.0
|
|
$
|
2.4
|
|
$
|
14.1
|
|
$
|
(2.4
|
)
|
$
|
879.9
|
|
2009
|
Electric Utility
|
Transportation and
Storage |
Gathering and Processing
|
Marketing
|
Other Operations
|
Eliminations
|
Total
|
||||||||||||||
(In millions)
|
|
|
|
|
|
|
|
||||||||||||||
Operating revenues
|
$
|
1,751.2
|
|
$
|
401.0
|
|
$
|
657.5
|
|
$
|
619.9
|
|
$
|
—
|
|
$
|
(559.9
|
)
|
$
|
2,869.7
|
|
Cost of goods sold
|
796.3
|
|
239.9
|
|
458.8
|
|
617.7
|
|
—
|
|
(555.0
|
)
|
1,557.7
|
|
|||||||
Gross margin on revenues
|
954.9
|
|
161.1
|
|
198.7
|
|
2.2
|
|
—
|
|
(4.9
|
)
|
1,312.0
|
|
|||||||
Other operation and maintenance
|
348.0
|
|
40.9
|
|
87.2
|
|
9.2
|
|
(13.9
|
)
|
(4.6
|
)
|
466.8
|
|
|||||||
Depreciation and amortization
|
187.4
|
|
20.4
|
|
43.9
|
|
0.1
|
|
10.8
|
|
—
|
|
262.6
|
|
|||||||
Impairment of assets
|
0.3
|
|
0.9
|
|
1.9
|
|
—
|
|
—
|
|
—
|
|
3.1
|
|
|||||||
Taxes other than income
|
65.1
|
|
13.2
|
|
5.5
|
|
0.4
|
|
3.4
|
|
—
|
|
87.6
|
|
|||||||
Operating income (loss)
|
$
|
354.1
|
|
$
|
85.7
|
|
$
|
60.2
|
|
$
|
(7.5
|
)
|
$
|
(0.3
|
)
|
$
|
(0.3
|
)
|
$
|
491.9
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Total assets
|
$
|
5,478.1
|
|
$
|
1,159.5
|
|
$
|
866.1
|
|
$
|
125.2
|
|
$
|
137.3
|
|
$
|
(499.5
|
)
|
$
|
7,266.7
|
|
Capital expenditures
|
$
|
600.5
|
|
$
|
71.4
|
|
$
|
166.0
|
|
$
|
—
|
|
$
|
10.2
|
|
$
|
(0.3
|
)
|
$
|
847.8
|
|
16.
|
Commitments and Contingencies
|
Year ended December 31
(In millions)
|
2012
|
2013
|
2014
|
2015
|
2016
|
2017 and Beyond
|
Total
|
||||||||||||||
Operating lease obligations
|
|
|
|
|
|
|
|
||||||||||||||
OG&E railcars
|
$
|
2.9
|
|
$
|
2.9
|
|
$
|
2.8
|
|
$
|
2.7
|
|
$
|
27.4
|
|
$
|
—
|
|
$
|
38.7
|
|
Enogex noncancellable operating leases
|
3.9
|
|
3.0
|
|
2.4
|
|
2.4
|
|
2.2
|
|
0.6
|
|
14.5
|
|
|||||||
Total operating lease obligations
|
$
|
6.8
|
|
$
|
5.9
|
|
$
|
5.2
|
|
$
|
5.1
|
|
$
|
29.6
|
|
$
|
0.6
|
|
$
|
53.2
|
|
(In millions)
|
2012
|
2013
|
2014
|
2015
|
2016
|
Total
|
||||||||||||
Other purchase obligations and commitments
|
|
|
|
|
|
|
||||||||||||
OG&E cogeneration capacity and fixed operation and maintenance payments
|
$
|
90.3
|
|
$
|
89.4
|
|
$
|
87.3
|
|
$
|
85.2
|
|
$
|
83.3
|
|
$
|
435.5
|
|
OG&E expected cogeneration energy payments
|
59.3
|
|
68.9
|
|
81.3
|
|
74.2
|
|
86.8
|
|
370.5
|
|
||||||
OG&E minimum fuel purchase commitments
|
380.2
|
|
192.4
|
|
87.9
|
|
90.4
|
|
—
|
|
750.9
|
|
||||||
OG&E expected wind purchase commitments
|
32.4
|
|
32.8
|
|
33.3
|
|
34.0
|
|
34.7
|
|
167.2
|
|
||||||
OG&E long-term service agreement commitments
|
4.5
|
|
6.6
|
|
33.7
|
|
5.1
|
|
5.0
|
|
54.9
|
|
||||||
OER Cheyenne Plains commitments
|
5.3
|
|
6.5
|
|
6.5
|
|
1.6
|
|
—
|
|
19.9
|
|
||||||
OER MEP commitments
|
2.1
|
|
2.1
|
|
1.2
|
|
—
|
|
—
|
|
5.4
|
|
||||||
OER other commitments
|
4.9
|
|
3.1
|
|
3.1
|
|
3.1
|
|
0.7
|
|
14.9
|
|
||||||
Total other purchase obligations and commitments
|
$
|
579.0
|
|
$
|
401.8
|
|
$
|
334.3
|
|
$
|
293.6
|
|
$
|
210.5
|
|
$
|
1,819.2
|
|
Year ended December 31, 2011
(In millions)
|
2011
|
2010
|
2009
|
||||||
CPV Keenan
|
$
|
24.5
|
|
$
|
3.8
|
|
$
|
—
|
|
Edison Mission Energy
|
8.5
|
|
—
|
|
—
|
|
|||
FPL Energy
|
3.7
|
|
3.9
|
|
4.0
|
|
|||
Total wind power purchased
|
$
|
36.7
|
|
$
|
7.7
|
|
$
|
4.0
|
|
17.
|
Rate Matters and Regulation
|
18.
|
Quarterly Financial Data (Unaudited)
|
Quarter ended (
In millions, except per share data)
|
|
March 31
|
June 30
|
September 30
|
December 31
|
Total
|
||||||||||
Operating revenues
|
2011
|
$
|
840.5
|
|
$
|
978.1
|
|
$
|
1,212.1
|
|
$
|
885.2
|
|
$
|
3,915.9
|
|
|
2010
|
$
|
875.8
|
|
$
|
887.2
|
|
$
|
1,125.4
|
|
$
|
