UNITED
STATES
|
SECURITIES
AND EXCHANGE COMMISSION
|
Washington,
D.C. 20549
|
FORM
10-K
|
(Mark
One)
|
x ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
For
the fiscal year ended December 31, 2009
|
OR
|
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
For
the transition period from _____to_____
|
Commission
File Number: 1-12579
|
OGE
ENERGY CORP.
|
||
(Exact
name of registrant as specified in its charter)
|
||
Oklahoma
|
73-1481638
|
|
(State
or other jurisdiction of
|
(I.R.S.
Employer
|
|
incorporation
or organization)
|
Identification
No.)
|
|
321
North Harvey
|
||
P.O.
Box 321
|
||
Oklahoma
City, Oklahoma 73101-0321
|
||
(Address
of principal executive offices)
|
||
(Zip
Code)
|
||
Registrant’s
telephone number, including area code: 405-553-3000
|
Securities
registered pursuant to Section 12(b) of the Act:
|
Title
of each
class
Common
Stock
Rights
to Purchase Series A Preferred Stock
|
Name of each exchange
on which registered
New
York Stock Exchange
New
York Stock Exchange
|
Securities
registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act.
Yes x No o
Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or 15(d)
of the Act.
Yes o No x
Indicate by check mark whether
the registrant (1) has filed all reports required to be filed by Section
13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements
for the past 90 days.Yes x No o
Indicate by check mark whether
the registrant has submitted electronically and posted on its corporate
Web site, if any, every Interactive Data File required to be submitted and
posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). o Yes o No
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this Chapter) is not contained herein, and
will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form
10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
Large
Accelerated Filer x Accelerated
Filer o
Non-Accelerated
Filer o (Do
not check if a smaller reporting
company) Smaller
reporting company o
Indicate by check mark whether
the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No x
At
June 30, 2009, the last business day of the registrant’s most recently
completed second fiscal quarter, the aggregate market value of shares of
common stock held by non-affiliates was $2,725,078,180 based on the number
of shares held by non-affiliates (96,224,512) and the reported closing
market price of the common stock on the New York Stock Exchange on such
date of $28.32.
At
January 31, 2010, 97,048,304 shares of common stock, par value $0.01 per
share, were outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
The Proxy Statement for the
Company’s 2010 annual meeting of shareowners is incorporated by reference
into Part III of this Form 10-K.
|
OGE
ENERGY CORP.
|
|
FORM
10-K
|
|
FOR
THE YEAR ENDED DECEMBER 31, 2009
|
|
TABLE
OF CONTENTS
|
|
Page
|
|
1
|
|
Item
1. Business
|
2
|
The
Company
|
2
|
Electric
Operations –
OG&E
|
4
|
4
|
|
Regulation
and
Rates
|
6
|
Rate
Structures
|
10
|
Fuel
Supply and
Generation
|
11
|
Natural Gas Pipeline Operations –
Enogex
|
12
|
Environmental
Matters
|
21
|
Finance and
Construction
|
24
|
Employees
|
27
|
Access to Securities and Exchange Commission
Filings
|
27
|
Item
1A. Risk
Factors
|
27
|
Item
1B. Unresolved Staff
Comments
|
38
|
Item
2. Properties
|
39
|
Item
3. Legal
Proceedings
|
41
|
Item
4. Submission of Matters to a Vote of
Security
Holders
|
44
|
44
|
|
Item
5. Market for Registrant’s Common
Equity, Related Stockholder Matters and Issuer Purchases
|
|
of
Equity
Securities
|
47
|
Item
6. Selected Financial
Data
|
49
|
Item
7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations
|
50
|
Item
7A. Quantitative and Qualitative Disclosures About Market
Risk
|
91
|
Item
8. Financial Statements and
Supplementary
Data
|
94
|
Item
9. Changes In and Disagreements with
Accountants on Accounting and Financial Disclosure
|
155
|
Item
9A. Controls and
Procedures
|
155
|
Item
9B. Other
Information
|
159
|
Item
10. Directors, Executive Officers and Corporate
Governance
|
159
|
Item
11. Executive
Compensation
|
159
|
Item
12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder
|
|
Matters
|
159
|
Item
13. Certain Relationships and Related Transactions,
and Director Independence
|
159
|
Item
14. Principal Accounting Fees and
Services
|
159
|
Item
15. Exhibits, Financial Statement
Schedules
|
159
|
167
|
Ÿ
|
general
economic conditions, including the availability of credit, access to
existing lines of credit, actions of rating agencies and their impact on
capital expenditures;
|
Ÿ
|
the
ability of OGE Energy Corp. (collectively, with its subsidiaries, the
“Company”) and its subsidiaries to access the capital markets and obtain
financing on favorable terms;
|
Ÿ
|
prices
and availability of electricity, coal, natural gas and natural gas
liquids, each on a stand-alone basis and in relation to each
other;
|
Ÿ
|
business
conditions in the energy and natural gas midstream
industries;
|
Ÿ
|
competitive
factors including the extent and timing of the entry of additional
competition in the markets served by the
Company;
|
Ÿ
|
unusual
weather;
|
Ÿ
|
availability
and prices of raw materials for current and future construction
projects;
|
Ÿ
|
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;
|
Ÿ
|
environmental
laws and regulations that may impact the Company’s
operations;
|
Ÿ
|
changes
in accounting standards, rules or
guidelines;
|
Ÿ
|
the
discontinuance of accounting principles for certain types of
rate-regulated activities;
|
Ÿ
|
creditworthiness
of suppliers, customers and other contractual
parties;
|
Ÿ
|
the
higher degree of risk associated with the Company’s nonregulated business
compared with the Company’s regulated utility business;
and
|
Ÿ
|
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.
|
Ÿ
|
in
January 2007, a 120 megawatt (“MW”) wind farm in northwestern Oklahoma
(“Centennial”) was placed in
service;
|
Ÿ
|
in
September 2008, OG&E purchased a 51 percent interest in the 1,230 MW
natural gas-fired, combined-cycle power generation facility in Luther,
Oklahoma (“Redbud Facility”);
|
Ÿ
|
in
2008, OG&E announced a “Positive Energy Smart Grid” initiative that
will empower customers to proactively manage their energy consumption
during periods of peak demand. As a result of the American
Recovery and Reinvestment Act of 2009 (“ARRA”) signed by the President
into law in February 2009, OG&E requested a $130 million grant from
the U.S. Department of Energy (“DOE”) in August 2009 to develop its Smart
Grid technology. In late October 2009, OG&E received
notification from the DOE that its grant had been accepted by the
DOE;
|
Ÿ
|
in
2008, OG&E began construction of a transmission line from Oklahoma
City, Oklahoma to Woodward, Oklahoma (“Windspeed”), which is a critical
first step to increased wind development in western
Oklahoma. This transmission line is expected to be in service
by April 2010;
|
Ÿ
|
in
June 2009, OG&E received SPP approval to build four 345 kV
transmission lines referred to as “Balanced Portfolio 3E”, which OG&E
expects to begin constructing in early 2010. These transmission
lines are expected to be in service between December 2012 and December
2014;
|
Ÿ
|
in
September 2009, OG&E signed power purchase agreements with two
developers who are to build two new wind farms, totaling 280 MWs, in
northwestern Oklahoma which OG&E intends to add to its
power-generation portfolio by the end of 2010. OG&E will
continue to evaluate renewable opportunities to add to its
power-generation portfolio in the
future;
|
Ÿ
|
in
November and December 2009, the individual turbines were placed in service
related to the OU Spirit wind project in western Oklahoma (“OU Spirit”),
which added 101 MWs of wind capacity to OG&E’s wind portfolio;
and
|
Ÿ
|
OG&E’s
construction initiative from 2010 to 2015 includes approximately $2.6
billion in major projects designed to expand capacity, enhance reliability
and improve environmental performance. This construction
initiative also includes strengthening and expanding the electric
transmission, distribution and substation systems and replacing aging
infrastructure.
|
Ÿ
|
expansions
on the east side of Enogex’s gathering system, primarily in the Woodford
Shale play in southeastern Oklahoma through construction of new facilities
and expansion of existing facilities and its interest in Atoka;
and
|
Ÿ
|
expansions
on the west side of Enogex’s gathering system, primarily in the Granite
Wash play, Woodford Shale play and Atoka play in western Oklahoma and the
Granite Wash play and Atoka play in the Wheeler County, Texas area, which
is located in the Texas Panhandle.
|
2009 vs. 2008
|
2008 vs. 2007
|
||||
Year ended December 31 (In millions)
|
2009
|
Decrease
|
2008
|
Increase
|
2007
|
System Sales (A)
|
25.9
|
(3.4)%
|
26.8
|
1.5%
|
26.4
|
(A)
|
Sales
are in millions of MWHs.
|
OKLAHOMA
GAS AND ELECTRIC COMPANY
|
|||||||||
CERTAIN
OPERATING STATISTICS
|
|||||||||
Year
ended December 31 (In
millions)
|
2009
|
2008
|
2007
|
||||||
ELECTRIC
ENERGY (Millions of
MWH)
|
|||||||||
Generation
(exclusive of station use)
|
25.0
|
25.7
|
23.8
|
||||||
Purchased
|
3.9
|
4.3
|
5.2
|
||||||
Total
generated and purchased
|
28.9
|
30.0
|
29.0
|
||||||
Company
use, free service and losses
|
(2.0)
|
(1.8)
|
(1.9)
|
||||||
Electric
energy sold
|
26.9
|
28.2
|
27.1
|
||||||
ELECTRIC
ENERGY SOLD (Millions of
MWH)
|
|||||||||
Residential
|
8.7
|
9.0
|
8.7
|
||||||
Commercial
|
6.4
|
6.5
|
6.3
|
||||||
Industrial
|
3.6
|
4.0
|
4.2
|
||||||
Oilfield
|
2.9
|
2.9
|
2.8
|
||||||
Public
authorities and street light
|
3.0
|
3.0
|
3.0
|
||||||
Sales
for resale
|
1.3
|
1.4
|
1.4
|
||||||
System
sales
|
25.9
|
26.8
|
26.4
|
||||||
Off-system
sales (A)
|
1.0
|
1.4
|
0.7
|
||||||
Total
sales
|
26.9
|
28.2
|
27.1
|
||||||
ELECTRIC
OPERATING REVENUES (In
millions)
|
|||||||||
Residential
|
$
|
717.9
|
$
|
751.2
|
$
|
706.4
|
|||
Commercial
|
439.8
|
479.0
|
450.1
|
||||||
Industrial
|
172.1
|
219.8
|
221.4
|
||||||
Oilfield
|
132.6
|
151.9
|
140.9
|
||||||
Public
authorities and street light
|
167.7
|
190.3
|
181.4
|
||||||
Sales
for resale
|
53.6
|
64.9
|
68.8
|
||||||
Provision
for rate refund
|
(0.6)
|
(0.4)
|
0.1
|
||||||
System
sales revenues
|
1,683.1
|
1,856.7
|
1,769.1
|
||||||
Off-system
sales revenues
|
31.8
|
68.9
|
35.1
|
||||||
Other
|
36.3
|
33.9
|
30.9
|
||||||
Total
operating revenues
|
$
|
1,751.2
|
$
|
1,959.5
|
$
|
1,835.1
|
|||
ACTUAL
NUMBER OF ELECTRIC CUSTOMERS (At end of
period)
|
|||||||||
Residential
|
665,344
|
659,829
|
653,369
|
||||||
Commercial
|
85,537
|
85,030
|
83,901
|
||||||
Industrial
|
3,056
|
3,086
|
3,142
|
||||||
Oilfield
|
6,437
|
6,424
|
6,324
|
||||||
Public
authorities and street light
|
16,124
|
15,670
|
15,446
|
||||||
Sales
for resale
|
52
|
49
|
52
|
||||||
Total
|
776,550
|
770,088
|
762,234
|
||||||
AVERAGE
RESIDENTIAL CUSTOMER SALES
|
|||||||||
Average
annual revenue
|
$
|
1,083.50
|
$
|
1,145.05
|
$
|
1,086.03
|
|||
Average
annual use (kilowatt-hour (“KWH”))
|
13,197
|
13,659
|
13,325
|
||||||
Average
price per KWH (cents)
|
$
|
8.21
|
$
|
8.38
|
$
|
8.15
|
Year
ended December 31
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||
Coal
|
$
|
1.65
|
$
|
1.11
|
$
|
1.10
|
$
|
1.10
|
$
|
0.98
|
|||||
Natural
Gas
|
$
|
4.02
|
$
|
8.40
|
$
|
6.77
|
$
|
7.10
|
$
|
8.76
|
|||||
Weighted Average
|
$
|
2.50
|
$
|
3.30
|
$
|
3.13
|
$
|
2.98
|
$
|
3.21
|
Ÿ
|
Fee-Based
Arrangements. Under these arrangements,
Enogex generally is paid a fixed cash 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. A sustained decline, however, 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, 2009,
these arrangements accounted for approximately 20 percent of Enogex’s
natural gas processed volumes.
|
Ÿ
|
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,
|
Ÿ
|
Keep-Whole
Arrangements. Enogex processes raw natural
gas to extract NGLs and returns to the producer the full gas equivalent
British thermal unit (“Btu”) 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 Btu value in
natural gas. At December 31, 2009, these arrangements accounted
for approximately 35 percent of Enogex’s natural gas processed
volumes.
|
Less than
|
|||||||||||||||
1 year
|
1-3 years
|
3-5 years
|
More than
|
||||||||||||
Total
|
(2010)
|
(2011-2012)
|
(2013-2014)
|
5 years
|
|||||||||||
OG&E Base Transmission
|
$
|
150
|
$
|
45
|
$
|
40
|
$
|
40
|
$
|
25
|
|||||
OG&E Base Distribution
|
1,320
|
235
|
430
|
435
|
220
|
||||||||||
OG&E Base Generation
|
205
|
30
|
70
|
70
|
35
|
||||||||||
OG&E Other
|
150
|
25
|
50
|
50
|
25
|
||||||||||
Total OG&E Base Transmission, Distribution,
|
|||||||||||||||
Generation and Other
|
1,825
|
335
|
590
|
595
|
305
|
||||||||||
OG&E Known and Committed Projects:
|
|||||||||||||||
Transmission Projects:
|
|||||||||||||||
Sunnyside-Hugo (345 kV)
|
120
|
30
|
90
|
---
|
---
|
||||||||||
Sooner-Rose Hill (345 kV)
|
65
|
10
|
55
|
---
|
---
|
||||||||||
Windspeed (345 kV)
|
25
|
25
|
---
|
---
|
---
|
||||||||||
Balanced Portfolio 3E Projects
|
300
|
10
|
170
|
120
|
---
|
||||||||||
Total Transmission Projects
|
510
|
75
|
315
|
120
|
---
|
||||||||||
Other Projects:
|
|||||||||||||||
Smart Grid Program (A)
|
230
|
40
|
120
|
60
|
10
|
||||||||||
System Hardening
|
35
|
20
|
15
|
---
|
---
|
||||||||||
OU Spirit
|
10
|
10
|
---
|
---
|
---
|
||||||||||
Other
|
30
|
20
|
10
|
---
|
---
|
||||||||||
Total Other Projects
|
305
|
90
|
145
|
60
|
10
|
||||||||||
Total OG&E Known and Committed Projects
|
815
|
165
|
460
|
180
|
10
|
||||||||||
Total OG&E (B)
|
2,640
|
500
|
1,050
|
775
|
315
|
||||||||||
Enogex (Base Maintenance and Known and Committed
|
|||||||||||||||
Projects)
|
355
|
135
|
85
|
90
|
45
|
||||||||||
OGE Energy and OERI
|
150
|
25
|
50
|
50
|
25
|
||||||||||
Total Consolidated
|
$
|
3,145
|
$
|
660
|
$
|
1,185
|
$
|
915
|
$
|
385
|
Ÿ
|
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;
|
Ÿ
|
develop
a baseline plan to prioritize the assessment of a covered pipeline
segment;
|
Ÿ
|
gather
data and identify and characterize applicable threats that could impact a
covered pipeline segment;
|
Ÿ
|
discover,
evaluate and remediate problems in accordance with the program
requirements;
|
Ÿ
|
continuously
improve all elements of the integrity
program;
|
Ÿ
|
continuously
perform preventative and mitigation
actions;
|
Ÿ
|
maintain
a quality assurance process and management-of-change process;
and
|
Ÿ
|
establish
a communication plan that addresses safety concerns raised by the DOT and
state agencies, including the periodic submission of performance documents
to the DOT.
|
Ÿ
|
damage
to pipelines and plants, related equipment and surrounding properties
caused by tornadoes, floods, earthquakes, fires and other natural
disasters and acts of terrorism;
|
Ÿ
|
inadvertent
damage from third parties, including construction, farm and utility
equipment;
|
Ÿ
|
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
|
Ÿ
|
fires
and explosions.
|
Ÿ
|
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;
|
Ÿ
|
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
|
Ÿ
|
our
debt levels may limit our flexibility in responding to changing business
and economic conditions.
|
2009
|
Unit
|
Station
|
||||||||||||||
Station
&
|
Year
|
Fuel
|
Unit
|
Capacity
|
Capability
|
Capability
|
||||||||||
Unit
|
Installed
|
Unit
Design Type
|
Capability
|
Run
Type
|
Factor
(A)
|
(MW)
|
(MW)
|
|||||||||
Muskogee
|
3
|
1956
|
Steam-Turbine
|
Gas
|
Base
Load
|
---
|
%
|
(B)
|
---
|
|||||||
4
|
1977
|
Steam-Turbine
|
Coal
|
Base
Load
|
51.3
|
%
|
505
|
|||||||||
5
|
1978
|
Steam-Turbine
|
Coal
|
Base
Load
|
69.4
|
%
|
517
|
|||||||||
6
|
1984
|
Steam-Turbine
|
Coal
|
Base
Load
|
63.8
|
%
|
502
|
1,524
|
||||||||
Seminole
|
1
|
1971
|
Steam-Turbine
|
Gas
|
Base
Load
|
23.1
|
%
|
491
|
||||||||
1GT
|
1971
|
Combustion-Turbine
|
Gas
|
Peaking
|
0.1
|
%
|
(C)
|
17
|
||||||||
2
|
1973
|
Steam-Turbine
|
Gas
|
Base
Load
|
22.7
|
%
|
494
|
|||||||||
3
|
1975
|
Steam-Turbine
|
Gas/Oil
|
Base
Load
|
18.3
|
%
|
502
|
1,504
|
||||||||
Sooner
|
1
|
1979
|
Steam-Turbine
|
Coal
|
Base
Load
|
68.4
|
%
|
522
|
||||||||
2
|
1980
|
Steam-Turbine
|
Coal
|
Base
Load
|
72.2
|
%
|
524
|
1,046
|
||||||||
Horseshoe
|
6
|
1958
|
Steam-Turbine
|
Gas/Oil
|
Base
Load
|
15.8
|
%
|
159
|
||||||||
Lake
|
7
|
1963
|
Combined
Cycle
|
Gas/Oil
|
Base
Load
|
19.2
|
%
|
227
|
||||||||
8
|
1969
|
Steam-Turbine
|
Gas
|
Base
Load
|
4.6
|
%
|
380
|
|||||||||
9
|
2000
|
Combustion-Turbine
|
Gas
|
Peaking
|
4.7
|
%
|
(C)
|
46
|
||||||||
10
|
2000
|
Combustion-Turbine
|
Gas
|
Peaking
|
4.3
|
%
|
(C)
|
46
|
858
|
|||||||
Mustang
|
1
|
1950
|
Steam-Turbine
|
Gas
|
Peaking
|
2.3
|
%
|
(C)
|
50
|
|||||||
2
|
1951
|
Steam-Turbine
|
Gas
|
Peaking
|
2.3
|
%
|
(C)
|
51
|
||||||||
3
|
1955
|
Steam-Turbine
|
Gas
|
Base
Load
|
9.9
|
%
|
113
|
|||||||||
4
|
1959
|
Steam-Turbine
|
Gas
|
Base
Load
|
13.6
|
%
|
253
|
|||||||||
5A
|
1971
|
Combustion-Turbine
|
Gas/Jet
Fuel
|
Peaking
|
0.6
|
%
|
(C)
|
32
|
||||||||
5B
|
1971
|
Combustion-Turbine
|
Gas/Jet
Fuel
|
Peaking
|
1.1
|
%
|
(C)
|
32
|
531
|
|||||||
Redbud
(D)
|
1
|
2003
|
Combined
Cycle
|
Gas
|
Base
Load
|
35.3
|
%
|
149
|
||||||||
2
|
2003
|
Combined
Cycle
|
Gas
|
Base
Load
|
45.4
|
%
|
147
|
|||||||||
3
|
2003
|
Combined
Cycle
|
Gas
|
Base
Load
|
43.9
|
%
|
148
|
|||||||||
4
|
2003
|
Combined
Cycle
|
Gas
|
Base
Load
|
46.6
|
%
|
145
|
589
|
||||||||
McClain
(E)
|
1
|
2001
|
Combined
Cycle
|
Gas
|
Base
Load
|
82.7
|
%
|
346
|
346
|
|||||||
Woodward
|
1
|
1963
|
Combustion-Turbine
|
Gas
|
Peaking
|
---
|
%
|
(B)
|
(C)
|
---
|
---
|
|||||
Enid
|
1
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
---
|
%
|
(B)
|
(C)
|
---
|
||||||
2
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
---
|
%
|
(B)
|
(C)
|
---
|
|||||||
3
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
0.2
|
%
|
(C)
|
11
|
||||||||
4
|
1965
|
Combustion-Turbine
|
Gas
|
Peaking
|
0.1
|
%
|
(C)
|
11
|
22
|
|||||||
Total
Generating Capability (all stations, excluding winds station)
|
6,420
|
|||||||||||||||
2009
|
Unit
|
Station
|
||||||||||||||
Year
|
Number
of
|
Fuel
|
Capacity
|
Capability
|
Capability
|
|||||||||||
Station
|
Installed
|
Location
|
Units
|
Capability
|
Factor
(A)
|
(MW)
|
(MW)
|
|||||||||
Centennial
|
2007
|
Woodward,
OK
|
80
|
Wind
|
34.2
|
%
|
1.5
|
120
|
||||||||
OU
Spirit (F)
|
2009
|
Woodward,
OK
|
44
|
Wind
|
---
|
%
|
2.3
|
101
|
||||||||
Total
Generating Capability (wind stations)
|
221
|
|||||||||||||||
(A) 2009
Capacity Factor = 2009 Net Actual Generation / (2009 Net Maximum Capacity
(Nameplate Rating in MWs) x Period Hours (8,760
Hours)).