828.5
|
|
$
|
3,716.9
|
|
Operating income
|
2011
|
$
|
67.9
|
|
$
|
182.2
|
|
$
|
299.7
|
|
$
|
96.9
|
|
$
|
646.7
|
|
|
2010
|
$
|
86.8
|
|
$
|
151.5
|
|
$
|
274.2
|
|
$
|
81.4
|
|
$
|
593.9
|
|
Net income
|
2011
|
$
|
29.7
|
|
$
|
109.3
|
|
$
|
181.4
|
|
$
|
43.2
|
|
$
|
363.6
|
|
|
2010
|
$
|
25.2
|
|
$
|
77.9
|
|
$
|
163.5
|
|
$
|
33.8
|
|
$
|
300.4
|
|
Net income attributable to OGE Energy
|
2011
|
$
|
24.8
|
|
$
|
103.0
|
|
$
|
178.7
|
|
$
|
36.4
|
|
$
|
342.9
|
|
|
2010
|
$
|
24.2
|
|
$
|
77.3
|
|
$
|
163.1
|
|
$
|
30.7
|
|
$
|
295.3
|
|
Basic earnings per average common share attributable to OGE Energy common shareholders (A)
|
2011
|
$
|
0.25
|
|
$
|
1.05
|
|
$
|
1.82
|
|
$
|
0.37
|
|
$
|
3.50
|
|
|
2010
|
$
|
0.25
|
|
$
|
0.79
|
|
$
|
1.67
|
|
$
|
0.32
|
|
$
|
3.03
|
|
Diluted earnings per average common share attributable to OGE Energy common shareholders (A)
|
2011
|
$
|
0.25
|
|
$
|
1.04
|
|
$
|
1.80
|
|
$
|
0.37
|
|
$
|
3.45
|
|
|
2010
|
$
|
0.25
|
|
$
|
0.78
|
|
$
|
1.65
|
|
$
|
0.31
|
|
$
|
2.99
|
|
|
/s/ Ernst & Young LLP
|
|
|
Ernst & Young LLP
|
|
/s/ Peter B. Delaney
|
|
/s/ Scott Forbes
|
Peter B. Delaney, Chairman of the Board, President
|
|
Scott Forbes, Controller
|
and Chief Executive Officer
|
|
and Chief Accounting Officer
|
|
|
|
/s/ Sean Trauschke
|
|
|
Sean Trauschke, Vice President
|
|
|
and Chief Financial Officer
|
|
|
|
/s/ Ernst & Young LLP
|
|
|
Ernst & Young LLP
|
|
•
|
Consolidated
Statements of Income for the years ended December 31, 2011, 2010 and 2009
|
•
|
Consolidated
Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009
|
•
|
Consolidated
Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009
|
•
|
Consolidated
Balance Sheets at December 31, 2011 and 2010
|
•
|
Consolidated
Statements of Capitalization at December 31, 2011 and 2010
|
•
|
Consolidated
Statements of Changes in
Stockholders'
Equity for the years ended December 31, 2011, 2010 and 2009
|
•
|
Notes to
Consolidated
Financial Statements
|
•
|
Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
|
•
|
Management's Report on Internal Control Over Financial Reporting
|
•
|
Report of Independent Registered Public Accounting Firm (Audit of Internal Control)
|
•
|
Schedule II - Valuation and Qualifying Accounts
|
4.02
|
Supplemental Indenture No. 1 dated October 16, 1995, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed October 24, 1995 (File No. 1-1097) and incorporated by reference herein)
|
4.03
|
Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed July 17, 1997 (File No. 1-1097) and incorporated by reference herein)
|
4.04
|
Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed April 16, 1998 (File No. 1-1097) and incorporated by reference herein)
|
4.05
|
Supplemental Indenture No. 4, dated as of October 15, 2000, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed October 20, 2000 (File No. 1-1097) and incorporated by reference herein)
|
4.06
|
Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to Registration Statement No. 333-104615 and incorporated by reference herein)
|
4.07
|
Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein)
|
4.08
|
Indenture dated as of November 1, 2004 between OGE Energy Corp. and UMB Bank, N.A., as trustee. (Filed as Exhibit 4.01 to OGE Energy's Form 8-K filed November 12, 2004 (File No. 1-12579) and incorporated by reference herein)
|
4.09
|
Supplemental Indenture No. 1 dated as of November 9, 2004 between OGE Energy Corp. and UMB Bank, N.A., as trustee. (Filed as Exhibit 4.02 to OGE Energy's Form 8-K filed November 12, 2004 (File No. 1-12579) and incorporated by reference herein)
|
4.10
|
Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to OG&E's Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein)
|
4.11
|
Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein)
|
4.12
|
Supplemental Indenture No. 9 dated as of September 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed September 9, 2008 (File No. 1-1097) and incorporated by reference herein)
|
4.13
|
Supplemental Indenture No. 10 dated as of December 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2008 (File No. 1-1097) and incorporated by reference herein)
|
4.14
|
Issuing and Paying Agency Agreement dated as of June 15, 2009, by and between Enogex LLC and UMB Bank, N.A. (Filed as Exhibit 4.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12579) and incorporated by reference herein)
|
4.15
|
Issuing and Paying Agency Agreement dated as of November 15, 2009, by and between Enogex LLC and UMB Bank, N.A. (Filed as Exhibit 4.15 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein)
|
4.16
|
Supplemental Indenture No. 11 dated as of June 1, 2010 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed June 8, 2010 (File No. 1-1097) and incorporated by reference herein)
|
4.17
|
Supplemental Indenture No. 12 dated as of May 15, 2011 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 27, 2011 (File No. 1-1097) and incorporated by reference herein)
|
10.01*
|
The Company's 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy's Form 10-K for the year ended December 31, 1998 (File No. 1-12579) and incorporated by reference herein)
|
10.02*
|
The Company's 2003 Stock Incentive Plan. (Filed as Annex A to OGE Energy's Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)
|
10.03*
|
The Company's 2003 Annual Incentive Compensation Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)
|
10.04
|
Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed July 6, 2009 (File No. 1-12579) and incorporated by reference herein)
|
10.05
|
Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.06
|
Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.07
|
Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.08*
|
Amendment No. 1 to the Company's 2003 Stock Incentive Plan. (Filed as Exhibit 10.23 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.09
|
Intrastate Firm No-Notice, Load Following Transportation and Storage Services Agreement dated as of May 1, 2003 between OG&E and Enogex. [Confidential treatment has been requested for certain portions of this exhibit.] (Filed as Exhibit 10.24 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.10
|
Firm Transportation Service Agreement Rate Schedule FT dated as of December 1, 2004 between OGE Energy Resources, Inc. and Cheyenne Plains Gas Pipeline Company, L.L.C. (Filed as Exhibit 10.25 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.11*
|
Form of Performance Unit Agreement under 2008 Stock Incentive Plan. (Filed as Exhibit 10.02 to OGE Energy's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12579) and incorporated by reference herein)
|
10.12*
|
Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)
|
10.13
|
Credit agreement dated as of December 13, 2011, by and between OGE Energy, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed December 19, 2011 (File No. 1-12579) and incorporated by reference herein)
|
10.14
|
Credit agreement dated as of December 13, 2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed December 19, 2011 (File No. 1-12579) and incorporated by reference herein)
|
10.15*
|
Amendment No. 1 to the Company's 1998 Stock Incentive Plan. (Filed as Exhibit 10.26 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein)
|
10.16*
|