|
||||||||||||||||
(B)
This unit did not demonstrate summer capability in 2009 as prescribed by
the SPP criteria.
|
||||||||||||||||
(C) Peaking
units are used when additional short-term capacity is
required.
|
||||||||||||||||
(D) The
original units at the Redbud Facility were installed in
2003. In September 2008, OG&E purchased a 51 percent
ownership interest in the Redbud Facility.
|
||||||||||||||||
(E)
Represents OG&E’s 77 percent ownership interest in the McClain
Plant.
|
||||||||||||||||
(F)
OU Spirit’s 44 turbines were placed into service in November and December
2009.
|
2009
Average Daily
|
Inlet
|
||||||||||
Processing
|
Year
|
Fuel
|
Inlet
Volumes
|
Capacity
|
|||||||
Plant
|
Installed
|
Type
of Plant
|
Capability
|
(MMcf/d)
|
(MMcf/d)
|
||||||
Calumet
(A)
|
1969
|
Lean
Oil
|
Gas/Electric
|
129
|
250
|
||||||
Cox
City (B)
|
1994
|
Cryogenic
|
Gas/Electric
|
162
|
180
|
||||||
Thomas
(A)
|
1981
|
Cryogenic
|
Gas
|
131
|
135
|
||||||
Clinton
(A)(C)
|
2009
|
Cryogenic
|
Electric
|
22
|
120
|
||||||
Roger
Mills (B)
|
2008
|
Refrigeration
|
Electric
|
42
|
100
|
||||||
Canute
(B)
|
1996
|
Cryogenic
|
Electric
|
55
|
60
|
||||||
Wetumka
(A)
|
1983
|
Cryogenic
|
Gas/Electric
|
47
|
60
|
||||||
Harrah
(A)
|
1994
|
Cryogenic
|
Gas/Electric
|
13
|
38
|
||||||
Atoka
(D)
|
2007
|
Refrigeration
|
Electric
|
16
|
20
|
||||||
Total
|
617
|
963
|
(A)
|
These
processing plants are located on property that Enogex owns in
fee.
|
(B)
|
These
processing plants are located on easements or leased property as described
above.
|
(C)
|
The
Clinton plant was placed in service in late October
2009.
|
(D)
|
This
processing plant is leased and located on property that Atoka owns in
fee.
|
Name
|
Age
|
Title
|
Peter
B. Delaney
|
56
|
Chairman
of the Board, President and Chief Executive Officer
|
-
OGE Energy Corp. and Chief Executive Officer - Enogex
LLC
|
||
Danny
P. Harris
|
54
|
Senior
Vice President and Chief Operating Officer - OGE Energy
|
Corp.
and President - Enogex LLC
|
||
Sean
Trauschke
|
42
|
Vice
President and Chief Financial Officer - OGE Energy Corp.
and
|
Chief
Financial Officer - Enogex LLC
|
||
Patricia
D. Horn
|
51
|
Vice
President - Governance and Environmental, Health &
Safety;
|
Corporate
Secretary - OGE Energy Corp.
|
||
Gary
D. Huneryager
|
59
|
Vice
President - Internal Audits - OGE Energy Corp.
|
S.
Craig Johnston
|
49
|
Vice
President - Strategic Planning and Marketing - OGE
Energy
|
Corp.
|
||
Jesse
B. Langston
|
47
|
Vice
President - Utility Commercial Operations - OG&E
|
Jean
C. Leger, Jr.
|
51
|
Vice
President - Utility Operations - OG&E
|
Cristina
F. McQuistion
|
45
|
Vice
President - Process and Performance Improvement -
|
OGE
Energy Corp.
|
||
Stephen
E. Merrill
|
45
|
Vice
President - Human Resources - OGE Energy Corp.
|
E.
Keith Mitchell
|
47
|
Senior
Vice President and Chief Operating Officer - Enogex
LLC
|
Howard
W. Motley
|
61
|
Vice
President - Regulatory Affairs - OG&E
|
Reid
V. Nuttall
|
52
|
Vice
President - Chief Information Officer - OGE Energy
Corp.
|
Melvin
H. Perkins, Jr.
|
61
|
Vice
President - Power Delivery - OG&E
|
Paul
L. Renfrow
|
53
|
Vice
President - Public Affairs - OGE Energy Corp.
|
John
Wendling, Jr.
|
53
|
Vice
President - Power Supply - OG&E
|
Max
J. Myers
|
35
|
Treasurer
- OGE Energy Corp.
|
Scott
Forbes
|
52
|
Controller
and Chief Accounting Officer - OGE Energy Corp.
|
Jerry
A. Peace
|
47
|
Chief
Risk Officer - OGE Energy Corp.
|
Name
|
Business
Experience
|
Peter
B. Delaney
|
2007
– Present:
|
Chairman
of the Board, President and Chief Executive Officer
|
of
OGE Energy Corp. and OG&E
|
||
2005
– Present:
|
Chief
Executive Officer of Enogex LLC
|
|
2007:
|
President
and Chief Operating Officer of OGE Energy Corp.
|
|
and
OG&E
|
||
2005
– 2007:
|
Executive
Vice President and Chief Operating Officer of OGE
|
|
Energy
Corp. and OG&E
|
||
2005:
|
President
of Enogex Inc.
|
|
Danny
P. Harris
|
2007
– Present:
|
Senior
Vice President and Chief Operating Officer of OGE
|
Energy
Corp. and OG&E and President of Enogex LLC
|
||
2005
– 2007:
|
Senior
Vice President of OGE Energy Corp. and President and
|
|
Chief
Operating Officer of Enogex Inc.
|
||
2005:
|
Vice
President and Chief Operating Officer of Enogex Inc.
|
|
Sean
Trauschke
|
2009
– Present:
|
Vice
President and Chief Financial Officer of OGE Energy
|
Corp.
and OG&E and Chief Financial Officer of Enogex LLC
|
||
2007
– 2009:
|
Senior
Vice President – Investor Relations and Financial
Planning
|
|
of
Duke Energy
|
||
2006
– 2007:
|
Vice
President – Investor Relations of Duke Energy
|
|
2005
– 2006:
|
Vice
President and Chief Risk Officer of Duke Energy (electric
utility)
|
|
Patricia
D. Horn
|
2010
– Present:
|
Vice
President – Governance and Environmental, Health &
Safety;
|
Corporate
Secretary of OGE Energy Corp. and OG&E
|
||
2005
– 2010:
|
Vice
President – Legal, Regulatory and Environmental Health
&
|
|
Safety,
General Counsel and Secretary of Enogex LLC
|
||
2005
– 2010:
|
Assistant
General Counsel of OGE Energy Corp.
|
|
Gary
D. Huneryager
|
2005
– Present:
|
Vice
President – Internal Audits of OGE Energy Corp. and
|
OG&E
|
||
2005:
|
Internal
Audit Officer of OGE Energy Corp. and OG&E
|
|
S.
Craig Johnston
|
2007
– Present:
|
Vice
President – Strategic Planning and Marketing of OGE
|
Energy
Corp. and OG&E
|
||
2005
– 2007:
|
Senior
Vice President of Worldwide Oil & Gas Markets of
Air
|
|
Liquide
(industrial gases company)
|
||
Jesse
B. Langston
|
2006
– Present:
|
Vice
President – Utility Commercial Operations of OG&E
|
2005
– 2006:
|
Director
– Utility Commercial Operations of OG&E
|
|
2005:
|
Director
– Corporate Planning of OG&E
|
|
Jean
C. Leger, Jr.
|
2008
– Present:
|
Vice
President – Utility Operations of OG&E
|
2005
– 2008:
|
Vice
President of Operations of Enogex LLC
|
|
2005:
|
Director
of Field Operations of Enogex Inc.
|
|
Cristina
F. McQuistion
|
2008
– Present:
|
Vice
President – Process and Performance Improvement of
|
OGE
Energy Corp. and OG&E
|
||
2007
– 2008:
|
Executive
Vice President and General Manager Point of Sale
|
|
Systems
of Teleflora
|
||
2005
– 2007:
|
Executive
Vice President – Member Services of Teleflora
|
|
(floral
industry and software services to floral industry
company)
|
||
Stephen
E. Merrill
|
2009
– Present:
|
Vice
President – Human Resources of OGE Energy Corp. and
OG&E
|
2007
– 2009:
|
Vice
President and Chief Financial Officer of Enogex LLC
|
|
2006
– 2007:
|
Vice
President and Chief Financial Officer of Cayenne
|
|
Drilling,
LLC and Sunstone Energy Group LLC (oil and gas
|
||
company)
|
||
2005
– 2006:
|
Director
of U.S. Operations at Plains All-American Pipeline L.P.
|
|
(natural
gas pipeline company)
|
Name
|
Business
Experience
|
E.
Keith Mitchell
|
2007
– Present:
|
Senior
Vice President and Chief Operating Officer of Enogex
LLC
|
2007:
|
Senior
Vice President of Enogex Inc.
|
|
2005
– 2007:
|
Vice
President – Transportation Services of Enogex Inc.
|
|
Howard
W. Motley
|
2006
– Present:
|
Vice
President – Regulatory Affairs of OG&E
|
2005
– 2006:
|
Director
– Regulatory Affairs and Strategy of OG&E
|
|
Reid
V. Nuttall
|
2009
– Present:
|
Vice
President – Chief Information Officer of OGE Energy
Corp.
|
and
OG&E
|
||
2006
– 2009:
|
Vice
President – Enterprise Information and Performance of
|
|
OGE
Energy Corp. and OG&E
|
||
2005
– 2006:
|
Vice
President – Enterprise Architecture of National Oilwell
|
|
Varco
(oil and gas equipment company)
|
||
2005:
|
Chief
Information Officer, Vice President – Information
|
|
Technology
of Varco International (oil and gas equipment
|
||
company)
|
||
Melvin
H. Perkins, Jr.
|
2007
– Present:
|
Vice
President – Power Delivery of OG&E
|
2005
– 2007:
|
Vice
President – Transmission of OG&E
|
|
Paul
L. Renfrow
|
2005
– Present:
|
Vice
President – Public Affairs of OGE Energy Corp. and
OG&E
|
2005:
|
Director
– Public Affairs of OGE Energy Corp. and OG&E
|
|
John
Wendling, Jr.
|
2007
– Present:
|
Vice
President – Power Supply of OG&E
|
2005
– 2007:
|
Director
– Power Plant Operations of OG&E
|
|
2005:
|
Plant
Manager – Sooner Power Plant of OG&E
|
|
Max
J. Myers
|
2009
– Present:
|
Treasurer
of OGE Energy Corp. and OG&E
|
2008:
|
Managing
Director of Corporate Development and Finance of
|
|
OGE
Energy Corp. and OG&E
|
||
2005
– 2008:
|
Manager
of Corporate Development of OGE Energy Corp.
|
|
and
OG&E
|
||
2005:
|
Director
of Corporate Finance and Development of Westar
|
|
Energy,
Inc. (electric utility)
|
||
Scott
Forbes
|
2005
– Present:
|
Controller
and Chief Accounting Officer of OGE Energy Corp.
|
and
OG&E
|
||
2008 – 2009:
|
Interim
Chief Financial Officer of OGE Energy Corp. and
OG&E
|
|
2005:
|
Chief
Financial Officer of First Choice Power (retail
electric
|
|
provider)
|
||
2005:
|
Senior
Vice President and Chief Financial Officer of Texas
|
|
New
Mexico Power Company (electric utility)
|
||
Jerry
A. Peace
|
2008
– Present:
|
Chief
Risk Officer of OGE Energy Corp. and OG&E
|
2005
– 2008:
|
Chief
Risk Officer and Compliance Officer of OGE Energy Corp.
|
|
and
OG&E
|
Dividend
|
Price
|
||||||||
2010
|
Paid
|
High
|
Low
|
||||||
First
Quarter (through January 31)
|
$
|
0.3625
|
$
|
37.92
|
$
|
35.50
|
Dividend
|
Price
|
||||||||
2009
|
Paid
|
High
|
Low
|
||||||
First
Quarter
|
$
|
0.3550
|
$
|
26.80
|
$
|
19.70
|
|||
Second
Quarter
|
0.3550
|
28.55
|
23.19
|
||||||
Third
Quarter
|
0.3550
|
33.72
|
26.50
|
||||||
Fourth
Quarter
|
0.3550
|
37.79
|
31.66
|
Dividend
|
Price
|
||||||||
2008
|
Paid
|
High
|
Low
|
||||||
First
Quarter
|
$
|
0.3475
|
$
|
36.23
|
$
|
29.83
|
|||
Second
Quarter
|
0.3475
|
34.02
|
30.61
|
||||||
Third
Quarter
|
0.3475
|
34.74
|
29.67
|
||||||
Fourth
Quarter
|
0.3475
|
31.41
|
19.56
|
Ÿ
|
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 the common stock,
premiums on capital stock (restricted to premiums on common stock only by
Securities and Exchange Commission orders), and surplus accounts is less
than 20 percent of capitalization;
|
Ÿ
|
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
|
Ÿ
|
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.
|
Approximate
Dollar
|
||||||||
Total
Number of
|
Value
of Shares that
|
|||||||
Shares
Purchased as
|
May
Yet Be
|
|||||||
Total
Number of
|
Average
Price Paid
|
Part
of Publicly
|
Purchased
Under the
|
|||||
Period
|
Shares
Purchased
|
per
Share
|
Announced
Plan
|
Plan
|
||||
1/1/09
– 1/31/09
|
81,300
|
$
|
25.33
|
N/A
|
N/A
|
|||
2/1/09
– 2/28/09
|
145,200
|
$
|
23.55
|
N/A
|
N/A
|
|||
3/1/09
– 3/31/09
|
75,900
|
$
|
22.93
|
N/A
|
N/A
|
|||
4/1/09
– 4/30/09
|
121,500
|
$
|
24.13
|
N/A
|
N/A
|
|||
5/1/09
– 5/31/09
|
53,800
|
$
|
26.18
|
N/A
|
N/A
|
|||
6/1/09
– 6/30/09
|
86,800
|
$
|
26.85
|
N/A
|
N/A
|
|||
7/1/09
– 7/31/09
|
142,600
|
$
|
28.70
|
N/A
|
N/A
|
|||
8/1/09
– 8/31/09
|
61,700
|
$
|
31.39
|
N/A
|
N/A
|
|||
9/1/09
– 9/30/09
|
17,800
|
$
|
31.39
|
N/A
|
N/A
|
|||
10/1/09
– 10/31/09
|
130,200
|
$
|
33.88
|
N/A
|
N/A
|
|||
11/1/09
– 11/30/09
|
55,900
|
$
|
33.42
|
N/A
|
N/A
|
|||
12/1/09
– 12/31/09
|
53,000
|
$
|
36.14
|
N/A
|
N/A
|
Year ended December 31
|
2009 (A)
|
2008
|
2007
|
2006
|
2005
|
||||||||||
SELECTED FINANCIAL DATA
|
|||||||||||||||
(In millions, except per share data)
|
|||||||||||||||
|
|||||||||||||||
Results of Operations Data:
|
|||||||||||||||
Operating revenues
|
$
|
2,869.7
|
$
|
4,070.7
|
$
|
3,797.6
|
$
|
4,005.6
|
$
|
5,911.5
|
|||||
Cost of goods sold
|
1,557.7
|
2,818.0
|
2,634.7
|
2,902.5
|
4,942.3
|
||||||||||
Gross margin on revenues
|
1,312.0
|
1,252.7
|
1,162.9
|
1,103.1
|
969.2
|
||||||||||
Other operating expenses
|
820.1
|
790.6
|
707.6
|
670.4
|
646.8
|
||||||||||
Operating income
|
491.9
|
462.1
|
455.3
|
432.7
|
322.4
|
||||||||||
Interest income
|
1.4
|
6.7
|
2.1
|
6.2
|
3.5
|
||||||||||
Allowance for equity funds used during construction
|
15.1
|
---
|
---
|
4.1
|
---
|
||||||||||
Other income (loss)
|
27.5
|
15.4
|
17.4
|
16.3
|
(0.3)
|
||||||||||
Other expense
|
16.3
|
25.6
|
22.7
|
16.7
|
5.5
|
||||||||||
Interest expense
|
137.4
|
120.0
|
90.2
|
96.0
|
90.3
|
||||||||||
Income tax expense
|
121.1
|
101.2
|
116.7
|
120.5
|
68.6
|
||||||||||
Income from continuing operations
|
261.1
|
237.4
|
245.2
|
226.1
|
161.2
|
||||||||||
Income from discontinued operations, net of tax
|
---
|
---
|
---
|
36.0
|
49.8
|
||||||||||
Net income
|
261.1
|
237.4
|
245.2
|
262.1
|
211.0
|
||||||||||
Less: Net income attributable to noncontrolling interest
|
2.8
|
6.0
|
1.0
|
---
|
---
|
||||||||||
Net income attributable to OGE Energy
|
$
|
258.3
|
$
|
231.4
|
$
|
244.2
|
$
|
262.1
|
$
|
211.0
|
|||||
Basic earnings per average common share attributable
|
|||||||||||||||
to OGE Energy common shareholders
|
|||||||||||||||
Income from continuing operations
|
$
|
2.68
|
$
|
2.50
|
$
|
2.66
|
$
|
2.48
|
$
|
1.79
|
|||||
Income from discontinued operations, net of tax
|
---
|
---
|
---
|
0.40
|
0.55
|
||||||||||
Net income attributable to OGE Energy common
|
|||||||||||||||
shareholders
|
$
|
2.68
|
$
|
2.50
|
$
|
2.66
|
$
|
2.88
|
$
|
2.34
|
|||||
Diluted earnings per average common share attributable
|
|||||||||||||||
to OGE Energy common shareholders
|
|||||||||||||||
Income from continuing operations
|
$
|
2.66
|
$
|
2.49
|
$
|
2.64
|
$
|
2.45
|
$
|
1.77
|
|||||
Income from discontinued operations, net of tax
|
---
|
---
|
---
|
0.39
|
0.55
|
||||||||||
Net income attributable to OGE Energy common
|
|||||||||||||||
shareholders
|
$
|
2.66
|
$
|
2.49
|
$
|
2.64
|
$
|
2.84
|
$
|
2.32
|
|||||
Dividends declared per share
|
$
|
1.4275
|
$
|
1.3975
|
$
|
1.3675
|
$
|
1.3375
|
$
|
1.33
|
|||||
Balance Sheet Data (at period end):
|
|||||||||||||||
Property, plant and equipment, net
|
$
|
5,911.6
|
$
|
5,249.8
|
$
|
4,246.3
|
$
|
3,867.5
|
$
|
3,567.4
|
|||||
Total assets
|
$
|
7,266.7
|
$
|
6,518.5
|
$
|
5,237.8
|
$
|
4,898.4
|
$
|
4,871.4
|
|||||
Long-term debt
|
$
|
2,088.9
|
$
|
2,161.8
|
$
|
1,344.6
|
$
|
1,346.3
|
$
|
1,350.8
|
|||||
Total stockholders’ equity
|
$
|
2,060.8
|
$
|
1,914.0
|
$
|
1,691.6
|
$
|
1,603.8
|
$
|
1,375.7
|
|||||
CAPITALIZATION RATIOS (B)
|
|||||||||||||||
Stockholders’ equity
|
46.4%
|
47.0%
|
55.7%
|
54.3%
|
50.5%
|
||||||||||
Long-term debt
|
53.6%
|
53.0%
|
44.3%
|
45.7%
|
49.5%
|
||||||||||
RATIO OF EARNINGS TO
|
|||||||||||||||
FIXED CHARGES (C)
|
|||||||||||||||
Ratio of earnings to fixed charges
|
3.38
|
3.50
|
4.65
|
4.28
|
3.37
|
(A) Effective
January 1, 2009, the Company changed the presentation of the Atoka
noncontrolling interest in the Company’s consolidated financial statements
related to the adoption of a new accounting principle and restated prior
periods for consistency.
(B) Capitalization
ratios = [Total stockholders’ equity / (Total stockholders’ equity +
Long-term debt + Long-term debt due within one year)] and [(Long-term debt
+ Long-term debt due within one year) / (Total stockholders’ equity +
Long-term debt + Long-term debt due within one year)].
(C) For
purposes of computing the ratio of earnings to fixed charges, (i) earnings
consist of pre-tax income from continuing operations plus fixed charges,
less allowance for borrowed funds used during construction and other
capitalized interest and (ii) fixed charges consist of interest on
long-term debt, related amortization, interest on short-term borrowings
and a calculated portion of rents considered to be interest.
|
Ÿ
|
in
January 2007, a 120 megawatt (“MW”) wind farm in northwestern Oklahoma was
placed in service;
|
Ÿ
|
in
September 2008, OG&E purchased a 51 percent interest in the 1,230 MW
natural gas-fired, combined-cycle power generation facility in Luther,
Oklahoma (“Redbud Facility”);
|
Ÿ
|
in
2008, OG&E announced a “Positive Energy Smart Grid” initiative that
will empower customers to proactively manage their energy consumption
during periods of peak demand. As a result of the American
Recovery and Reinvestment Act of 2009 (“ARRA”) signed by the President
into law in February 2009, OG&E requested a $130 million grant from
the U.S. Department of Energy (“DOE”) in August 2009 to develop its Smart
Grid technology. In late October 2009, OG&E received
notification from the DOE that its grant had been accepted by the
DOE;
|
Ÿ
|
in
2008, OG&E began construction of a transmission line from Oklahoma
City, Oklahoma to Woodward, Oklahoma (“Windspeed”), which is a critical
first step to increased wind development in western
Oklahoma. This transmission line is expected to be in service
by April 2010;
|
Ÿ
|
in
June 2009, OG&E received Southwest Power Pool (“SPP”) approval to
build four 345 kilovolt (“kV”) transmission lines referred to as “Balanced
Portfolio 3E”, which OG&E expects to begin constructing in early
2010. These transmission lines are expected to be in service
between December 2012 and December
2014;
|
Ÿ
|
in
September 2009, OG&E signed power purchase agreements with two
developers who are to build two new wind farms, totaling 280 MWs, in
northwestern Oklahoma which OG&E intends to add to its
power-generation portfolio by the end of 2010. OG&E will
continue to evaluate renewable opportunities to add to its
power-generation portfolio in the
future;
|
Ÿ
|
in
November and December 2009, the individual turbines were placed in service
related to the OU Spirit wind project in western Oklahoma (“OU Spirit”),
which added 101 MWs of wind capacity to OG&E’s wind portfolio;
and
|
Ÿ
|
OG&E’s
construction initiative from 2010 to 2015 includes approximately $2.6
billion in major projects designed to expand capacity, enhance reliability
and improve environmental performance. This construction
initiative also includes strengthening and expanding the electric
transmission, distribution and substation systems and replacing aging
infrastructure.
|
Ÿ
|
expansions
on the east side of Enogex’s gathering system, primarily in the Woodford
Shale play in southeastern Oklahoma through construction of new facilities
and expansion of existing facilities and its interest in Atoka;
and
|
Ÿ
|
expansions
on the west side of Enogex’s gathering system, primarily in the Granite
Wash play, Woodford Shale play and Atoka play in western Oklahoma and the
Granite Wash play and Atoka play in the Wheeler County, Texas area, which
is located in the Texas Panhandle.
|
Ÿ
|
net
income at OG&E of approximately $200.4 million in 2009 as compared to
approximately $143.0 million in 2008, which was an increase in net income
of approximately $57.4 million, or $0.52 per diluted share of the
Company’s common stock, in 2009 as compared to 2008 primarily due to a
higher gross margin on revenues (“gross margin”), primarily due to rate
increases and riders partially offset by milder weather and lower demand
and related revenues by non-residential customers, and a higher allowance
for equity funds used during construction (“AEFUDC”) partially offset by
higher depreciation and amortization expense, higher interest expense and
higher income tax expense;
|
Ÿ
|
net
income at Enogex of approximately $66.3 million in 2009 as compared to
approximately $91.2 million in 2008, which was a decrease in net income of
approximately $24.9 million, or $0.30 per diluted share of the Company’s
common stock, in 2009 as compared 2008 primarily due to a lower gross
margin, primarily due to lower processing spreads, lower NGLs prices and
lower natural gas prices, and higher depreciation and amortization expense
partially offset by lower operation and maintenance expense and lower
income tax expense;
|
Ÿ
|
net
loss at OGE Energy of approximately $3.3 million in 2009 as compared to
approximately $7.2 million in 2008, which was an improvement of
approximately $3.9 million, or $0.05 per diluted share of the Company’s
common stock, in 2009 as compared to 2008 primarily due to lower operation
and maintenance expense resulting from lower transaction costs associated
with terminated transactions of approximately $8.8 million and a lower
income tax benefit partially offset by lower other income due to receiving
life insurance proceeds in 2008 from the death of one of the Company’s
directors in 2008 and higher depreciation and amortization expense;
and
|
Ÿ
|
net
loss at OERI of approximately $5.1 million in 2009 as compared to net
income of approximately $4.4 million in 2008, which was a decrease in net
income of approximately $9.5 million, or $0.10 per diluted share of the
Company’s common stock, in 2009 as compared to 2008 primarily due to a
lower gross margin
|
Ÿ
|
net
income at OG&E of approximately $143.0 million in 2008 as compared to
approximately $161.7 million in 2007, which was a decrease in net income
of approximately $18.7 million, or $0.21 per diluted share of the
Company’s common stock, in 2008 as compared to 2007 primarily due to
higher operation and maintenance expense, higher depreciation and
amortization expense, higher other expense and higher interest expense
partially offset by a higher gross margin due to increased rates from
various regulatory riders implemented in 2008 and lower income tax
expense;
|
Ÿ
|
net
income at Enogex of approximately $91.2 million in 2008 as compared to
approximately $86.2 million in 2007, which was an increase in net income
of approximately $5.0 million, or $0.05 per diluted share of the Company’s
common stock, in 2008 as compared to 2007 primarily due to a higher gross
margin partially offset by higher operation and maintenance expense,
higher depreciation and amortization expense, lower interest income,
higher other expense and higher income tax expense. Net income
for Enogex in 2007 included net income of approximately $10.9 million, or
$0.12 per diluted share, attributable to
OERI;
|
Ÿ
|
net
income at OERI of approximately $4.4 million, or $0.05 per diluted share
of the Company’s common stock, in 2008;
and
|
Ÿ
|
net
loss at OGE Energy of approximately $7.2 million in 2008 as compared to
approximately $3.7 million in 2007, which was an increase in the net loss
of approximately $3.5 million, or $0.03 per diluted share of the Company’s
common stock, in 2008 as compared to 2007 primarily due to higher
operation and maintenance expense related to the 2008 write-off of
transaction costs incurred related to the proposed joint venture between
OGE Energy and Energy Transfer Partners, L.P. that was terminated and
transaction costs associated with the formation of OGE Enogex Partners,
L.P. of approximately $8.8 million, partially offset by lower interest
expense due to lower advances from subsidiaries, higher other income due
to receiving life insurance proceeds in 2008 from the death of one of the
Company’s directors in 2008 and a higher income tax benefit due to a
higher net loss.
|
Ÿ
|
Between
98 million and 99 million average diluted shares
outstanding;
|
Ÿ
|
An
effective tax rate of approximately 29 percent;
and
|
Ÿ
|
A
projected loss at the holding company between $7 million and $9 million,
or $0.07 to $0.09 per diluted share, primarily due to interest expense
relating to long and short-term debt borrowings and an anticipated loss at
OERI primarily due to a transportation contract
agreement.
|
Ÿ
|
Normal
weather patterns are experienced for the
year;
|
Ÿ
|
Gross
margin on revenues of approximately $1.05 billion to $1.06
billion. The key assumptions for gross margin are listed
below:
|
Ÿ
|
Sales
growth of approximately 0.9 percent on a weather adjusted basis;
and
|
Ÿ
|
The
Windspeed transmission line is in service with the rider effective April
1, 2010;
|
Ÿ
|
Operating
expenses of approximately $655 million to $665 million, with operation and
maintenance expenses comprising approximately 60 percent of
total;
|
Ÿ
|
Interest
expense of approximately $105 million to $115 million, which assumes
approximately $250 million of additional long-term debt issued by OG&E
in mid-2010;
|
Ÿ
|
AEFUDC
income of approximately $5 million;
and
|
Ÿ
|
An
effective tax rate of approximately 27
percent.
|
Ÿ
|
Total
Enogex anticipated gross margin of approximately $370 million to $400
million. The gross margin assumption
includes:
|
Ÿ
|
Transportation
and storage gross margin contribution of approximately $150 million to
$160 million, of which approximately 20 percent is attributable to the
storage business;
|
Ÿ
|
Gathering
and processing gross margin contribution of approximately $220 million to
$240 million, with equal contributions to gross margin from each
business;
|
Ÿ
|
Key
factors affecting the gathering and processing gross margin forecast
are:
|
Ÿ
|
Assumed
increase of five to seven percent in gathered volumes over
2009;
|
Ÿ
|
Assumed
increase of 10 to 12 percent in inlet processing volumes over
2009;
|
Ÿ
|
At
the midpoint of Enogex’s gathering and processing assumption Enogex has
included:
|
Ÿ
|
Realized
commodity spreads of $4.78 per Million British thermal unit (“MMBtu”) in
2010. The realized commodity spread takes into account that the
majority of non-ethane processing volumes that bear price risk are hedged
and the amortized cost of the hedges is included in the realized commodity
spread calculation. Every 10 percent change in commodity spreads from
$4.78 per MMBtu changes net income by approximately $4.0 million on an
annual basis assuming all other margins remain
static;
|
Ÿ
|
Natural
gas price of $5.28 per MMBtu in
2010;
|
Ÿ
|
Realized
weighted average NGLs price of $0.93 per gallon in 2010;
and
|
Ÿ
|
Realized
condensate spread of $7.81 per MMBtu in
2010;
|
Ÿ
|
Operating
expenses of approximately $220 million to $230 million, with operation and
maintenance expenses comprising approximately 60 percent of
total;
|
Ÿ
|
Interest
expense of approximately $30 million to $35 million;
and
|
Ÿ
|
An
effective tax rate of approximately 39
percent.
|
Twelve
Months Ended
|
|||
(In
millions)
|
December
31, 2010 (A)
|
||
Net
Income Attributable to Enogex LLC
|
$
|
74.0
|
|
Add:
|
|||
Interest
expense, net
|
33.0
|
||
Income
tax expense
|
49.0
|
||
Depreciation
and amortization
|
69.0
|
||
EBITDA
|
$
|
225.0
|
Year
ended December 31 (In
millions, except per share data)
|
2009
|
2008
|
2007
|
||||||
Operating
income
|
$
|
491.9
|
$
|
462.1
|
$
|
455.3
|
|||
Net
income attributable to OGE Energy
|
$
|
258.3
|
$
|
231.4
|
$
|
244.2
|
|||
Basic
average common shares outstanding
|
96.2
|
92.4
|
91.7
|
||||||
Diluted
average common shares outstanding
|
97.2
|
92.8
|
92.5
|
||||||
Basic
earnings per average common share attributable to
|
|||||||||
OGE
Energy common shareholders
|
$
|
2.68
|
$
|
2.50
|
$
|
2.66
|
|||
Diluted
earnings per average common share attributable to
|
|||||||||
OGE
Energy common shareholders
|
$
|
2.66
|
$
|
2.49
|
$
|
2.64
|
|||
Dividends
declared per share
|
$
|
1.4275
|
$
|
1.3975
|
$
|
1.3675
|
Operating
Income (Loss) by Business Segment
|
|||||||||
Year
ended December 31 (In
millions)
|
2009
|
2008
|
2007
|
||||||
OG&E
(Electric Utility)
|
$
|
354.1
|
$
|
278.3
|
$
|
292.0
|
|||
Enogex
(Natural Gas Pipeline)
|
|||||||||
Transportation and storage
|
85.7
|
67.8
|
55.0
|
||||||
Gathering and processing
|
60.2
|
117.4
|
91.4
|
||||||
OERI
(Natural Gas Marketing) (A)
|
(7.5)
|
6.4
|
17.1
|
||||||
Other
Operations (B)
|
(0.6)
|
(7.8)
|
(0.2)
|
||||||
Consolidated
operating income
|
$
|
491.9
|
$
|
462.1
|
$
|
455.3
|
Year
ended December 31 (Dollars in
millions)
|
2009
|
2008
|
2007
|
||||||
Operating
revenues
|
$
|
1,751.2
|
$
|
1,959.5
|
$
|
1,835.1
|
|||
Cost
of goods sold
|
796.3
|
1,114.9
|
1,025.1
|
||||||
Gross
margin on revenues
|
954.9
|
844.6
|
810.0
|
||||||
Other
operation and maintenance
|
348.0
|
351.6
|
320.7
|
||||||
Depreciation
and amortization
|
187.4
|
155.0
|
141.3
|
||||||
Impairment
of assets
|
0.3
|
---
|
---
|
||||||
Taxes
other than income
|
65.1
|
59.7
|
56.0
|
||||||
Operating
income
|
354.1
|
278.3
|
292.0
|
||||||
Interest
income
|
1.1
|
4.4
|
---
|
||||||
Allowance
for equity funds used during construction
|
15.1
|
---
|
---
|
||||||
Other
income
|
20.4
|
3.6
|
5.0
|
||||||
Other
expense
|
6.7
|
11.8
|
7.2
|
||||||
Interest
expense
|
93.6
|
79.1
|
54.9
|
||||||
Income
tax expense
|
90.0
|
52.4
|
73.2
|
||||||
Net
income
|
$
|
200.4
|
$
|
143.0
|
$
|
161.7
|
|||
Operating
revenues by classification
|
|||||||||
Residential
|
$
|
717.9
|
$
|
751.2
|
$
|
706.4
|
|||
Commercial
|
439.8
|
479.0
|
450.1
|
||||||
Industrial
|
172.1
|
219.8
|
221.4
|
||||||
Oilfield
|
132.6
|
151.9
|
140.9
|
||||||
Public
authorities and street light
|
167.7
|
190.3
|
181.4
|
||||||
Sales
for resale
|
53.6
|
64.9
|
68.8
|
||||||
Provision
for rate refund
|
(0.6)
|
(0.4)
|
0.1
|
||||||
System
sales revenues
|
1,683.1
|
1,856.7
|
1,769.1
|
||||||
Off-system
sales revenues (A)
|
31.8
|
68.9
|
35.1
|
||||||
Other
|
36.3
|
33.9
|
30.9
|
||||||
Total
operating revenues
|
$
|
1,751.2
|
$
|
1,959.5
|
$
|
1,835.1
|
|||
MWH
(B) sales by classification (in millions)
|
|||||||||
Residential
|
8.7
|
9.0
|
8.7
|
||||||
Commercial
|
6.4
|
6.5
|
6.3
|
||||||
Industrial
|
3.6
|
4.0
|
4.2
|
||||||
Oilfield
|
2.9
|
2.9
|
2.8
|
||||||
Public
authorities and street light
|
3.0
|
3.0
|
3.0
|
||||||
Sales
for resale
|
1.3
|
1.4
|
1.4
|
||||||
System
sales
|
25.9
|
26.8
|
26.4
|
||||||
Off-system
sales
|
1.0
|
1.4
|
0.7
|
||||||
Total
sales
|
26.9
|
28.2
|
27.1
|
||||||
Number
of customers
|
776,550
|
770,088
|
762,234
|
||||||
Average
cost of energy per KWH (C) - cents
|
|||||||||
Natural
gas
|
3.696
|
8.455
|
6.872
|
||||||
Coal
|
1.747
|
1.153
|
1.143
|
||||||
Total
fuel
|
2.474
|
3.337
|
3.173
|
||||||
Total
fuel and purchased power
|
2.760
|
3.710
|
3.523
|
||||||
Degree
days (D)
|
|||||||||
Heating
- Actual
|
3,456
|
3,394
|
3,175
|
||||||
Heating
- Normal
|
3,631
|
3,650
|
3,631
|
||||||
Cooling
- Actual
|
1,860
|
2,081
|
2,221
|
||||||
Cooling
- Normal
|
1,911
|
1,912
|
1,911
|
||||||
(A) Sales
to other utilities and power marketers.
(B) Megawatt-hour.
(C) Kilowatt-hour.