Amendment No. 2 to the Company's 2003 Stock Incentive Plan. (Filed as Exhibit 10.27 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein)
|
10.17
|
Capacity Lease Agreement dated as of December 11, 2006, by and between Enogex, Inc. and Midcontinent Express Pipeline LLC. [Confidential treatment has been requested for certain portions of this exhibit.] (Filed as Exhibit 10.30 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein)
|
10.18
|
Ownership and Operating Agreement, dated as of January 21, 2008, entered into by and among OG&E, the Oklahoma Municipal Power Authority and the Grand River Dam Authority. (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.19
|
Credit agreement dated as of December 13, 2011, by and between Enogex LLC, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.03 to OGE Energy's Form 8-K filed December 19, 2011 (File No. 1-12579) and incorporated by reference herein)
|
10.20*
|
Amendment No. 1 to the Company's 2003 Annual Incentive Compensation Plan. (Filed as Exhibit 10.02 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.21*
|
OGE Energy Corp. Supplemental Executive Retirement Plan, as amended and restated. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.22*
|
OGE Energy Corp. Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.23*
|
OGE Energy Corp. Deferred Compensation Plan, as amended and restated. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.24*
|
Amendment No. 3 to the Company's 2003 Stock Incentive Plan. (Filed as Exhibit 10.06 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.25*
|
Amendment No. 2 to the Company's 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.26*
|
The Company's 2008 Stock Incentive Plan. (Filed as Annex A to OGE Energy's Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)
|
10.27*
|
The Company's 2008 Annual Incentive Compensation Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)
|
10.28*
|
Form of Employment Agreement for all existing and future officers of the Company relating to change of control.
|
10.29*
|
Form of Restricted Stock Agreement under 2008 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended September 30, 2008 (File No. 1-12579) and incorporated by reference herein)
|
10.30
|
Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's OU Spirit application. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed December 2, 2009 (File No. 1-12579) and incorporated by reference herein)
|
10.31
|
Agreement, dated February 17, 2010, between Oklahoma Gas and Electric Company and Oklahoma Department of Environmental Quality. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein)
|
10.32*
|
Amendment No. 1 to the Company's Restoration of Retirement Income Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein)
|
10.33*
|
Amendment No. 1 to the Company's Deferred Compensation Plan.
|
10.34
|
Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 1, 2010 (File No. 1-12579) and incorporated by reference herein)
|
10.35
|
Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Crossroads application. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed July 1, 2010 (File No. 1-12579) and incorporated by reference herein)
|
10.36
|
Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 19, 2011 (File No. 1-12579) and incorporated by reference herein)
|
10.37
|
Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed June 28, 2011 (File No. 1-12579) and incorporated by reference herein)
|
10.38*
|
Amendment No. 2 to the Company's Deferred Compensation Plan. (Filed as Exhibit 10.41 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein)
|
10.39*
|
Amendment No. 3 to the Company's Deferred Compensation Plan.