(D)
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.
|
Ÿ
|
increased
price variance, which included revenues from various rate riders,
including the Redbud Facility rider, the storm cost recovery rider, the
system hardening rider, the OU Spirit rider and the Oklahoma demand
program rider, and higher revenues from the sales and customer mix, which
increased the gross margin by approximately $89.5
million;
|
Ÿ
|
the
$48.3 million Oklahoma rate increase in which the majority of the annual
increase is recovered during the summer months, which increased the gross
margin by approximately $28.6
million;
|
Ÿ
|
revenues
from the Arkansas rate increase, which increased the gross margin by
approximately $9.3 million;
|
Ÿ
|
new
customer growth in OG&E’s service territory, which increased the gross
margin by approximately $8.1 million;
and
|
Ÿ
|
increased
transmission revenues due to higher transmission volumes and increased
rates due to the FERC formula rate tariff filing, which increased the
gross margin by approximately $1.8
million.
|
Ÿ
|
milder
weather in OG&E’s service territory, which decreased the gross margin
by approximately $18.2 million; and
|
Ÿ
|
lower
demand and related revenues by non-residential customers in OG&E’s
service territory, which decreased the gross margin by approximately $8.1
million.
|
Ÿ
|
a
decrease of approximately $13.2 million in contract technical and
construction services attributable to decreased spending on overhauls at
some of OG&E’s power plants in 2009 as compared to 2008 and
utilization of employees instead of contracting external
labor;
|
Ÿ
|
a
decrease of approximately $9.5 million due to a correction of the
over-capitalization of certain payroll, benefits, other employee related
costs and overhead costs in previous years in March 2008, as discussed in
Note 12 of Notes to Consolidated Financial
Statements;
|
Ÿ
|
an
increase in capitalized labor in 2009 as compared to 2008, which decreased
other operation and maintenance expenses by approximately $7.7
million;
|
Ÿ
|
a
decrease of approximately $3.8 million in fleet transportation expense
primarily due to lower fuel costs in 2009;
and
|
Ÿ
|
a
decrease of approximately $3.2 million due to the reclassification of 2006
and 2007 pension settlement costs to a regulatory asset due to the
Arkansas rate case settlement, as discussed in Note 1 of Notes to
Consolidated Financial Statements.
|
Ÿ
|
an
increase of approximately $11.8 million in salaries and wages expense
primarily due to salary increases in 2009 and increased incentive
compensation expense in 2009;
|
Ÿ
|
an
increase of approximately $7.2 million due to increased spending on
vegetation management related to system hardening, which expenses are
being recovered through a rider;
|
Ÿ
|
an
increase of approximately $5.4 million in pension
expense;
|
Ÿ
|
an
increase of approximately $3.3 million due to OG&E’s demand-side
management initiatives, which expenses are being recovered through a
rider;
|
Ÿ
|
an
increase of approximately $2.2 million in medical and dental expenses;
and
|
Ÿ
|
an
increase of approximately $2.2 million in materials and supplies
expense.
|
Ÿ
|
an
increase of approximately $29.2 million in interest expense related to the
issuances of long-term debt in 2008;
and
|
Ÿ
|
an
increase of approximately $2.0 million in interest expense due to interest
to customers related to the fuel over recovery balance in
2009.
|
Ÿ
|
a
decrease in interest expense of approximately $8.9 million related to
interest on short-term debt primarily due to lower short-term borrowings
in 2009 due to the issuances of long-term debt by OG&E in
2008;
|
Ÿ
|
a
decrease in interest expense of approximately $4.3 million primarily due
to a higher allowance for borrowed funds used during construction for
capitalized interest; and
|
Ÿ
|
a
decrease in interest expense of approximately $2.4 million due to the
settlement of treasury lock agreements OG&E entered into related to
the issuance of long-term debt by OG&E in January
2008.
|
Ÿ
|
new
revenues from the Redbud Facility rider and the storm cost recovery rider,
which increased the gross margin by approximately $21.1
million;
|
Ÿ
|
new
customer growth in OG&E’s service territory, which increased the gross
margin by approximately $8.4 million;
and
|
Ÿ
|
increased
demand and related revenues by non-residential customers in OG&E’s
service territory, which increased the gross margin by approximately $5.0
million.
|
Ÿ
|
a
decrease in capitalized work of approximately $14.0 million primarily
related to costs related to the 2007 ice storm that were deferred as a
regulatory asset;
|
Ÿ
|
an
increase of approximately $9.5 million due to a correction of the
over-capitalization of certain payroll, benefits, other employee related
costs and overhead costs in previous years in March 2008, as discussed in
Note 12 of Notes to Consolidated Financial
Statements;
|
Ÿ
|
an
increase of approximately $6.9 million in salaries and wages expense
primarily due to hiring additional employees to support OG&E’s
operations as well as salary increases in
2008;
|
Ÿ
|
an
increase of approximately $6.6 million in contract technical and
construction services expense and approximately $1.5 million in materials
and supplies expense primarily attributable to overhaul expenses at
several of OG&E’s power plants in
2008;
|
Ÿ
|
an
increase of approximately $5.3 million due to increased spending on
vegetation management;
|
Ÿ
|
an
increase of approximately $2.2 million in fleet transportation expense
primarily due to higher fuel and maintenance costs in 2008;
and
|
Ÿ
|
an
increase of approximately $1.3 million in professional services expense
primarily due to higher engineering consulting services in 2008 as
compared to 2007.
|
Ÿ
|
lower
allocations from OGE Energy of approximately $9.0 million due to lower
pension and medical expenses and lower incentive compensation
accruals;
|
Ÿ
|
a
decrease of approximately $4.0 million primarily due to overtime worked
during the 2007 ice storm; and
|
Ÿ
|
a
decrease of approximately $3.0 million due to lower bad debt
expense.
|
Ÿ
|
an
increase of approximately $16.4 million in interest expense related to the
issuances of long-term debt in
2008;
|
Ÿ
|
an
increase of approximately $7.2 million due to a settlement with the
Internal Revenue Service (“IRS”) resulting in a reversal of interest
expense in 2007; and
|
Ÿ
|
an
increase of approximately $2.9 million in interest expense related to
interest on short-term debt primarily due to increased commercial paper
borrowings and revolving credit borrowings to fund the purchase of the
Redbud Facility and daily operational needs of the
Company.
|
Transportation
|
Gathering
|
|||||||||||
and
|
and
|
|||||||||||
Year
Ended December 31, 2009
|
Storage
|
Processing
|
Eliminations
|
Total
|
||||||||
(In
millions)
|
||||||||||||
Operating
revenues
|
$
|
401.0
|
$
|
657.5
|
$
|
(207.6)
|
$
|
850.9
|
||||
Cost
of goods sold
|
239.9
|
458.8
|
(207.6)
|
491.1
|
||||||||
Gross
margin on revenues
|
161.1
|
198.7
|
---
|
359.8
|
||||||||
Other
operation and maintenance
|
40.9
|
87.2
|
---
|
128.1
|
||||||||
Depreciation
and amortization
|
20.4
|
43.9
|
---
|
64.3
|
||||||||
Impairment
of assets
|
0.9
|
1.9
|
---
|
2.8
|
||||||||
Taxes
other than income
|
13.2
|
5.5
|
---
|
18.7
|
||||||||
Operating
income
|
$
|
85.7
|
$
|
60.2
|
$
|
---
|
$
|
145.9
|
Transportation
|
Gathering
|
||||||||||||
and
|
and
|
||||||||||||
Year
Ended December 31, 2008
|
Storage
|
Processing
|
Eliminations
|
Total
|
|||||||||
(In
millions)
|
|||||||||||||
Operating
revenues
|
$
|
625.9
|
$
|
1,053.2
|
$
|
(575.9)
|
$
|
1,103.2
|
|||||
Cost
of goods sold
|
479.7
|
806.4
|
(575.9)
|
710.2
|
|||||||||
Gross
margin on revenues
|
146.2
|
246.8
|
---
|
393.0
|
|||||||||
Other
operation and maintenance
|
48.2
|
87.3
|
---
|
135.5
|
|||||||||
Depreciation
and amortization
|
17.5
|
37.1
|
---
|
54.6
|
|||||||||
Impairment
of assets
|
---
|
0.4
|
---
|
0.4
|
|||||||||
Taxes
other than income
|
12.7
|
4.6
|
---
|
17.3
|
|||||||||
Operating
income
|
$
|
67.8
|
$
|
117.4
|
$
|
---
|
$
|
185.2
|
Transportation
|
Gathering
|
||||||||||||||
and
|
and
|
||||||||||||||
Year
Ended December 31, 2007
|
Storage
|
Processing
|
Marketing
|
Eliminations
|
Total
|
||||||||||
(In
millions)
|
|||||||||||||||
Operating
revenues
|
$
|
529.1
|
$
|
799.4
|
$
|
1,541.2
|
$
|
(804.5)
|
$
|
2,065.2
|
|||||
Cost
of goods sold
|
396.4
|
603.5
|
1,513.4
|
(801.2)
|
1,712.1
|
||||||||||
Gross
margin on revenues
|
132.7
|
195.9
|
27.8
|
(3.3)
|
353.1
|
||||||||||
Other
operation and maintenance
|
48.5
|
72.1
|
10.1
|
(3.3)
|
127.4
|
||||||||||
Depreciation
and amortization
|
17.0
|
28.7
|
0.2
|
---
|
45.9
|
||||||||||
Impairment
of assets
|
0.5
|
---
|
---
|
---
|
0.5
|
||||||||||
Taxes
other than income
|
11.7
|
3.7
|
0.4
|
---
|
15.8
|
||||||||||
Operating
income
|
$
|
55.0
|
$
|
91.4
|
$
|
17.1
|
$
|
---
|
$
|
163.5
|
Year
Ended December 31
|
2009
|
2008
|
2007
|
||||||
Gathered
volumes – TBtu/d (A)
|
1.25
|
1.16
|
1.05
|
||||||
Incremental
transportation volumes – TBtu/d (B)
|
0.54
|
0.41
|
0.47
|
||||||
Total
throughput volumes – TBtu/d
|
1.79
|
1.57
|
1.52
|
||||||
Natural
gas processed – TBtu/d
|
0.70
|
0.66
|
0.57
|
||||||
Natural
gas liquids sold (keep-whole) – million gallons
|
110
|
181
|
252
|
||||||
Natural
gas liquids sold (purchased for resale) – million gallons
|
351
|
222
|
117
|
||||||
Natural
gas liquids sold (percent-of-liquids) – million gallons
|
32
|
23
|
16
|
||||||
Total
natural gas liquids sold – million gallons
|
493
|
426
|
385
|
||||||
Average
sales price per gallon
|
$
|
0.770
|
$
|
1.255
|
$
|
1.048
|
|||
Estimated
realized keep-whole spreads (C)
|
$
|
4.12
|
$
|
6.15
|
$
|
5.35
|
Ÿ
|
new
capacity lease service under the MEP and Gulf Crossing capacity leases
that were placed into service in the second quarter of 2009 that increased
transportation fees by approximately $10.3
million;
|
Ÿ
|
implementation
of the new Section 311 firm East side service during the second quarter of
2009 that increased transportation fees by approximately $4.2
million;
|
Ÿ
|
completion
of the Bennington compressor station which increased take away capacity
from the Enogex system and higher demand for crosshaul services as
shippers bid up rates to move natural gas on the Enogex system during the
first half of the 2009 that increased transportation fees by approximately
$3.0 million, net of approximately $1.6 million for a potential rate
refund pending the FERC approval of Enogex
rates;
|
Ÿ
|
higher
seasonal spread values resulted in higher realized margins on operational
storage hedges in 2009 as compared to 2008 that increased storage revenues
by approximately $2.6 million;
|
Ÿ
|
increased
value of storage capacity due to the natural gas price volatility and
seasonal spread values that increased storage fees by approximately $1.7
million;
|
Ÿ
|
an
approximate 8.6 percent volume increase primarily due to volumes from
gathering expansion projects that increased transportation fees by
approximately $1.4 million; and
|
Ÿ
|
lower
natural gas market prices and reduced injection and withdrawal activity
reduced the valuation of the storage field losses by approximately $1.3
million.
|
Ÿ
|
lower
natural gas market prices resulting in the recognition of a lower of cost
or market adjustment to the natural gas storage inventory of approximately
$5.8 million in 2009 as compared to an adjustment of approximately $0.7
million in 2008, which decreased the gross margin by approximately $5.1
million;
|
Ÿ
|
customer
operational needs and contract renegotiations resulting in some customers
transitioning from firm demand to interruptible services, which decreased
transportation fees by approximately $2.2 million;
and
|
Ÿ
|
lower
volumes and realized margin on sales of physical natural gas long/short
positions associated with transportation operations decreased the gross
margin by approximately $1.0 million, net of imbalance and fuel tracker
obligations.
|
Ÿ
|
decreased
gross margin on keep-whole processing of approximately $58.5
million;
|
Ÿ
|
decreased
gross margin on NGLs retained under POL contracts of approximately $9.5
million; and
|
Ÿ
|
increased
fixed processing fees of approximately $7.0
million.
|
Ÿ
|
a
decrease in condensate revenues by approximately $5.8 million associated
with the gathering and processing operations due to decreases in prices
partially offset by an increase in volumes due to several new expansion
projects with higher GPM gas;
|
Ÿ
|
lower
natural gas market prices partially offset by a 9.4 percent increase in
residue gas volumes associated with Atoka’s operations that decreased the
gross margin by approximately $5.6 million;
and
|
Ÿ
|
lower
NGLs prices and an increase in utilization of third-party processing fees
that decreased the Atoka processing gross margin by approximately $1.2
million.
|
Ÿ
|
new
volumes associated with gathering expansion projects that increased
overall volumes by 7.7 percent resulting in increased gathering and
treating fees by approximately $11.7 million;
and
|
Ÿ
|
higher
volumes and realized margin on sales of physical natural gas long/short
associated with gathering operations that increased the gross margin by
approximately $10.2 million, net of imbalance and fuel tracker
obligations.
|
Ÿ
|
an
increase in interest expense of approximately $8.9 million on the $200
million of 6.875% 5-year senior notes issued in June 2009 and the $250
million of 6.25% 10-year senior notes issued in November 2009;
and
|
Ÿ
|
an
increase in interest expense of approximately $3.0 million due to a tender
payment on the tender offer Enogex completed in July 2009 for the purchase
of approximately $110.8 million of Enogex’s $400.0 million 8.125% senior
notes outstanding that matured on January 15,
2010.
|
Ÿ
|
lower
interest expense of approximately $3.9 million due to the retirement in
July 2009 of approximately $110.8 million of senior notes, which is a
portion of Enogex’s 8.125% senior notes due January 15,
2010;
|
Ÿ
|
lower
interest expense of approximately $2.7 million due to an increase in the
amount of construction expenditures eligible for interest capitalization
in 2009; and
|
Ÿ
|
a
decrease in interest expense of approximately $2.0 million due to a
decrease in credit support fees.
|
Ÿ
|
a
decreased imbalance liability, net of fuel recoveries, electric
compression costs and natural gas long/short positions, associated with
the transportation operations in 2008, which increased the gross margin by
approximately $16.3 million;
|
Ÿ
|
increased
crosshaul revenues as a result of a contract change in January 2008, that
transferred revenues that had previously been classified as high pressure
gathering revenues in 2007 as well as increased customer production in
2008, which increased the gross margin by approximately $4.9
million;
|
Ÿ
|
administrative
service fees received from OERI in 2008, which increased the gross margin
by approximately $3.4 million; and
|
Ÿ
|
increased
low pressure revenues as a result of increased volumes primarily due to
several new projects which began production in 2008, which increased the
gross margin by approximately $2.1
million.
|
Ÿ
|
Enogex’s
transportation operations moving from an under-recovered position to an
over-recovered position under its FERC-approved fuel tracker in the East
Zone in 2008, which resulted in a loss compared to a gain in 2007, which
decreased the gross margin by approximately $8.0
million;
|
Ÿ
|
lower
gross margins on realized operational storage hedges in 2008 as compared
to 2007, which decreased the gross margin by approximately $2.9
million;
|
Ÿ
|
lower
gross margins on commodity and interruptible storage fees resulting from
the loss of a contract in 2008 and decreased activity due to changes in
the marketplace, which decreased the gross margin by approximately $1.2
million; and
|
Ÿ
|
the
removal of a liability associated with a throughput contract which was
transferred to the gathering and processing segment during 2007 with no
comparable item recorded in 2008, which increased the 2007 gross margin by
approximately $1.2 million.
|
Ÿ
|
an
increase in keep-whole margins associated with the processing operations
in 2008 as compared to 2007 primarily due to higher keep-whole margins
throughout the majority of 2008, which increased the gross margin by
approximately $16.8 million;
|
Ÿ
|
an
increase in the condensate margin associated with the processing
operations due to higher prices and a 17.1 percent increase in
volumes in 2008 as compared to 2007, which increased the gross margin by
approximately $12.4 million;
|
Ÿ
|
an
increase in the POL gross margin associated with the processing operations
due to: (i) favorable pricing for NGLs, as well an approximate 28.3
percent increase in volumes retained by Enogex, which increased the gross
margin by approximately $10.8 million and (ii) new volumes from Atoka’s
processing operations, which began operations in August 2007, which
increased the gross margin by approximately $3.2
million;
|
Ÿ
|
higher
compression and dehydration fees associated with the gathering operations
resulting from new projects, including Atoka, in 2007 and 2008, which
increased the gross margin by approximately $7.9
million;
|
Ÿ
|
sales
of residue gas, condensate and additional retained NGLs associated with
the processing operations of Atoka, which began operations in August 2007,
which increased the gross margin by approximately $6.8
million;
|
Ÿ
|
an
increase of natural gas processed under new and renegotiated fixed fee
processing contracts, which increased the gross margin by approximately
$4.0 million;
|
Ÿ
|
increased
low pressure gathering fees associated with new projects, including Atoka,
which increased the gross margin by approximately $4.0 million;
and
|
Ÿ
|
the
recognition of the liability associated with a throughput contract which
was transferred from the transportation and storage segment in 2007 with
no comparable item recorded 2008, which decreased the 2007 gross margin by
approximately $1.9 million.
|
Ÿ
|
Enogex
moving from an under-recovered position to an over-recovered position in
the East and West Zones in 2008, which resulted in a loss compared to the
gain recognized in 2007, which decreased the gross margin approximately
$7.2 million;
|
Ÿ
|
an
increased imbalance liability, net of fuel recoveries, electric
compression costs and natural gas long/short positions in 2008, which
decreased the gross margin by approximately $3.9 million;
and
|
Ÿ
|
increased
costs for electric compression primarily due to the installation of a new
compressor at one of Enogex’s processing plants in 2008, which decreased
the gross margin by approximately $1.7
million.
|
Ÿ
|
higher
internal allocations for overhead costs of approximately $3.0 million to
the other Enogex segments, which decreased other operation and maintenance
expense for the transportation and storage
segment;
|
Ÿ
|
lower
contract professional, technical services and materials and supplies
expense of approximately $1.3 million due to lower expenses on line
remediation and non-capital pipeline integrity projects in 2008;
and
|
Ÿ
|
lower
service expenses of approximately $1.1 million charged to the
transportation and storage segment in 2008 by OERI due to a portion of the
service fee being allocated to the gathering and processing segment in
2008.
|
Ÿ
|
higher
allocations for overhead and labor costs from the transportation and
storage segment of approximately $6.6 million in
2008;
|
Ÿ
|
higher
contract professional services and materials and supplies expense of
approximately $3.7 million due to an increase in non-capitalized system
projects in 2008; and
|
Ÿ
|
higher
costs for compressor and equipment rental of approximately $1.7 million
due to increased business in 2008.
|
Year
Ended December 31 (In
millions)
|
2009
|
2008
|
2007
|
|||||||
Operating
revenues
|
$
|
619.9
|
$
|
1,529.4
|
$
|
1,541.2
|
||||
Cost
of goods
sold
|
617.7
|
1,509.5
|
1,513.4
|
|||||||
Gross
margin on
revenues
|
2.2
|
19.9
|
27.8
|
|||||||
Other
operation and
maintenance
|
9.2
|
12.9
|
10.1
|
|||||||
Depreciation
and
amortization
|
0.1
|
0.2
|
0.2
|
|||||||
Taxes
other than
income
|
0.4
|
0.4
|
0.4
|
|||||||
Operating
income
(loss)
|
$
|
(7.5)
|
$
|
6.4
|
$
|
17.1
|
Ÿ
|
smaller
differences in natural gas prices at various U.S. market locations which
resulted a reduced spread that OERI was able to realize from delivering
gas under its transportation contracts, which decreased the gross margin
from transportation by approximately $7.2
million;
|
Ÿ
|
the
decrease in natural gas prices and NGLs spreads discussed above as well as
selective deal execution in light of credit and other risks in the
commodity price and credit environment in 2009 which resulted in limited
opportunities for OERI in its customer focused risk management services
and natural gas marketing activities, which decreased the gross margin by
approximately $7.2 million; and
|
Ÿ
|
a
natural gas storage contract that ended in the second quarter of 2008
resulting in less storage capacity to manage in 2009, which decreased the
gross margin from storage by approximately $3.3
million.