|
10.40*
|
Amendment No. 1 to the Company's 2008 Stock Incentive Plan.
|
10.41*
|
Directors' Compensation.
|
10.42*
|
Executive Officer Compensation.
|
10.43*
|
Consulting Agreement between the Company and Danny P. Harris, the Company's retired Chief Operating Officer.
|
12.01
|
Calculation of Ratio of Earnings to Fixed Charges.
|
21.01
|
Subsidiaries of the Registrant.
|
23.01
|
Consent of Ernst & Young LLP.
|
24.01
|
Power of Attorney.
|
31.01
|
Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.01
|
Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
99.01
|
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995.
|
99.02
|
Copy of OCC order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed July 30, 2009 (File No. 1-12579) and incorporated by reference herein)
|
99.03
|
Copy of APSC order with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 22, 2011 (File No. 1-12579) and incorporated by reference herein)
|
99.04
|
Copy of OCC order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's OU Spirit application. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed October 21, 2009 (File No. 1-12579) and incorporated by reference herein)
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Additions
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||||||||
Description
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Balance at Beginning of Period
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Charged to Costs and Expenses
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Deductions (A)
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Balance at End of Period
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||||||||
(In millions)
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||||||||
Balance at December 31, 2009
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||||||||
Reserve for Uncollectible Accounts
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$
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3.2
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$
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3.1
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$
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3.9
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$
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2.4
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Balance at December 31, 2010
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||||||||
Reserve for Uncollectible Accounts
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$
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2.4
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$
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2.6
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$
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3.1
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$
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1.9
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Balance at December 31, 2011
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||||||||
Reserve for Uncollectible Accounts
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$
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1.9
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$
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5.8
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$
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3.9
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$
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3.8
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OGE ENERGY CORP.
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(Registrant)
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By
/s/
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Peter B. Delaney
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Peter B. Delaney
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Chairman of the Board, President
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and Chief Executive Officer
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Signature
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Title
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Date
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/s/ Peter B. Delaney
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Peter B. Delaney
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Principal Executive
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Officer and Director;
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February 16, 2012
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/s/ Sean Trauschke
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Sean Trauschke
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Principal Financial Officer; and
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February 16, 2012
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/s/ Scott Forbes
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Scott Forbes
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Principal Accounting Officer.
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February 16, 2012
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James H. Brandi
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Director;
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Wayne H. Brunetti
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Director;
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Luke R. Corbett
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Director;
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John D. Groendyke
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Director;
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Kirk Humphreys
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Director;
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Robert Kelley
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Director;
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Linda P. Lambert
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Director;
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Robert O. Lorenz
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Director;
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Judy R. McReynolds
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Director; and
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Leroy C. Richie
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Director.
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/s/ Peter B. Delaney
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By Peter B. Delaney (attorney-in-fact)
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February 16, 2012
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OGE ENERGY CORP.
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By
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Peter B. Delaney
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Chairman of the Board, President and Chief Executive Officer
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1
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Annual Incentive Compensation Plan
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2
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Stock Incentive Plan
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3
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OGE Energy Corp. Employees' Stock Ownership and Retirement Savings Plan
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4
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OGE Energy Corp. Deferred Compensation Plan
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5
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Retirement Plan
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6
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Restoration of Retirement Income Plan
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Amendment Number 1 to the
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OGE Energy Corp. Deferred Compensation Plan
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(As Amended and Restated Effective January 1, 2005)
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1.
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By d
e
leting
Section 2.32 of
the Plan
and
inserting in li
e
u thereof the
following:
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"2.3
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"
Valuation
Date
" means the last business day of
each calendar
month
and such
other dates
as
may
be specified
by the
Administrator;
provided
,
however
,
that for purpose of
Article VI (other
than Section 6.4)
only,
(i)
effective
January 1, 2006 through Sept
e
mber 30,
2008,
Valuation Date
shall also
mean
the
last busin
ess
day of
eac
h calendar
week
and (ii)
effec
tive Octob
e
r 1
,
2008, Valuation
D
ate s
hall m
ea
n
eac
h
day
th
e
New York
Stock
Exchange
is
open."