|
Ÿ
|
the
receipt of approximately $0.9 million from a bankruptcy settlement in 2009
for a bankruptcy that was recorded as a bad debt expense of approximately
$1.5 million in 2008, resulting in a decrease in operation and maintenance
expense of approximately $2.4 million;
and
|
Ÿ
|
a
lower support service allocation of approximately $1.6 million from OGE
Energy and Enogex in 2009.
|
Ÿ
|
lower
realized gains associated with various transportation contracts in 2008 as
compared to 2007, which decreased the gross margin by approximately $12.5
million;
|
Ÿ
|
increased
losses on economic hedges associated with various transportation contracts
from recording these hedges at market value on December 31, 2008 as
compared to recording these hedges at market value on December 31, 2007,
which decreased the gross margin by approximately $6.8
million;
|
Ÿ
|
a
lower of cost or market adjustment to the natural gas storage inventory of
approximately $6.2 million in 2008 as compared to an adjustment of
approximately $3.6 million in 2007, which decreased the gross margin by
approximately $2.6 million; and
|
Ÿ
|
lower
gains on physical sales of natural gas storage inventory activity
partially offset by lower storage fees paid by OERI, which decreased the
gross margin by approximately $2.5
million.
|
Ÿ
|
gains
on economic hedges associated with storage contracts from recording these
hedges at market value on December 31, 2008 as compared to losses from
recording these hedges at market value on December 31, 2007, which
increased the gross margin by approximately $12.6 million;
and
|
Ÿ
|
increased
gains from origination and other marketing and trading activity in 2008 as
compared to 2007, which increased the gross margin by approximately $3.8
million.
|
Ÿ
|
the
financial performance of Enogex’s assets without regard to financing
methods, capital structure or historical cost
basis;
|
Ÿ
|
Enogex’s
operating performance and return on capital as compared to other companies
in the midstream energy sector, without regard to financing or capital
structure; and
|
Ÿ
|
the
viability of acquisitions and capital expenditure projects and the overall
rates of return on alternative investment
opportunities.
|
Year
Ended December 31 (In
millions)
|
2009
|
2008
|
2007
|
||||||||
Net income
attributable to Enogex LLC (A)
|
$
|
66.3
|
$
|
91.2
|
$
|
86.2
|
|||||
Add:
|
|||||||||||
Interest
expense, net
|
35.5
|
30.2
|
22.4
|
||||||||
Income
tax expense
|
40.8
|
57.3
|
53.5
|
||||||||
Depreciation
and amortization
|
64.3
|
54.6
|
45.9
|
||||||||
EBITDA
|
$
|
206.9
|
$
|
233.3
|
$
|
208.0
|
Less than
|
|||||||||||||||
1 year
|
1-3 years
|
3-5 years
|
More than
|
||||||||||||
(In millions)
|
Total
|
(2010)
|
(2011-2012)
|
(2013-2014)
|
5 years
|
||||||||||
Capital Expenditures
|
|||||||||||||||
OG&E Base Transmission
|
$
|
150.0
|
$
|
45.0
|
$
|
40.0
|
$
|
40.0
|
$
|
25.0
|
|||||
OG&E Base Distribution
|
1,320.0
|
235.0
|
430.0
|
435.0
|
220.0
|
||||||||||
OG&E Base Generation
|
205.0
|
30.0
|
70.0
|
70.0
|
35.0
|
||||||||||
OG&E Other
|
150.0
|
25.0
|
50.0
|
50.0
|
25.0
|
||||||||||
Total OG&E Base Transmission, Distribution,
|
|||||||||||||||
Generation and Other
|
1,825.0
|
335.0
|
590.0
|
595.0
|
305.0
|
||||||||||
OG&E Known and Committed Projects:
|
|||||||||||||||
Transmission Projects:
|
|||||||||||||||
Sunnyside-Hugo (345 kV)
|
120.0
|
30.0
|
90.0
|
---
|
---
|
||||||||||
Sooner-Rose Hill (345 kV)
|
65.0
|
10.0
|
55.0
|
---
|
---
|
||||||||||
Windspeed (345 kV)
|
25.0
|
25.0
|
---
|
---
|
---
|
||||||||||
Balanced Portfolio 3E Projects
|
300.0
|
10.0
|
170.0
|
120.0
|
---
|
||||||||||
Total Transmission Projects
|
510.0
|
75.0
|
315.0
|
120.0
|
---
|
||||||||||
Other Projects:
|
|||||||||||||||
Smart Grid Program (A)
|
230.0
|
40.0
|
120.0
|
60.0
|
10.0
|
||||||||||
System Hardening
|
35.0
|
20.0
|
15.0
|
---
|
---
|
||||||||||
OU Spirit
|
10.0
|
10.0
|
---
|
---
|
---
|
||||||||||
Other
|
30.0
|
20.0
|
10.0
|
---
|
---
|
||||||||||
Total Other Projects
|
305.0
|
90.0
|
145.0
|
60.0
|
10.0
|
||||||||||
Total OG&E Known and Committed Projects
|
815.0
|
165.0
|
460.0
|
180.0
|
10.0
|
||||||||||
Total OG&E (B)
|
2,640.0
|
500.0
|
1,050.0
|
775.0
|
315.0
|
||||||||||
Enogex (Base Maintenance and Known
|
|||||||||||||||
and Committed Projects)
|
355.0
|
135.0
|
85.0
|
90.0
|
45.0
|
||||||||||
OGE Energy and OERI
|
150.0
|
25.0
|
50.0
|
50.0
|
25.0
|
||||||||||
Total capital expenditures
|
3,145.0
|
660.0
|
1,185.0
|
915.0
|
385.0
|
||||||||||
Maturities of long-term debt
|
2,384.6
|
289.2
|
---
|
300.0
|
1,795.4
|
||||||||||
Total capital requirements
|
5,529.6
|
949.2
|
1,185.0
|
1,215.0
|
2,180.4
|
||||||||||
Operating lease obligations
|
|||||||||||||||
OG&E railcars
|
41.9
|
3.9
|
38.0
|
---
|
---
|
||||||||||
Enogex noncancellable operating leases
|
4.5
|
2.5
|
2.0
|
---
|
---
|
||||||||||
Total operating lease obligations
|
46.4
|
6.4
|
40.0
|
---
|
---
|
||||||||||
Other purchase obligations and commitments
|
|||||||||||||||
OG&E cogeneration capacity payments
|
406.0
|
86.1
|
164.2
|
155.7
|
---
|
||||||||||
OG&E fuel minimum purchase commitments
|
426.0
|
340.0
|
84.2
|
1.8
|
---
|
||||||||||
OG&E wind minimum purchase commitments
|
948.9
|
10.2
|
103.3
|
104.8
|
730.6
|
||||||||||
OG&E long-term service agreements
|
141.3
|
3.7
|
28.4
|
37.9
|
71.3
|
||||||||||
OERI Cheyenne Plains commitments
|
30.8
|
5.4
|
10.8
|
13.0
|
1.6
|
||||||||||
OERI MEP commitments
|
9.2
|
2.1
|
4.2
|
2.9
|
---
|
||||||||||
Total other purchase obligations
and
|
|||||||||||||||
commitments
|
1,962.2
|
447.5
|
395.1
|
316.1
|
803.5
|
||||||||||
Total capital requirements, operating lease
|
|||||||||||||||
obligations and other purchase obligations
|
|||||||||||||||
and
commitments
|
7,538.2
|
1,403.1
|
1,620.1
|
1,531.1
|
2,983.9
|
||||||||||
Amounts recoverable through fuel adjustment
|
|||||||||||||||
clause (C)
|
(1,822.8)
|
(440.2)
|
(389.7)
|
(262.3)
|
(730.6)
|
||||||||||
Total, net
|
$
|
5,715.4
|
$
|
962.9
|
$
|
1,230.4
|
$
|
1,268.8
|
$
|
2,253.3
|
Year Ended December 31 (In millions)
|
2009
|
2008
|
2007
|
||||||
Net cash provided from operating activities
|
$
|
654.5
|
$
|
625.0
|
$
|
328.5
|
|||
Net cash used in investing activities
|
(808.5)
|
(1,184.1)
|
(556.3)
|
||||||
Net cash provided from financing activities
|
37.7
|
724.7
|
188.7
|
Ÿ
|
higher
fuel recoveries at OG&E in 2009 as compared to
2008;
|
Ÿ
|
cash
received in 2009 from the implementation of the Redbud Facility rider in
the third quarter of 2008;
|
Ÿ
|
cash
received in 2009 from the implementation of the Oklahoma rate increase in
August 2009;
|
Ÿ
|
payments
made by OG&E in the first quarter of 2008 related to the December 2007
ice storm; and
|
Ÿ
|
a
decrease in payments for purchases at Enogex and OERI due to a decrease in
natural gas prices and volumes in 2009 as compared to
2008.
|
Ÿ
|
a
decrease in cash receipts for sales at Enogex and OERI due to a decrease
in natural gas prices and volumes in 2009 as compared to 2008;
and
|
Ÿ
|
a
decrease in cash collateral posted by counterparties and held by OERI
related to OERI’s existing NGLs hedge
positions.
|
Ÿ
|
higher
fuel recoveries at OG&E in 2008 as compared to
2007;
|
Ÿ
|
an
increase in cash collateral received from counterparties related to OERI’s
existing NGLs hedge positions;
|
Ÿ
|
an
increase in payments for purchases at Enogex due to an increase in natural
gas prices and volumes in 2008 as compared to 2007;
and
|
Ÿ
|
higher
billed sales at OG&E in 2008.
|
Ÿ
|
payments
made by OG&E in the first quarter of 2008 related to the December 2007
ice storm; and
|
Ÿ
|
an
increase in cash receipts for sales at Enogex due to an increase in
natural gas prices and volumes in 2008 as compared to
2007.
|
Ÿ
|
proceeds
received from the issuances of $700 million in long-term debt by OG&E
in 2008;
|
Ÿ
|
repayments
of borrowings under Enogex’s revolving credit agreement in
2009;
|
Ÿ
|
repayments
of short-term debt in 2009; and
|
Ÿ
|
the
purchase of approximately $110.8 million of Enogex’s $400.0 million 8.125%
senior notes related to the tender offer discussed
below.
|
Ÿ
|
proceeds
received from the issuances of $450 million in long-term debt by Enogex in
2009; and
|
Ÿ
|
an
increase in the issuance of common stock in
2009.
|
(In millions)
|
OG&E
(A)
|
Enogex
|
OGE
Energy
|
Total
|
||||||||
Pension
Settlement Charge:
|
||||||||||||
2007
|
$
|
13.3
|
$
|
0.5
|
$
|
2.9
|
$
|
16.7
|
||||
Retirement
Restoration Plan Settlement Charge:
|
||||||||||||
2007
|
$
|
0.1
|
$
|
---
|
$
|
2.2
|
$
|
2.3
|
Moody’s
|
Standard
& Poor’s
|
Fitch’s
|
|
OG&E
Senior Notes
|
A2
|
BBB+
|
AA-
|
Enogex
Notes
|
Baa3
|
BBB+
|
BBB
|
OGE
Energy Corp. Senior Notes
|
Baa1
|
BBB
|
A
|
OGE
Energy Corp. Commercial Paper
|
P2
|
A2
|
F1
|
Revolving
Credit Agreements and Available Cash (In
millions)
|
||||||||
Aggregate
|
Amount
|
Weighted-Average
|
||||||
Entity
|
Commitment
|
Outstanding
|
Interest
Rate
|
Maturity
|
||||
OGE
Energy
|
$
|
596.0
|
$
|
175.0
|
0.27%
|
December
6, 2012
|
||
OG&E
|
389.0
|
10.2
|
0.14%
|
December
6, 2012
|
||||
Enogex
|
250.0
|
---
|
---%
|
March
31, 2013
|
||||
1,235.0
|
185.2
|
0.26%
|
||||||
Cash
|
58.1
|
N/A
|
N/A
|
N/A
|
||||
Total
|
$
|
1,293.1
|
$
|
185.2
|
0.26%
|
Impact on
|
||
Change
|
Funded Status
|
|
Actual plan asset returns
|
+/- 5 percent
|
+/- $24.8 million
|
Discount rate
|
+/- 0.25 percent
|
+/- $19.4 million
|
Contributions
|
+ $10.0 million
|
+ $10.0 million
|
Expected long-term return on plan assets
|
+/- 1 percent
|
None
|
Year ended
|
||||||||||||||||||||
December 31
|
12/31/09
|
|||||||||||||||||||
(Dollars in millions)
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
Fair Value
|
||||||||||||
Fixed-rate debt (A)
|
||||||||||||||||||||
Principal amount
|
$
|
289.2
|
$
|
---
|
$
|
---
|
$
|
---
|
$
|
300.0
|
$
|
1,660.0
|
$
|
2,249.2
|
$
|
2,341.4
|
||||
Weighted-average
|
||||||||||||||||||||
interest rate
|
8.13
|
%
|
---
|
---
|
---
|
6.25
|
%
|
6.57
|
%
|
6.73
|
%
|
---
|
||||||||
Variable-rate debt (B)
|
||||||||||||||||||||
Principal amount
|
---
|
---
|
---
|
---
|
---
|
$
|
135.4
|
$
|
135.4
|
$
|
135.4
|
|||||||||
Weighted-average
|
||||||||||||||||||||
interest rate
|
---
|
---
|
---
|
---
|
---
|
0.57
|
%
|
0.57
|
%
|
---
|
December
31 (In
millions)
|
2009
|
2008
|
||||
Commodity
market risk, net
|
$
|
0.4
|
$
|
0.1
|
December
31 (In
millions)
|
2009
|
2008
|
||||
Commodity
market risk, net
|
$
|
17.0
|
$
|
6.6
|
OGE
ENERGY CORP.
|
||||||||||||||
CONSOLIDATED
STATEMENTS OF INCOME
|
||||||||||||||
Year
ended December 31 (In millions, except per share data)
|
2009
|
2008
|
2007
|
|||||||||||
OPERATING
REVENUES
|
||||||||||||||
Electric
Utility operating revenues
|
$
|
1,751.2
|
$
|
1,959.5
|
$
|
1,835.1
|
||||||||
Natural
Gas Pipeline operating revenues
|
1,118.5
|
2,111.2
|
1,962.5
|
|||||||||||
Total
operating revenues
|
2,869.7
|
4,070.7
|
3,797.6
|
|||||||||||
COST
OF GOODS SOLD (exclusive of depreciation and amortization
|
||||||||||||||
shown
below)
|
||||||||||||||
Electric
Utility cost of goods sold
|
748.7
|
1,061.2
|
977.8
|
|||||||||||
Natural
Gas Pipeline cost of goods sold
|
809.0
|
1,756.8
|
1,656.9
|
|||||||||||
Total
cost of goods sold
|
1,557.7
|
2,818.0
|
2,634.7
|
|||||||||||
Gross
margin on revenues
|
1,312.0
|
1,252.7
|
1,162.9
|
|||||||||||
Other
operation and maintenance
|
466.8
|
492.2
|
436.8
|
|||||||||||
Depreciation
and amortization
|
262.6
|
217.5
|
195.3
|
|||||||||||
Impairment
of assets
|
3.1
|
0.4
|
0.5
|
|||||||||||
Taxes
other than income
|
87.6
|
80.5
|
75.0
|
|||||||||||
OPERATING
INCOME
|
491.9
|
462.1
|
455.3
|
|||||||||||
OTHER
INCOME (EXPENSE)
|
||||||||||||||
Interest
income
|
1.4
|
6.7
|
2.1
|
|||||||||||
Allowance
for equity funds used during construction
|
15.1
|
---
|
---
|
|||||||||||
Other
income
|
27.5
|
15.4
|
17.4
|
|||||||||||
Other
expense
|
(16.3
|
)
|
(25.6
|
)
|
(22.7
|
)
|
||||||||
Net
other income (expense)
|
27.7
|
(3.5
|
)
|
(3.2
|
)
|
|||||||||
INTEREST
EXPENSE
|
||||||||||||||
Interest
on long-term debt
|
137.3
|
103.0
|
87.8
|
|||||||||||
Allowance
for borrowed funds used during construction
|
(8.3
|
) |
(4.0
|
)
|
(4.0
|
)
|
||||||||
Interest
on short-term debt and other interest charges
|
8.4
|
21.0
|
6.4
|
|||||||||||
Interest
expense
|
137.4
|
120.0
|
90.2
|
|||||||||||
INCOME
BEFORE TAXES
|
382.2
|
338.6
|
361.9
|
|||||||||||
INCOME
TAX EXPENSE
|
121.1
|
101.2
|
116.7
|
|||||||||||
NET
INCOME
|
261.1
|
237.4
|
245.2
|
|||||||||||
Less:
Net income attributable to noncontrolling interest
|
2.8
|
6.0
|
1.0
|
|||||||||||
NET
INCOME ATTRIBUTABLE TO OGE ENERGY
|
$
|
258.3
|
$
|
231.4
|
$
|
244.2
|
||||||||
BASIC
AVERAGE COMMON SHARES OUTSTANDING
|
96.2
|
92.4
|
91.7
|
|||||||||||
DILUTED
AVERAGE COMMON SHARES OUTSTANDING
|
97.2
|
92.8
|
92.5
|
|||||||||||
BASIC
EARNINGS PER AVERAGE COMMON SHARE
|
||||||||||||||
ATTRIBUTABLE
TO OGE ENERGY COMMON SHAREHOLDERS
|
$
|
2.68
|
$
|
2.50
|
$
|
2.66
|
||||||||
DILUTED
EARNINGS PER AVERAGE COMMON SHARE
|
||||||||||||||
ATTRIBUTABLE
TO OGE ENERGY COMMON SHAREHOLDERS
|
$
|
2.66
|
$
|
2.49
|
$
|
2.64
|
||||||||
DIVIDENDS
DECLARED PER SHARE
|
$
|
1.4275
|
$
|
1.3975
|
$
|
1.3675
|
||||||||
OGE ENERGY CORP.
|
|||||||
CONSOLIDATED BALANCE SHEETS
|
|||||||
December 31 (In millions)
|
2009
|
2008
|
|||||
ASSETS
|
|||||||
CURRENT ASSETS
|
|||||||
Cash and cash equivalents
|
$
|
58.1
|
$
|
174.4
|
|||
Accounts receivable, less reserve of $2.4 and $3.2, respectively
|
291.4
|
288.1
|
|||||
Accrued unbilled revenues
|
57.2
|
47.0
|
|||||
Income taxes receivable
|
157.7
|
---
|
|||||
Fuel inventories
|
118.5
|
88.7
|
|||||
Materials and supplies, at average cost
|
78.4
|
72.1
|
|||||
Price risk management
|
1.8
|
11.9
|
|||||
Gas imbalances
|
3.2
|
6.2
|
|||||
Accumulated deferred tax assets
|
39.8
|
14.9
|
|||||
Fuel clause under recoveries
|
0.3
|
24.0
|
|||||
Prepayments
|
8.7
|
9.0
|
|||||
Other
|
11.0
|
8.3
|
|||||
Total current assets
|
826.1
|
744.6
|
|||||
OTHER PROPERTY AND INVESTMENTS, at cost
|
43.7
|
42.2
|
|||||
PROPERTY, PLANT AND EQUIPMENT
|
|||||||
In service
|
8,617.8
|
7,722.4
|
|||||
Construction work in progress
|
335.4
|
399.0
|
|||||
Total property, plant and equipment
|
8,953.2
|
8,121.4
|
|||||
Less accumulated depreciation
|
3,041.6
|
2,871.6
|
|||||
Net property, plant and equipment
|
5,911.6
|
5,249.8
|
|||||
DEFERRED CHARGES AND OTHER ASSETS
|
|||||||
Income taxes recoverable from customers, net
|
19.1
|
14.6
|
|||||
Benefit obligations regulatory asset
|
357.8
|
344.7
|
|||||
Price risk management
|
4.3
|
22.0
|
|||||
McClain Plant deferred expenses
|
---
|
6.2
|
|||||
Unamortized loss on reacquired debt
|
16.5
|
17.7
|
|||||
Unamortized debt issuance costs
|
15.3
|
13.5
|
|||||
Other
|
72.3
|
63.2
|
|||||
Total deferred charges and other assets
|
485.3
|
481.9
|
|||||
TOTAL ASSETS
|
$
|
7,266.7
|
$
|
6,518.5
|
The
accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
|
OGE ENERGY CORP.
|
||||||
CONSOLIDATED BALANCE SHEETS (Continued)
|
||||||
December 31 (In millions)
|
2009
|
2008
|
||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||
CURRENT LIABILITIES
|
||||||
Short-term debt
|
$
|
175.0
|
$
|
298.0
|
||
Accounts payable
|
297.0
|
279.7
|
||||
Dividends payable
|
35.1
|
33.2
|
||||
Customer deposits
|
85.6
|
58.8
|
||||
Accrued taxes
|
37.0
|
26.8
|
||||
Accrued interest
|
60.6
|
48.7
|
||||
Accrued compensation
|
50.1
|
45.2
|
||||
Long-term debt due within one year
|
289.2
|
---
|
||||
Price risk management
|
14.2
|
2.3
|
||||
Gas imbalances
|
12.0
|
24.9
|
||||
Fuel clause over recoveries
|
187.5
|
8.6
|
||||
Other
|
32.4
|
62.2
|
||||
Total current liabilities
|
1,275.7
|
888.4
|
||||
LONG-TERM DEBT
|
2,088.9
|
2,161.8
|
||||
DEFERRED CREDITS AND OTHER LIABILITIES
|
||||||
Accrued benefit obligations
|
369.3
|
350.5
|
||||
Accumulated deferred income taxes
|
1,246.6
|
996.9
|
||||
Accumulated deferred investment tax credits
|
13.1
|
17.3
|
||||
Accrued removal obligations, net
|
168.2
|
150.9
|
||||
Price risk management
|
0.1
|
3.8
|
||||
Other
|
44.0
|
34.9
|
||||
Total deferred credits and other liabilities
|
1,841.3
|
1,554.3
|
||||
Total liabilities
|
5,205.9
|
4,604.5
|
||||
COMMITMENTS AND CONTINGENCIES (NOTE 13)
|
||||||
STOCKHOLDERS’ EQUITY
|
||||||
Common stockholders’ equity
|
887.7
|
802.9
|
||||
Retained earnings
|
1,227.8
|
1,107.6
|
||||
Accumulated other comprehensive loss, net of tax
|
(74.7)
|
(13.7)
|
||||
Total OGE Energy stockholders’ equity
|
2,040.8
|
1,896.8
|
||||
Noncontrolling interest
|
20.0
|
17.2
|
||||
Total stockholders’ equity
|
2,060.8
|
1,914.0
|
||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
7,266.7
|
$
|
6,518.5
|
The
accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
|
OGE ENERGY CORP.
|
|||||||||
CONSOLIDATED STATEMENTS OF CAPITALIZATION
|
|||||||||
December 31 (In millions)
|
2009
|
2008
|
|||||||
STOCKHOLDERS’ EQUITY
|
|||||||||
Common stock, par value $0.01 per share; authorized 125.0 shares;
|
|||||||||
and outstanding 97.0 and 93.5 shares, respectively
|
$
|
1.0
|
$
|
0.9
|
|||||
Premium on capital stock
|
886.7
|
802.0
|
|||||||
Retained earnings
|
1,227.8
|
1,107.6
|
|||||||
Accumulated other comprehensive loss, net of tax
|
(74.7)
|
(13.7)
|
|||||||
Total OGE Energy stockholders’ equity
|
2,040.8
|
1,896.8
|
|||||||
Noncontrolling interest
|
20.0
|
17.2
|
|||||||
Total stockholders’ equity
|
2,060.8
|
1,914.0
|
|||||||
LONG-TERM DEBT
|
|||||||||
SERIES
|
DATE DUE
|
||||||||
Senior Notes - OGE Energy Corp.
|
|||||||||
5.00%
|
Senior Notes, Series Due November 15, 2014
|
100.0
|
100.0
|
||||||
Unamortized discount
|
(0.5)
|
(0.5)
|
|||||||
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
|
||||||
Other Bonds - OG&E
|
|||||||||
0.30% - 1.00%
|
Garfield Industrial Authority, January 1, 2025
|
47.0
|
47.0
|
||||||
0.42% - 0.74%
|
Muskogee Industrial Authority, January 1, 2025
|
32.4
|
32.4
|
||||||
0.42% - 0.75%
|
Muskogee Industrial Authority, June 1, 2027
|
56.0
|
55.9
|
||||||
Unamortized discount
|
(3.6)
|
(3.9)
|
|||||||
Enogex
|
|||||||||
8.125%
|
Senior Notes, Series Due January 15, 2010
|
289.2
|
400.0
|
||||||
---%
|
Enogex Revolving Credit Agreement Due March 31, 2013
|
---
|
120.0
|
||||||
6.875%
|
Senior Notes, Series Due July 15, 2014
|
200.0
|
---
|
||||||
6.25%
|
Senior Notes, Series Due March 15, 2020
|
250.0
|
---
|
||||||
Unamortized discount
|
(2.4)
|
---
|
|||||||
Unamortized swap
monetization
|
---
|
0.9
|
|||||||
Total long-term debt
|
2,378.1
|
2,161.8
|
|||||||
Less long-term debt due within one year
|
289.2
|
---
|
|||||||
Total long-term debt (excluding long-term debt due within one year)
|
2,088.9
|
2,161.8
|
|||||||
Total Capitalization
|
$
|
4,149.7
|
$
|
4,075.8
|
The accompanying Notes to
Consolidated Financial Statements are an integral part
hereof.
|
Premium
|
Accumulated
|
|||||
on
|
Other
|
|||||
Common
|
Capital
|
Retained
|
Comprehensive
|
Noncontrolling
|
||
(In millions)
|
Stock
|
Stock
|
Earnings
|
Income (Loss)
|
Interest
|
Total
|
Balance at December 31, 2006
|
$ 0.9
|
$ 740.1
|
$ 890.8
|
$ (28.0)
|
$ ---
|
$ 1,603.8
|
Comprehensive income (loss)
|
||||||
Net income for 2007
|
---
|
---
|
244.2
|
---
|
1.0
|
245.2
|
Other comprehensive income (loss), net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Net loss, net of tax ($4.4 pre-tax)
|
---
|
---
|
---
|
2.7
|
---
|
2.7
|
Prior service cost, net of tax ($5.4 pre-tax)
|
---
|
---
|
---
|
3.3
|
---
|
3.3
|
Defined benefit postretirement plans:
|
||||||
Net loss, net of tax ($3.3 pre-tax)
|
---
|
---
|
---
|
1.7
|
---
|
1.7
|
Net transition obligation, net of tax ($0.2 pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Prior service cost, net of tax ($0.5 pre-tax)
|
---
|
---
|
---
|
0.3
|
---
|
0.3
|
Deferred hedging losses, net of tax (($100.0) pre-tax)
|
---
|
---
|
---
|
(61.3)
|
---
|
(61.3)
|
Amortization of cash flow hedge, net of tax ($0.4 pre-tax)
|
---
|
---
|
---
|
0.2
|
---
|
0.2
|
Other comprehensive loss
|
---
|
---
|
---
|
(53.0)
|
---
|
(53.0)
|
Comprehensive income (loss)
|
---
|
---
|
244.2
|
(53.0)
|
1.0
|
192.2
|
Dividends declared on common stock
|
---
|
---
|
(125.5)
|
---
|
---
|
(125.5)
|
Adoption of new accounting principle (($6.2) pre-tax) (A)
|
---
|
---
|
(3.8)
|
---
|
---
|
(3.8)
|
Contribution from noncontrolling interest partner
|
---
|
---
|
---
|
---
|
9.7
|
9.7
|
Issuance of common stock
|
---
|
15.2
|
---
|
---
|
---
|
15.2
|
Balance at December 31, 2007
|
$ 0.9
|
$ 755.3
|
$ 1,005.7
|
$ (81.0)
|
$ 10.7
|
$ 1,691.6
|
Comprehensive income (loss)
|
||||||
Net income for 2008
|
---
|
---
|
231.4
|
---
|
6.0
|
237.4
|
Other comprehensive income (loss), net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Net loss, net of tax (($42.2) pre-tax)
|
---
|
---
|
---
|
(25.8)
|
---
|
(25.8)
|
Prior service cost, net of tax ($0.5 pre-tax)
|
---
|
---
|
---
|
0.3
|
---
|
0.3
|
Defined benefit postretirement plans:
|
||||||
Net loss, net of tax (($2.6) pre-tax)
|
---
|
---
|
---
|
(1.6)
|
---
|
(1.6)
|
Net transition obligation, net of tax ($0.3 pre-tax)
|
---
|
---
|
---
|
0.2
|
---
|
0.2
|
Prior service cost, net of tax ($0.3 pre-tax)
|
---
|
---
|
---
|
0.2
|
---
|
0.2
|
Deferred hedging gains, net of tax ($153.3 pre-tax)
|
---
|
---
|
---
|
93.8
|
---
|
93.8
|
Amortization of cash flow hedge, net of tax ($0.4 pre-tax)
|
---
|
---
|
---
|
0.2
|
---
|
0.2
|
Other comprehensive income
|
---
|
---
|
---
|
67.3
|
---
|
67.3
|
Comprehensive income
|
---
|
---
|
231.4
|
67.3
|
6.0
|
304.7
|
Dividends declared on common stock
|
---
|
---
|
(129.5)
|
---
|
---
|
(129.5)
|
Contribution from noncontrolling interest partner
|
---
|
---
|
---
|
---
|
0.5
|
0.5
|
Issuance of common stock
|
---
|
46.7
|
---
|
---
|
---
|
46.7
|
Balance at December 31, 2008
|
$ 0.9
|
$ 802.0
|
$ 1,107.6
|
$ (13.7)
|
$ 17.2
|
$ 1,914.0
|
Comprehensive income (loss)
|
||||||
Net income for 2009
|
---
|
---
|
258.3
|
---
|
2.8
|
261.1
|
Other comprehensive income (loss), net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Net loss, net of tax ($6.2 pre-tax)
|
---
|
---
|
---
|
3.8
|
---
|
3.8
|
Prior service cost, net of tax (($0.3) pre-tax)
|
---
|
---
|
---
|
(0.2)
|
---
|
(0.2)
|
Defined benefit postretirement plans:
|
||||||
Net loss, net of tax (($8.8) pre-tax)
|
---
|
---
|
---
|
(5.4)
|
---
|
(5.4)
|
Net transition obligation, net of tax ($0.2 pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Prior service cost, net of tax ($0.3 pre-tax)
|
---
|
---
|
---
|
0.2
|
---
|
0.2
|
Deferred hedging losses, net of tax (($97.7) pre-tax)
|
---
|
---
|
---
|
(59.8)
|
---
|
(59.8)
|
Amortization of cash flow hedge, net of tax ($0.5 pre-tax)
|
---
|
---
|
---
|
0.3
|
---
|
0.3
|
Other comprehensive loss
|
---
|
---
|
---
|
(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
|
84.7
|
---
|
---
|
---
|
84.8
|
Balance at December 31, 2009
|
$ 1.0
|
$ 886.7
|
$1,227.8
|
$ (74.7)
|
$ 20.0
|
$ 2,060.8
|
(A)
The Company recognized a cumulative effect adjustment for its uncertain
tax positions on January 1, 2007 related to the adoption of a new
accounting principle.
|
||||||
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
|
Year ended December 31 (In millions)
|
2009
|
2008
|
2007
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|||||||||
Net income
|
$
|
261.1
|
$
|
237.4
|
$
|
245.2
|
|||
Adjustments to reconcile net income to net cash provided from
|
|||||||||
operating activities
|
|||||||||
Depreciation and amortization
|
262.6
|
217.5
|
195.3
|
||||||
Impairment of assets
|
3.1
|
0.4
|
0.5
|
||||||
Deferred income taxes and investment tax credits, net
|
269.8
|
123.4
|
16.1
|
||||||
Allowance for equity funds used during construction
|
(15.1)
|
---
|
---
|
||||||
Loss on disposition and abandonment of assets
|
1.3
|
0.3
|
3.7
|
||||||
Write-down of regulatory assets
|
---
|
9.2
|
---
|
||||||
Stock-based compensation expense
|
5.8
|
4.3
|
3.6
|
||||||
Excess tax benefit on stock-based compensation
|
(3.3)
|
(1.9)
|
(2.8)
|
||||||
Stock-based compensation converted to cash for tax withholding
|
(1.7)
|
---
|
---
|
||||||
Price risk management assets
|
27.8
|
(25.9)
|
32.0
|
||||||
Price risk management liabilities
|
(88.7)
|
126.9
|
(74.3)
|
||||||
Other assets
|
15.4
|
5.1
|
(24.8)
|
||||||
Other liabilities
|
(55.2)
|
(22.9)
|
(61.5)
|
||||||
Change in certain current assets and liabilities
|
|||||||||
Funds on deposit
|
---
|
---
|
32.0
|
||||||
Accounts receivable, net
|
(3.3)
|
46.3
|
9.9
|
||||||
Accrued unbilled revenues
|
(10.2)
|
(1.3)
|
(6.0)
|
||||||
Income taxes receivable
|
(157.7)
|
---
|
---
|
||||||
Fuel, materials and supplies inventories
|
(36.1)
|
(15.2)
|
(21.3)
|
||||||
Gas imbalance assets
|
3.0
|
0.5
|
(3.9)
|
||||||
Fuel clause under recoveries
|
23.7
|
3.3
|
(27.3)
|
||||||
Other current assets
|
(1.4)
|
(2.2)
|
5.4
|
||||||
Accounts payable
|
(17.2)
|
(119.6)
|
104.3
|
||||||
Customer deposits
|
6.6
|
3.3
|
2.1
|
||||||
Accrued taxes
|
11.2
|
(9.0)
|
(13.5)
|
||||||
Accrued interest
|
11.9
|
11.7
|
(7.0)
|
||||||
Accrued compensation
|
4.9
|
(8.7)
|
7.9
|
||||||
Gas imbalance liabilities
|
(12.9)
|
13.8
|
---
|
||||||
Fuel clause over recoveries
|
178.9
|
4.4
|
(92.1)
|
||||||
Other current liabilities
|
(29.8)
|
23.9
|
5.0
|
||||||
Net Cash Provided from Operating Activities
|
654.5
|
625.0
|
328.5
|
||||||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|||||||||
Capital expenditures (less allowance for equity funds used during
|
|||||||||
construction)
|
(847.8)
|
(1,184.5)
|
(557.7)
|
||||||
Construction reimbursement
|
38.8
|
---
|
---
|
||||||
Proceeds from sale of assets
|
1.4
|
0.8
|
1.4
|
||||||
Capital contribution to unconsolidated affiliate
|
(0.9)
|
(0.3)
|
---
|
||||||
Other investing activities
|
---
|
(0.1)
|
---
|
||||||
Net Cash Used in Investing Activities
|
(808.5)
|
(1,184.1)
|
(556.3)
|
||||||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|||||||||
Proceeds from long-term debt
|
444.8
|
743.0
|
---
|
||||||
Proceeds from line of credit
|
80.0
|
145.0
|
---
|
||||||
Issuance of common stock
|
79.6
|
36.4
|
8.2
|
||||||
Excess tax benefit on stock-based compensation
|
3.3
|
1.9
|
2.8
|
||||||
Contributions from noncontrolling interest partner
|
---
|
0.5
|
9.7
|
||||||
Retirement of long-term debt
|
(110.8)
|
(51.1)
|
(3.1)
|
||||||
(Decrease) increase in short-term debt, net
|
(123.0)
|
2.2
|
295.8
|
||||||
Dividends paid on common stock
|
(136.2)
|
(128.2)
|
(124.7)
|
||||||
Repayment of line of credit
|
(200.0)
|
(25.0)
|
---
|
||||||
Net Cash Provided from Financing Activities
|
37.7
|
724.7
|
188.7
|
||||||
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
|
(116.3)
|
165.6
|
(39.1)
|
||||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
|
174.4
|
8.8
|
47.9
|
||||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD
|
$
|
58.1
|
$
|
174.4
|
$
|
8.8
|
December 31 (In millions)
|
2009
|
2008
|
|||||
Regulatory Assets
|
|||||||
Benefit obligations regulatory asset
|
$
|
357.8
|
$
|
344.7
|
|||
Deferred storm expenses
|
28.0
|
32.2
|
|||||
Income taxes recoverable from customers, net
|
19.1
|
14.6
|
|||||
Deferred pension plan expenses
|
18.1
|
14.6
|
|||||
Unamortized loss on reacquired debt
|
16.5
|
17.7
|
|||||
Red Rock deferred expenses
|
7.7
|
7.4
|
|||||
Fuel clause under recoveries
|
0.3
|
24.0
|
|||||
McClain Plant deferred expenses
|
---
|
6.2
|
|||||
Miscellaneous
|
3.9
|
2.9
|
|||||
Total Regulatory Assets
|
$
|
451.4
|
$
|
464.3
|
|||
Regulatory Liabilities
|
|||||||
Fuel clause over recoveries
|
$
|
187.5
|
$
|
8.6
|
|||
Accrued removal obligations, net
|
168.2
|
150.9
|
|||||
Miscellaneous
|
7.3
|
4.9
|
|||||
Total Regulatory Liabilities
|
$
|
363.0
|
$
|
164.4
|
December 31 (In millions)
|
2009
|
2008
|
||||
Defined benefit pension plan
and restoration of retirement income plan:
|
||||||
Net loss
|
$
|
222.8
|
$
|
259.8
|
||
Prior service cost
|
12.5
|
3.5
|
||||
Defined benefit postretirement plans:
|
||||||
Net loss
|
114.9
|
70.4
|
||||
Net transition obligation
|
7.6
|
10.2
|
||||
Prior service cost
|
---
|
0.8
|
||||
Total
|
$
|
357.8
|
$
|
344.7
|
(In millions)
|
|||
Defined benefit pension plan
and restoration of retirement income plan:
|
|||
Net loss
|
$
|
15.9
|
|
Prior service cost
|
2.7
|
||
Defined benefit postretirement plans:
|
|||
Net loss
|
9.1
|
||
Net transition obligation
|
2.5
|
||
Total
|
$
|
30.2
|
Percentage
|
Total Property, Plant
|
Accumulated
|
Net Property, Plant
|
|||||||
December 31, 2009 (In millions)
|
Ownership
|
and Equipment
|
Depreciation
|
and
Equipment
|
||||||
McClain Plant
|
77
|
$
|
197.7
|
$
|
55.3
|
$
|
142.4
|
|||
Redbud Facility
|
51
|
$
|
523.3
|
(A)
|
$
|
80.3
|
(B)
|
$
|
443.0
|
|
(A) This amount includes a plant acquisition adjustment of approximately $148.3 million.
|
||||||||||
(B) This amount includes accumulated amortization of the plant acquisition adjustment of approximately $6.9 million.
|
||||||||||
Percentage
|
Total Property, Plant
|
Accumulated
|
Net Property, Plant
|
|||||||
December 31, 2008 (In millions)
|
Ownership
|
and Equipment
|
Depreciation
|
and
Equipment
|
||||||
McClain Plant
|
77
|
$
|
181.0
|
$
|
44.6
|
$
|
136.4
|
|||
Redbud Facility
|
51
|
$
|
496.6
|
(C)
|
$
|
63.9
|
(D)
|
$
|
432.7
|
|
(C) This amount includes a plant acquisition adjustment of approximately $153.7 million.
|
||||||||||
(D) This amount includes accumulated amortization of the plant acquisition adjustment of approximately $1.5 million.