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2.
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By
d
e
l
e
ting th
e
first
sentence of Section
4.5
of
the
Plan and
inserting in lieu th
ereof t
he
following:
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3.
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By adding a
n
ew se
ntenc
e
after
th
e
second sentence of Section 6.1 of
the Plan
as follows:
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4.
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By deleting the third and fourth sentence of the
first
paragraph of Section 6.2 of
the
Plan and inserting in lieu
ther
eof
the
following:
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5.
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By deleting the last
se
nt
e
nc
e
of the
fi
rst
paragraph of Section 6.2 of the
Plan
an
d
inserting in lieu thereof the following:
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6.
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By deleting the
t
hird
se
nt
e
n
ce
of Section 6.3
o
f
th
e
Plan and
in
ser
tin
g
in
li
eu
thereof the following:
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Amendment Number 3 to the
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OGE Energy Corp. Deferred Compensation Plan
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(As Amended and Restated Effective January 1, 2005)
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Years of Service
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Percentage of
Matching Credits Vested |
Less than 3
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0%
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3 or more
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100%
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Amendment Number 1 to the
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OGE Energy Corp. 2008 Stock Incentive Plan
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Executive Officer
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2012 Base Salary
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Peter B. Delaney, Chairman, President and Chief Executive Officer
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$885,000
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Sean Trauschke, Vice President and Chief Financial Officer
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$478,400
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E. Keith Mitchell, President and Chief Operating Officer of Enogex Holdings; President of Enogex LLC
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$345,000
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Stephen E. Merrill, Chief Operating Officer of Enogex LLC
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$306,600
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CONSULTANT:
By:
_/s/ Danny P. Harris
Danny P. Harris
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COMPANY:
By:
__/s/ Peter B. Delaney________________
Peter B. Delaney, Chief Executive Officer
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Year ended December 31
(In millions)
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2007
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2008
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2009
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2010
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2011
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||||||||||
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||||||||||
Earnings:
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||||||||||
Pre-tax income
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$
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361.9
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$
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338.6
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$
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382.2
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$
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461.4
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$
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524.3
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Add: Fixed charges
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97.6
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130.0
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154.5
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150.1
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161.8
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|||||
Subtotal
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459.5
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468.6
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536.7
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611.5
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686.1
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|||||
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||||||||||
Subtract:
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||||||||||
Allowance for borrowed funds used during construction
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4.0
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4.0
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8.3
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5.5
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10.4
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|||||
Other capitalized interest
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0.9
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3.5
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6.3
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2.5
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8.7
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|||||
Total earnings
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454.6
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461.1
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522.1
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603.5
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667.0
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|||||
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||||||||||
Fixed Charges:
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||||||||||
Interest on long-term debt
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88.7
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106.6
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143.6
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141.8
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154.8
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|||||
Interest on short-term debt and other interest charges
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6.4
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21.0
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8.4
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5.9
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5.2
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|||||
Calculated interest on leased property
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2.5
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2.4
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2.5
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2.4
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1.8
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|||||
Total fixed charges
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$
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97.6
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$
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130.0
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$
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154.5
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$
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150.1
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$
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161.8
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||||||||||
Ratio of Earnings to Fixed Charges
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4.66
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3.55
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3.38
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4.02
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4.12
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Name of Subsidiary
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Jurisdiction of Incorporation
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Percentage of
Ownership
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Oklahoma Gas and Electric Company
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Oklahoma
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100.0
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OGE Enogex Holdings LLC
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Delaware
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100.0