|
Total Property,
|
Net Property,
|
||||||||
Plant and
|
Accumulated
|
Plant and
|
|||||||
December 31, 2009 (In millions)
|
Equipment
|
Depreciation
|
Equipment
|
||||||
OGE Energy (holding company and OERI)
|
|||||||||
Holding company property, plant and equipment
|
$
|
107.4
|
$
|
75.8
|
$
|
31.6
|
|||
OERI property, plant and equipment
|
7.3
|
7.0
|
0.3
|
||||||
OGE Energy property, plant and equipment
|
114.7
|
82.8
|
31.9
|
||||||
OG&E
|
|||||||||
Distribution assets
|
2,676.2
|
861.1
|
1,815.1
|
||||||
Electric generation assets
|
2,878.2
|
1,141.5
|
1,736.7
|
||||||
Transmission assets
|
1,071.6
|
310.1
|
761.5
|
||||||
Intangible plant
|
29.7
|
22.6
|
7.1
|
||||||
Other property and equipment
|
227.9
|
80.7
|
147.2
|
||||||
OG&E property, plant and equipment
|
6,883.6
|
2,416.0
|
4,467.6
|
||||||
Enogex
|
|||||||||
Transportation and storage assets
|
873.1
|
228.8
|
644.3
|
||||||
Gathering and processing assets
|
1,081.8
|
314.0
|
767.8
|
||||||
Enogex property, plant and equipment
|
1,954.9
|
542.8
|
1,412.1
|
||||||
Total property, plant and equipment
|
$
|
8,953.2
|
$
|
3,041.6
|
$
|
5,911.6
|
Total Property,
|
Net Property,
|
||||||||
Plant and
|
Accumulated
|
Plant and
|
|||||||
December 31, 2008 (In millions)
|
Equipment
|
Depreciation
|
Equipment
|
||||||
OGE Energy (holding company and OERI)
|
|||||||||
Holding company property, plant and equipment
|
$
|
101.4
|
$
|
68.8
|
$
|
32.6
|
|||
OERI property, plant and equipment
|
7.3
|
7.0
|
0.3
|
||||||
OGE Energy property, plant and equipment
|
108.7
|
75.8
|
32.9
|
||||||
OG&E
|
|||||||||
Distribution assets
|
2,551.5
|
824.8
|
1,726.7
|
||||||
Electric generation assets
|
2,623.8
|
1,095.4
|
1,528.4
|
||||||
Transmission assets
|
846.1
|
299.8
|
546.3
|
||||||
Intangible plant
|
26.8
|
18.4
|
8.4
|
||||||
Other property and equipment
|
222.0
|
76.3
|
145.7
|
||||||
OG&E property, plant and equipment
|
6,270.2
|
2,314.7
|
3,955.5
|
||||||
Enogex
|
|||||||||
Transportation and storage assets
|
822.0
|
208.6
|
613.4
|
||||||
Gathering and processing assets
|
920.5
|
272.5
|
648.0
|
||||||
Enogex property, plant and equipment
|
1,742.5
|
481.1
|
1,261.4
|
||||||
Total property, plant and equipment
|
$
|
8,121.4
|
$
|
2,871.6
|
$
|
5,249.8
|
December 31 (In millions)
|
2009
|
2008
|
||||
Defined benefit pension plan and restoration of retirement income plan:
|
||||||
Net loss, net of tax (($65.6) and ($71.6) pre-tax, respectively)
|
$
|
(40.0)
|
$
|
(43.8)
|
||
Prior service cost, net of tax (($1.1) and ($0.8) pre-tax, respectively)
|
(0.7)
|
(0.5)
|
||||
Defined benefit postretirement plans:
|
||||||
Net loss, net of tax (($21.2) and ($11.6) pre-tax, respectively)
|
(10.7)
|
(5.3)
|
||||
Net transition obligation, net of tax (($0.6) and ($0.8) pre-tax, respectively)
|
(0.4)
|
(0.5)
|
||||
Prior service cost, net of tax (($0.1) and ($0.3) pre-tax, respectively)
|
---
|
(0.2)
|
||||
Deferred hedging gains (losses), net of tax (($35.5) and $62.4 pre-tax,
|
||||||
respectively)
|
(21.7)
|
38.1
|
||||
Deferred hedging losses on interest rate swaps, net of tax (($1.9) and ($2.4) pre-
|
||||||
tax, respectively)
|
(1.2)
|
(1.5)
|
||||
Total accumulated other comprehensive loss, net of tax
|
$
|
(74.7)
|
$
|
(13.7)
|
(In millions)
|
|||
Defined benefit pension plan and restoration of retirement income plan:
|
|||
Net loss, net of tax ($4.7 pre-tax)
|
$
|
2.9
|
|
Prior service cost, net of tax ($0.4 pre-tax)
|
0.2
|
||
Defined benefit postretirement plans:
|
|||
Net loss, net of tax ($1.9 pre-tax)
|
1.2
|
||
Net transition obligation, net of tax ($0.2 pre-tax)
|
0.1
|
||
Total
|
$
|
4.4
|
December 31,
|
|||||||||||||
(In millions)
|
2009
|
Level 1
|
Level 2
|
Level 3
|
|||||||||
Assets
|
|||||||||||||
Gross derivative assets
|
$
|
71.3
|
$
|
16.1
|
$
|
6.2
|
$
|
49.0
|
|||||
Gas imbalance assets
|
3.2
|
---
|
3.2
|
---
|
|||||||||
Total
|
$
|
74.5
|
$
|
16.1
|
$
|
9.4
|
$
|
49.0
|
|||||
Liabilities
|
|||||||||||||
Gross derivative liabilities
|
$
|
77.8
|
$
|
13.3
|
$
|
49.8
|
$
|
14.7
|
|||||
Gas imbalance liabilities (A)
|
8.0
|
---
|
8.0
|
---
|
|||||||||
Total
|
$
|
85.8
|
$
|
13.3
|
$
|
57.8
|
$
|
14.7
|
(A)
|
Gas
imbalance liabilities exclude fuel reserves for over retained fuel due to
shippers of approximately $4.0 million, 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.
|
December 31,
|
||||||||||||
(In millions)
|
2008
|
Level 1
|
Level 2
|
Level 3
|
||||||||
Assets
|
||||||||||||
Gross derivative assets
|
$
|
243.7
|
$
|
83.9
|
$
|
38.6
|
$
|
121.2
|
||||
Gas imbalance assets
|
6.2
|
---
|
6.2
|
---
|
||||||||
Total
|
$
|
249.9
|
$
|
83.9
|
$
|
44.8
|
$
|
121.2
|
||||
Liabilities
|
||||||||||||
Gross derivative liabilities
|
$
|
141.8
|
$
|
67.7
|
$
|
74.1
|
$
|
---
|
||||
Gas imbalance liabilities (B)
|
13.1
|
---
|
13.1
|
---
|
||||||||
Total
|
$
|
154.9
|
$
|
67.7
|
$
|
87.2
|
$
|
---
|
(B)
|
Gas
imbalance liabilities exclude fuel reserves for over retained fuel due to
shippers of approximately $11.8 million, 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.
|
December 31 (In millions)
|
2009
|
2008
|
||||
Assets
|
||||||
Gross derivative assets
|
$
|
71.3
|
$
|
243.7
|
||
Less: Amounts held in clearing broker accounts reflected in Other Current Assets
|
17.3
|
86.3
|
||||
Less: Amounts offset under master netting agreements
|
47.9
|
65.4
|
||||
Less: Net collateral payments received from counterparties
|
---
|
58.1
|
||||
Net Price Risk Management Assets
|
$
|
6.1
|
$
|
33.9
|
||
Liabilities
|
||||||
Gross derivative liabilities
|
$
|
77.8
|
$
|
141.8
|
||
Less: Amounts held in clearing broker accounts reflected in Other Current Assets
|
15.6
|
70.3
|
||||
Less: Amounts offset under master netting agreements
|
47.9
|
65.4
|
||||
Net Price Risk Management Liabilities
|
$
|
14.3
|
$
|
6.1
|
Derivative Assets
|
|||||||
Year Ended December 31 (In millions)
|
2009
|
2008
|
|||||
Balance at January 1
|
$
|
121.2
|
$
|
1.4
|
|||
Total gains or losses (realized/unrealized)
|
|||||||
Included in earnings
|
---
|
---
|
|||||
Included in other comprehensive income
|
(54.0)
|
2.4
|
|||||
Purchases, sales, issuances and settlements, net (A)
|
(18.2)
|
82.0
|
|||||
Transfers in and/or out of Level 3 (B)
|
---
|
35.4
|
|||||
Balance at December 31
|
$
|
49.0
|
$
|
121.2
|
|||
The amount of total gains or losses for the period included in earnings
|
|||||||
attributable to the change in unrealized gains or losses relating to
|
|||||||
assets held at December 31
|
$
|
---
|
$
|
---
|
|||
(A)
|
During
2008, Enogex purchased NGLs options to hedge a portion of the commodity
price risk associated with its keep-whole and percent-of-liquids
processing arrangements for 2011 and to reset the price level of a portion
of the existing hedged volumes for 2010.
|
||||||
(B)
|
During
2008, the transfers into Level 3 were primarily due to NGLs swaps and
shorter-term NGLs options being recategorized as Level 3. These
transactions were previously categorized as Level 2 based on corroboration
to price data from a related, active market. The correlation
between the markets deteriorated during the fourth quarter of 2008,
resulting in the transactions being transferred to Level
3.
|
Derivative Liabilities
|
||||||
Year Ended December 31 (In millions)
|
2009
|
2008
|
||||
Balance at January 1
|
$
|
---
|
$
|
---
|
||
Total gains or losses (realized/unrealized)
|
||||||
Included in earnings
|
---
|
---
|
||||
Included in other comprehensive income
|
14.7
|
---
|
||||
Purchases, sales, issuances and settlements, net
|
---
|
---
|
||||
Transfers in and/or out of Level 3
|
---
|
---
|
||||
Balance at December 31
|
$
|
14.7
|
$
|
---
|
||
The amount of total gains or losses for the period included in earnings
|
||||||
attributable to the change in unrealized gains or losses relating to
|
||||||
liabilities held at December 31
|
$
|
---
|
$
|
---
|
2009
|
2008
|
|||||||||||||||||
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||||
December 31 (In millions)
|
Amount
|
Value
|
Amount
|
Value
|
||||||||||||||
Price Risk Management Assets
|
||||||||||||||||||
Energy Derivative Contracts
|
$
|
6.1
|
$
|
6.1
|
$
|
33.9
|
$
|
33.9
|
||||||||||
Price Risk Management Liabilities
|
||||||||||||||||||
Energy Derivative Contracts
|
$
|
14.3
|
$
|
14.3
|
$
|
6.1
|
$
|
6.1
|
||||||||||
Long-Term Debt
|
||||||||||||||||||
OG&E Senior Notes
|
$
|
1,406.4
|
$
|
1,492.1
|
$
|
1,406.1
|
$
|
1,327.4
|
||||||||||
OGE Energy Senior Notes
|
99.5
|
102.6
|
99.5
|
93.4
|
||||||||||||||
OG&E Industrial Authority Bonds
|
135.4
|
135.4
|
135.3
|
135.3
|
||||||||||||||
Enogex Senior Notes
|
736.8
|
746.7
|
400.9
|
436.1
|
||||||||||||||
Enogex Revolving Credit Agreement
|
---
|
---
|
120.0
|
120.0
|
2009
|
2008
|
2007
|
|||||||
Expected dividend yield
|
4.5
|
%
|
3.8
|
%
|
3.6
|
%
|
|||
Expected price volatility
|
31.0
|
%
|
18.7
|
%
|
15.9
|
%
|
|||
Risk-free interest rate
|
1.25
|
%
|
2.21
|
%
|
4.47
|
%
|
|||
Expected life of units (in years)
|
2.88
|
2.84
|
2.95
|
||||||
Fair value of units granted
|
$
|
25.55
|
$
|
33.62
|
$
|
24.18
|
Stock
|
Aggregate
|
||||||
Number
|
Conversion
|
Intrinsic
|
|||||
(dollars in millions)
|
of Units
|
Ratio (A)
|
Value
|
||||
Units Outstanding at 12/31/08
|
376,616
|
1:1
|
|||||
Granted (B)
|
316,513
|
1:1
|
|||||
Converted
|
(128,755)
|
1:1
|
$
|
3.0
|
|||
Forfeited
|
(17,907)
|
1:1
|
|||||
Units Outstanding at 12/31/09
|
546,467
|
1:1
|
$
|
36.3
|
|||
Units Fully Vested at 12/31/09
|
78,997
|
1:1
|
$
|
4.1
|
Weighted-Average
|
||||||
Number
|
Grant Date
|
|||||
of Units
|
Fair Value
|
|||||
Units Non-Vested at 12/31/08
|
247,861
|
$
|
30.50
|
|||
Granted (C)
|
316,513
|
$
|
25.55
|
|||
Vested
|
(78,997)
|
$
|
24.18
|
|||
Forfeited
|
(17,907)
|
$
|
27.87
|
|||
Units Non-Vested at 12/31/09 (D)
|
467,470
|
$
|
28.27
|
Stock
|
Aggregate
|
||||||
Number
|
Conversion
|
Intrinsic
|
|||||
(dollars in millions)
|
of Units
|
Ratio (A)
|
Value
|
||||
Units Outstanding at 12/31/08
|
125,464
|
1:1
|
|||||
Granted (B)
|
105,504
|
1:1
|
|||||
Converted
|
(42,914)
|
1:1
|
$
|
2.4
|
|||
Forfeited
|
(5,968)
|
1:1
|
|||||
Units Outstanding at 12/31/09
|
182,086
|
1:1
|
$
|
2.6
|
|||
Units Fully Vested at 12/31/09
|
26,279
|
1:1
|
$
|
0.7
|
Weighted-Average
|
||||||
Number
|
Grant Date
|
|||||
of Units
|
Fair Value
|
|||||
Units Non-Vested at 12/31/08
|
82,550
|
$
|
30.66
|
|||
Granted (C)
|
105,504
|
$
|
20.02
|
|||
Vested
|
(26,279)
|
$
|
33.59
|
|||
Forfeited
|
(5,968)
|
$
|
25.17
|
|||
Units Non-Vested at 12/31/09 (D)
|
155,807
|
$
|
23.19
|
Aggregate
|
Weighted-Average
|
|||||||||||
Number
|
Weighted-Average
|
Intrinsic
|
Remaining
|
|||||||||
(dollars in millions)
|
of Options
|
Exercise Price
|
Value
|
Contractual Term
|
||||||||
Options Outstanding at 12/31/08
|
425,247
|
$
|
21.98
|
|||||||||
Exercised
|
161,903
|
$
|
21.32
|
$
|
1.7
|
|||||||
Expired
|
16,600
|
$
|
28.59
|
$
|
0.5
|
|||||||
Options Outstanding at 12/31/09
|
246,744
|
$
|
21.98
|
$
|
3.7
|
2.87
|
years
|
|||||
Options Fully Vested and Exercisable at 12/31/09
|
246,744
|
$
|
21.98
|
$
|
3.7
|
2.87
|
years
|
Ÿ
|
NGLs
put options and NGLs swaps are used to manage Enogex’s NGLs exposure
associated with its processing
agreements;
|
Ÿ
|
natural
gas swaps are used to manage Enogex’s keep-whole natural gas exposure
associated with its processing agreements and Enogex’s natural gas
exposure associated with operating its gathering, transportation and
storage assets;
|
Ÿ
|
natural
gas futures and swaps and natural gas commodity purchases and sales are
used to manage OERI’s natural gas exposure associated with its storage and
transportation contracts; and
|
Ÿ
|
natural
gas futures and swaps, natural gas options and natural gas commodity
purchases and sales are used to manage OERI’s marketing and trading
activities.
|
Notional
|
|||||
Commodity
|
Volume (A)
|
Maturity
|
|||
(volumes in millions)
|
|||||
Short Financial Swaps/Futures (fixed)
|
NGLs
|
0.5
|
Current
|
||
Purchased Financial Options
|
NGLs
|
1.3
|
Current
|
||
Purchased Financial Options
|
NGLs
|
1.3
|
Non-Current
|
||
Total Purchased Financial Options
|
2.6
|
||||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
6.3
|
Current
|
||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
5.2
|
Non-Current
|
||
Total Long Financial Swaps/Futures (fixed)
|
11.5
|
||||
Short Financial Swaps/Futures (fixed)
|
Natural Gas
|
4.0
|
Current
|
||
Short Financial Basis Swaps
|
Natural Gas
|
4.0
|
Current
|
Notional
|
|||||
Commodity
|
Volume (A)
|
Maturity
|
|||
(volumes in millions)
|
|||||
Short Financial Swaps/Futures (fixed)
|
NGLs
|
0.8
|
Current
|
||
Long Financial Swaps/Futures (fixed)
|
NGLs
|
0.8
|
Current
|
||
Physical Purchases (B)
|
Natural Gas
|
16.1
|
Current
|
||
Physical Purchases (B)
|
Natural Gas
|
4.1
|
Non-Current
|
||
Total Physical Purchases
|
20.2
|
||||
Physical Sales (B)
|
Natural Gas
|
31.3
|
Current
|
||
Physical Sales (B)
|
Natural Gas
|
13.2
|
Non-Current
|
||
Total Physical Sales
|
44.5
|
||||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
31.3
|
Current
|
||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
1.0
|
Non-Current
|
||
Total Long Financial Swaps/Futures (fixed)
|
32.3
|
||||
Short Financial Swaps/Futures (fixed)
|
Natural Gas
|
31.8
|
Current
|
||
Short Financial Swaps/Futures (fixed)
|
Natural Gas
|
2.9
|
Non-Current
|
||
Total Short Financial Swaps/Futures (fixed)
|
34.7
|
||||
Purchased Financial Option
|
Natural Gas
|
9.5
|
Current
|
||
Sold Financial Option
|
Natural Gas
|
12.8
|
Current
|
||
Long Financial Basis Swaps
|
Natural Gas
|
7.7
|
Current
|
||
Long Financial Basis Swaps
|
Natural Gas
|
1.0
|
Non-Current
|
||
Total Long Financial Basis Swaps
|
8.7
|
||||
Short Financial Basis Swaps
|
Natural Gas
|
7.0
|
Current
|
||
Short Financial Basis Swaps
|
Natural Gas
|
1.2
|
Non-Current
|
||
Total Short Financial Basis Swaps
|
8.2
|
||||
(A) Natural gas in MMBtu; NGLs in barrels. All volumes are presented on a gross basis.
|
|||||
(B) Of
the natural gas physical purchases and sales volumes not designated as
cash flow or fair value 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.
|
Fair Value
|
||||||||||||||
Balance Sheet
|
||||||||||||||
Instrument
|
Commodity
|
Location
|
Assets
|
Liabilities
|
||||||||||
(dollars in millions)
|
||||||||||||||
Derivatives Designated as Hedging Instruments
|
||||||||||||||
Financial Options
|
NGLs
|
Current PRM
|
$
|
16.4
|
$
|
---
|
||||||||
Non-Current PRM
|
23.4
|
---
|
||||||||||||
Financial Futures/Swaps
|
NGLs
|
Current PRM
|
---
|
6.1
|
||||||||||
Financial Futures/Swaps
|
Natural Gas
|
Current PRM
|
---
|
14.8
|
||||||||||
Non-Current PRM
|
---
|
19.7
|
||||||||||||
Other Current Assets
|
4.6
|
1.2
|
||||||||||||
Total Gross Derivatives Designated as Hedging Instruments
|
$
|
44.4
|
$
|
41.8
|
||||||||||
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||
Financial Futures/Swaps (A)
|
NGLs
|
Current PRM
|
$
|
9.2
|
$
|
8.6
|
||||||||
Financial Futures/Swaps (B)
|
Natural Gas
|
Current PRM
|
3.6
|
12.3
|
||||||||||
Non-Current PRM
|
---
|
0.1
|
||||||||||||
Other Current Assets
|
11.8
|
13.6
|
||||||||||||
Physical Purchases/Sales
|
Natural Gas
|
Current PRM
|
0.8
|
0.6
|
||||||||||
Non-Current PRM
|
0.6
|
---
|
||||||||||||
Financial Options
|
Natural Gas
|
Other Current Assets
|
0.9
|
0.8
|
||||||||||
Total Gross Derivatives Not Designated as Hedging Instruments
|
$
|
26.9
|
$
|
36.0
|
||||||||||
Total Gross Derivatives (C)
|
$
|
71.3
|
$
|
77.8
|
(A)
|
The
entire fair value of Financial Futures/Swaps – NGLs not designated as
hedging instruments includes derivatives that were previously designated
as hedging instruments and subsequently de-designated with offsetting
derivatives to close the hedge positions.