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Enogex Holdings LLC
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Delaware
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81.3
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Enogex LLC
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Delaware
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81.3
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Enogex Gathering & Processing LLC
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Oklahoma
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81.3
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OGE Energy Resources LLC
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Oklahoma
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81.3
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Enogex Products LLC
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Oklahoma
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81.3
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Enogex Gas Gathering LLC
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Oklahoma
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81.3
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/s/ Ernst & Young LLP
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Ernst & Young LLP
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Peter B. Delaney, Chairman, Principal
Executive Officer and Director |
/s/
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Peter B. Delaney
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James H. Brandi, Director
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/s/
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James H. Brandi
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Wayne H. Brunetti, Director
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/s/
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Wayne H. Brunetti
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Luke R. Corbett, Director
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/s/
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Luke R. Corbett
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John D. Groendyke, Director
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/s/
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John D. Groendyke
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Kirk Humphreys, Director
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/s/
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Kirk Humphreys
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Robert Kelley, Director
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/s/
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Robert Kelley
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Linda P. Lambert, Director
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/s/
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Linda P. Lambert
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Robert O. Lorenz, Director
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/s/
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Robert O. Lorenz
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Judy R. McReynolds, Director
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/s/
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Judy R. McReynolds
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Leroy C. Richie, Director
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/s/
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Leroy C. Richie
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Sean Trauschke, Principal Financial Officer
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/s/
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Sean Trauschke
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Scott Forbes, Principal Accounting Officer
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/s/
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Scott Forbes
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STATE OF OKLAHOMA
|
)
|
|
|
)
|
SS
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COUNTY OF OKLAHOMA
|
)
|
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/s/ Kelly Hamilton-Coyer
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By: Kelly Hamilton-Coyer
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Notary Public
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/s/ Peter B. Delaney
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Peter B. Delaney
|
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Chairman of the Board, President and Chief Executive Officer
|
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/s/ Sean Trauschke
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Sean Trauschke
|
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Vice President and Chief Financial Officer
|
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/s/ Peter B. Delaney
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Peter B. Delaney
|
|
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Chairman of the Board, President and Chief Executive Officer
|
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/s/ Sean Trauschke
|
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Sean Trauschke
|
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Vice President and Chief Financial Officer
|
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•
|
Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, currency, interest rate and warranty risks;
|
•
|
Risks associated with PRM strategies intended to mitigate exposure to adverse movement in the prices of natural gas on both a global and regional basis, including commodity price changes, market supply shortages, interest rate changes and counterparty default;
|
•
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General economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures and our ability to access the capital markets, inflation rates and monetary fluctuations;
|
•
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Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services currently and in the future;
|
•
|
Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the FERC, state public utility commissions; the regional state committee which regulates the SPP; state entities which regulate natural gas transmission, gathering and processing and similar entities with regulatory oversight;
|
•
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Environmental laws, safety laws or other regulations passed by the EPA, the ODEQ or other governing agencies that may impact the cost of operations or restrict or change the way the Company operates its facilities;
|
•
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Availability or cost of capital, including changes in interest rates, market perceptions of the utility and energy-related industries, the Company or any of its subsidiaries or security ratings;
|
•
|
Employee workforce factors including changes in key executives and employee retention;
|
•
|
Social attitudes regarding the utility, natural gas and power industries;
|
•
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Identification of suitable investment opportunities to enhance shareowner returns and achieve long-term financial objectives through business acquisitions and divestitures;
|
•
|
Some future investments made by the Company could take the form of noncontrolling interests which would limit the Company's ability to control the development or operation of an investment;
|
•
|
Increased pension and healthcare costs;
|
•
|
Costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including but not limited to those described in Note 16 of Notes to Consolidated Financial Statements in this Form 10-K;
|
•
|
Technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
|
•
|
The cost of protecting assets against, or damage due to, terrorism or cyber attacks; and
|
•
|
Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents.
|
•
|
Increased competition in the utility industry, including effects of decreasing margins as a result of competitive pressures; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;
|
•
|
Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
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•
|
Rate-setting policies or procedures of regulatory entities, including environmental externalities;
|
•
|
Approval of future regulatory filings with the OCC or the APSC;
|
•
|
Whether OG&E can successfully implement its Smart Grid program to install meters for its customers and integrate the Smart Grid meters with its customer billing and other computer information systems; and
|
•
|
Discontinuance of accounting principles for certain types of rate-regulated activities.
|
•
|
Increased competition in the natural gas processing industry, including effects of decreasing margins as a result of competitive pressures, commodity exposure and nature of competitors entering the industry; and
|
•
|
Cold weather extremes that may impact the ability of producing customers to maintain gas deliveries, or the quality of such deliveries, into the pipeline system.
|