|
(B)
|
The
fair value of Financial Futures/Swaps – Natural Gas not designated as
hedging instruments includes derivatives that were previously designated
as hedging instruments and subsequently de-designated with offsetting
derivatives to close the hedge positions. The referenced
derivatives had a fair value as presented in the table above in Current
Assets of approximately $2.9 million and Current Liabilities of
approximately $11.7 million.
|
(C)
|
See
reconciliation of the Company’s total derivatives fair value to the
Company’s Consolidated Balance Sheet at December 31, 2009 (see Note
3).
|
Amount of
|
|||||||||||||
Gain or Loss
|
|||||||||||||
Amount of
|
Location of Gain or
|
Recognized
|
|||||||||||
Gain or Loss
|
Loss Recognized in
|
in Income on
|
|||||||||||
Amount of Gain
|
Reclassified
|
Income on
|
Derivative
|
||||||||||
or Loss
|
from
|
Derivative
|
(Ineffective
|
||||||||||
Recognized in
|
Location of Gain or
|
Accumulated
|
(Ineffective Portion
|
Portion and
|
|||||||||
OCI on
|
Loss Reclassified
|
OCI into
|
and Amount
|
Amount
|
|||||||||
Derivative
|
from Accumulated
|
Income
|
Excluded from
|
Excluded from
|
|||||||||
(Effective
|
OCI into Income
|
(Effective
|
Effectiveness
|
Effectiveness
|
|||||||||
Instrument
|
Portion)(A)
|
(Effective Portion)
|
Portion)
|
Testing)
|
Testing)
|
||||||||
(dollars in millions)
|
|||||||||||||
Derivatives in Cash Flow Hedging Relationships
|
|||||||||||||
NGLs Financial Options
|
$
|
(56.4)
|
Operating Revenues
|
$
|
1.7
|
Operating Revenues
|
$
|
---
|
|||||
NGLs Financial
|
|||||||||||||
Futures/Swaps
|
(33.7)
|
Operating Revenues
|
12.6
|
Operating Revenues
|
---
|
||||||||
Natural Gas Financial
|
|||||||||||||
Futures/Swaps
|
(19.8)
|
Operating Revenues
|
(26.5)
|
Operating Revenues
|
(0.2)
|
||||||||
Total
|
$
|
(109.9)
|
Total
|
$
|
(12.2)
|
Total
|
$
|
(0.2)
|
|||||
(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at December 31, 2009 that
is expected
to be reclassified
|
|||||||||||||
into
earnings within the next 12 months is a loss of approximately $24.4 million.
|
Amount of Gain or
|
||||
Location of Gain or
|
Loss Recognized in
|
|||
Loss Recognized in
|
Income of
|
|||
Income on Derivative
|
Derivative
|
|||
(dollars in millions)
|
||||
Derivatives Not Designated as Hedging Instruments
|
||||
Natural Gas Physical Purchases/Sales
|
Operating Revenues
|
$
|
(24.3)
|
|
Natural Gas Financial Futures/Swaps
|
Operating Revenues
|
17.7
|
||
NGLs Financial Futures/Swaps
|
Operating Revenues
|
(0.2)
|
||
Total
|
$
|
(6.8)
|
Year ended December 31 (In millions)
|
2009
|
2008
|
2007
|
||||||
NON-CASH INVESTING AND FINANCING ACTIVITIES
|
|||||||||
OU Spirit future
installment payments to developer
|
$
|
3.9
|
$
|
---
|
$
|
---
|
|||
Power plant long-term service agreement
|
---
|
3.5
|
0.7
|
||||||
Capital lease for distribution equipment
|
---
|
0.3
|
---
|
||||||
SUPPLEMENTAL CASH FLOW INFORMATION
|
|||||||||
Cash Paid During the Period for
|
|||||||||
Interest (net of interest capitalized of $14.7, $7.6, $4.9)
|
$
|
125.8
|
$
|
122.3
|
$
|
93.5
|
|||
Income taxes (net of income tax refunds)
|
2.0
|
---
|
86.6
|
7.
|
Income Taxes
|
Year ended December 31 (In millions)
|
2009
|
2008
|
2007
|
||||||
Provision (Benefit) for Current Income Taxes
|
|||||||||
Federal
|
$
|
(147.0)
|
$
|
(18.6)
|
$
|
96.0
|
|||
State
|
(3.1)
|
(0.8)
|
3.9
|
||||||
Total Provision (Benefit) for Current Income Taxes
|
(150.1)
|
(19.4)
|
99.9
|
||||||
Provision for Deferred Income Taxes, net
|
|||||||||
Federal
|
259.5
|
126.9
|
18.2
|
||||||
State
|
5.3
|
1.2
|
2.7
|
||||||
Total Provision for Deferred Income Taxes, net
|
264.8
|
128.1
|
20.9
|
||||||
Deferred Federal Investment Tax Credits, net
|
(4.2)
|
(4.6)
|
(4.8)
|
||||||
Income Taxes Relating to Other Income and Deductions
|
10.6
|
(2.9)
|
0.7
|
||||||
Total Income Tax Expense
|
$
|
121.1
|
$
|
101.2
|
$
|
116.7
|
Year ended December 31
|
2009
|
2008
|
2007
|
||||||
Statutory Federal tax rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
|||
State income taxes, net of Federal income tax benefit
|
1.0
|
0.2
|
1.9
|
||||||
Amortization of net unfunded deferred taxes
|
0.7
|
0.7
|
0.8
|
||||||
401(k) dividends
|
(0.7)
|
(0.8)
|
(1.2)
|
||||||
Medicare Part D subsidy
|
(1.1)
|
(0.3)
|
(0.3)
|
||||||
Federal investment tax credits, net
|
(1.1)
|
(1.4)
|
(1.3)
|
||||||
Federal renewable energy credit (A)
|
(2.2)
|
(2.7)
|
(2.0)
|
||||||
Other
|
0.1
|
(0.8)
|
(0.7)
|
||||||
Effective income tax rate as reported
|
31.7
|
%
|
29.9
|
%
|
32.2
|
%
|
December 31 (In millions)
|
2009
|
2008
|
||||
Current Accumulated Deferred Tax Assets
|
||||||
Federal tax credits
|
$
|
17.3
|
$
|
9.2
|
||
Derivative instruments
|
8.9
|
---
|
||||
Accrued vacation
|
7.0
|
7.2
|
||||
Accrued liabilities
|
4.7
|
5.6
|
||||
Uncollectible accounts
|
0.9
|
1.5
|
||||
Other
|
2.6
|
---
|
||||
Total Current Accumulated Deferred Tax Assets
|
41.4
|
23.5
|
||||
Current Accumulated Deferred Tax Liabilities
|
||||||
Derivative instruments
|
---
|
(7.0)
|
||||
Other
|
(1.6)
|
(1.6)
|
||||
Total Current Accumulated Deferred Tax Liabilities
|
(1.6)
|
(8.6)
|
||||
Current Accumulated Deferred Tax Assets, net
|
$
|
39.8
|
$
|
14.9
|
||
Non-Current Accumulated Deferred Tax Liabilities
|
||||||
Accelerated depreciation and other property related differences
|
$
|
1,325.6
|
$
|
1,025.7
|
||
Company pension plan
|
51.3
|
52.1
|
||||
Income taxes refundable to customers, net
|
7.4
|
5.7
|
||||
Bond redemption-unamortized costs
|
5.2
|
5.7
|
||||
Regulatory asset
|
0.2
|
3.2
|
||||
Derivative instruments
|
---
|
17.0
|
||||
Total Non-Current Accumulated Deferred Tax Liabilities
|
1,389.7
|
1,109.4
|
||||
Non-Current Accumulated Deferred Tax Assets
|
||||||
Regulatory liabilities
|
(51.1)
|
(58.5)
|
||||
Postretirement medical and life insurance benefits
|
(52.5)
|
(34.3)
|
||||
State tax credits
|
(29.9)
|
(11.8)
|
||||
Deferred Federal investment tax credits
|
(5.1)
|
(6.7)
|
||||
Derivative instruments
|
(3.4)
|
---
|
||||
Other
|
(1.1)
|
(1.2)
|
||||
Total Non-Current Accumulated Deferred Tax Assets
|
(143.1)
|
(112.5)
|
||||
Non-Current Accumulated Deferred Income Tax Liabilities, net
|
$
|
1,246.6
|
$
|
996.9
|
Year ended December 31 (In millions)
|
2009
|
2008
|
2007
|
|||||||||
Average Common Shares Outstanding
|
||||||||||||
Basic average common shares outstanding
|
96.2
|
92.4
|
91.7
|
|||||||||
Effect of dilutive securities:
|
||||||||||||
Employee stock options and unvested stock grants
|
---
|
0.1
|
0.3
|
|||||||||
Contingently issuable shares (performance units)
|
1.0
|
0.3
|
0.5
|
|||||||||
Diluted average common shares outstanding
|
97.2
|
92.8
|
92.5
|
|||||||||
Anti-dilutive shares excluded from EPS calculation
|
---
|
---
|
---
|
SERIES
|
DATE DUE
|
AMOUNT
|
||
0.30% - 1.00% Garfield Industrial Authority, January 1, 2025
|
$
|
47.0
|
||
0.42% - 0.74% Muskogee Industrial Authority, January 1, 2025
|
32.4
|
|||
0.42% - 0.75% Muskogee Industrial Authority, June 1, 2027
|
56.0
|
|||
Total (redeemable during next 12 months)
|
$
|
135.4
|
Revolving Credit Agreements and Available Cash (In millions)
|
||||||||
Aggregate
|
Amount
|
Weighted-Average
|
||||||
Entity
|
Commitment
|
Outstanding (A)
|
Interest Rate
|
Maturity
|
||||
OGE Energy (B)
|
$
|
596.0
|
$
|
175.0
|
0.27% (D)
|
December 6, 2012
|
||
OG&E (C)
|
389.0
|
10.2
|
0.14% (D)
|
December 6, 2012
|
||||
Enogex (E)
|
250.0
|
---
|
---% (D)
|
March 31, 2013
|
||||
1,235.0
|
185.2
|
0.26%
|
||||||
Cash
|
58.1
|
N/A
|
N/A
|
N/A
|
||||
Total
|
$
|
1,293.1
|
$
|
185.2
|
0.26%
|
|||
(A)
Includes direct borrowings under the revolving credit agreements,
commercial paper borrowings and letters of credit at December 31,
2009.
(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, 2009, there were no outstanding
borrowings under this revolving credit agreement and approximately $175.0
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, 2009, there was approximately $10.2
million supporting letters of credit. There were no outstanding
borrowings under this revolving credit agreement and no outstanding
commercial paper borrowings at December 31, 2009.
(D)
Represents the weighted-average interest rate for the outstanding
borrowings under the revolving credit agreements and commercial paper
borrowings.
(E)
This bank facility is available to provide revolving credit borrowings for
Enogex. At December 31, 2009, there were no outstanding
borrowings under this revolving credit
agreement.
|
11.
|
Retirement
Plans and Postretirement Benefit
Plans
|
(In millions)
|
OG&E
(A)
|
Enogex
|
OGE
Energy
|
Total
|
||||||||
Pension
Settlement Charge:
|
||||||||||||
2007
|
$
|
13.3
|
$
|
0.5
|
$
|
2.9
|
$
|
16.7
|
||||
Retirement
Restoration Plan Settlement Charge:
|
||||||||||||
2007
|
$
|
0.1
|
$
|
---
|
$
|
2.2
|
$
|
2.3
|
Asset
Class
|
Target
Allocation
|
Minimum
|
Maximum
|
|||||||
Domestic All-Cap Equity
|
20
|
%
|
---
|
%
|
25
|
%
|
||||
Domestic Equity Passive
|
10
|
%
|
---
|
%
|
60
|
%
|
||||
Domestic Mid-Cap Equity
|
10
|
%
|
---
|
%
|
10
|
%
|
||||
Domestic Small-Cap Equity
|
10
|
%
|
---
|
%
|
10
|
%
|
||||
International Equity
|
15
|
%
|
---
|
%
|
15
|
%
|
||||
Fixed Income Domestic
|
35
|
%
|
30
|
%
|
70
|
%
|
Asset Class
|
Comparative Benchmark(s)
|
Fixed Income
|
Barclays
Capital Aggregate Index
|
Equity Index
|
S&P 500 Index
|
Value Equity
|
Russell 1000 Value Index – Short-term
|
S&P 500 Index – Long-term
|
|
Growth Equity
|
Russell 1000 Growth Index – Short-term
|
S&P 500 Index – Long-term
|
|
Mid-Cap Equity
|
S&P 400 Midcap Index
|
Small-Cap Equity
|
Russell 2000 Index
|
International Equity
|
Morgan Stanley Capital International Europe, Australia and Far East Index
|
(In
millions)
|
Total
|
Level
1
|
Level
2
|
||||||
Common
stocks
|
|||||||||
U.S.
common stocks
|
$
|
152.4
|
$
|
152.4
|
$
|
---
|
|||
Foreign
common stocks
|
57.2
|
57.2
|
---
|
||||||
Bonds,
debentures and notes (A)
|
|||||||||
Bonds,
debentures and notes
|
119.1
|
---
|
119.1
|
||||||
Mortgage-backed
securities
|
8.6
|
---
|
8.6
|
||||||
U.S.
Government obligations
|
|||||||||
Mortgage-backed
securities
|
72.3
|
---
|
72.3
|
||||||
U.S.
treasury notes and bonds (B)
|
22.2
|
22.2
|
---
|
||||||
Other
securities
|
4.5
|
---
|
4.5
|
||||||
Commingled
fund (C)
|
32.8
|
---
|
32.8
|
||||||
Common
collective trust (D)
|
15.9
|
---
|
15.9
|
||||||
Foreign
government bonds
|
5.1
|
---
|
5.1
|
||||||
U.S.
municipal bonds
|
2.5
|
---
|
2.5
|
||||||
Foreign
mutual funds
|
2.0
|
2.0
|
---
|
||||||
Foreign
preferred stock
|
0.9
|
0.9
|
---
|
||||||
U.S.
mutual funds
|
0.8
|
0.8
|
---
|
||||||
Total
|
$
|
496.3
|
$
|
235.5
|
$
|
260.8
|
(In
millions)
|
Total
|
Level
1
|
Level
3
|
||||||
Group
retiree medical insurance contract (A)
|
$
|
49.3
|
$
|
---
|
$
|
49.3
|
|||
U.S.
mutual fund (B)
|
4.9
|
4.9
|
---
|
||||||
Cash
|
0.8
|
0.8
|
---
|
||||||
Total
|
$
|
55.0
|
$
|
5.7
|
$
|
49.3
|
Group
retiree medical insurance contract
|
|||
Year
Ended December 31 (In
millions)
|
2009
|
||
Balance
at January 1
|
$
|
55.1
|
|
Actual
return on plan assets relating to assets held at the reporting
date
|
(5.8)
|
||
Purchases,
sales, issuances and settlements, net
|
---
|
||
Transfers
in and/or out of Level 3
|
---
|
||
Balance
at December 31
|
$
|
49.3
|
ONE-PERCENTAGE
POINT INCREASE
|
|||||||||
Year
ended December 31 (In
millions)
|
2009
|
2008
|
2007
|
||||||
Effect
on aggregate of the service and interest cost components
|
$
|
2.4
|
$
|
2.2
|
$
|
2.3
|
|||
Effect
on accumulated postretirement benefit obligations
|
40.3
|
28.3
|
26.9
|
ONE-PERCENTAGE
POINT DECREASE
|
|||||||||
Year
ended December 31 (In
millions)
|
2009
|
2008
|
2007
|
||||||
Effect
on aggregate of the service and interest cost components
|
$
|
1.9
|
$
|
1.8
|
$
|
1.9
|
|||
Effect
on accumulated postretirement benefit obligations
|
32.9
|
23.4
|
22.2
|
Restoration
of Retirement
|
Postretirement
|
|||||||||||||||||
Pension
Plan
|
Income
Plan
|
Benefit
Plans
|
||||||||||||||||
December
31 (In
millions)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Change
in Benefit Obligation
|
||||||||||||||||||
Beginning
obligations
|
$
|
(547.0)
|
$
|
(518.0)
|
$
|
(7.3)
|
$
|
(4.0)
|
$
|
(234.3)
|
$
|
(216.8)
|
||||||
Service
cost
|
(18.1)
|
(19.0)
|
(0.7)
|
(0.7)
|
(3.3)
|
(3.7)
|
||||||||||||
Interest
cost
|
(31.4)
|
(31.4)
|
(0.4)
|
(0.4)
|
(14.1)
|
(13.4)
|
||||||||||||
Plan
amendments
|
(10.2)
|
---
|
(0.5)
|
---
|
---
|
---
|
||||||||||||
Plan
curtailments
|
0.4
|
---
|
---
|
---
|
---
|
---
|
||||||||||||
Participants’
contributions
|
---
|
---
|
---
|
---
|
(6.8)
|
(6.0)
|
||||||||||||
Actuarial
gains (losses)
|
(39.3)
|
(19.5)
|
0.1
|
(2.7)
|
(45.2)
|
(9.2)
|
||||||||||||
Benefits
paid
|
34.7
|
40.9
|
0.5
|
0.5
|
15.7
|
14.8
|
||||||||||||
Ending
obligations
|
(610.9)
|
(547.0)
|
(8.3)
|
(7.3)
|
(288.0)
|
(234.3)
|
||||||||||||
Change
in Plans’ Assets
|
||||||||||||||||||
Beginning
fair value
|
389.9
|
514.2
|
---
|
---
|
57.0
|
78.5
|
||||||||||||
Actual return on plans’ assets
|
91.1
|
(133.4)
|
---
|
---
|
(7.3)
|
(19.2)
|
||||||||||||
Employer
contributions
|
50.0
|
50.0
|
0.5
|
0.5
|
14.2
|
6.5
|
||||||||||||
Participants’
contributions
|
---
|
---
|
---
|
---
|
6.8
|
6.0
|
||||||||||||
Benefits
paid
|
(34.7)
|
(40.9)
|
(0.5)
|
(0.5)
|
(15.7)
|
(14.8)
|
||||||||||||
Ending
fair value
|
496.3
|
389.9
|
---
|
---
|
55.0
|
57.0
|
||||||||||||
Funded
status at end of year
|
$
|
(114.6)
|
$
|
(157.1)
|
$
|
(8.3)
|
$
|
(7.3)
|
$
|
(233.0)
|
$
|
(177.3)
|
Restoration
of Retirement
|
Postretirement
|
||||||||||||||||||
Pension
Plan
|
Income
Plan
|
Benefit
Plans
|
|||||||||||||||||
Year
ended December 31
|
|||||||||||||||||||
(In
millions)
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||||
Service cost
|
$
|
18.1
|
$
|
19.0
|
$
|
20.6
|
$
|
0.7
|
$
|
0.8
|
$
|
0.6
|
$
|
3.3
|
$
|
3.7
|
$
|
4.0
|
|
Interest cost
|
31.4
|
31.4
|
31.8
|
0.4
|
0.4
|
0.5
|
14.1
|
13.4
|
12.4
|
||||||||||
Return on plan assets
|
(33.0)
|
(43.7)
|
(43.9)
|
---
|
---
|
---
|
(6.5)
|
(6.5)
|
(5.9)
|
||||||||||
Amortization of transition
|
|||||||||||||||||||
obligation
|
---
|
---
|
---
|
---
|
---
|
2.7
|
2.7
|
2.7
|
|||||||||||
Amortization of net loss
|
23.5
|
9.3
|
10.5
|
0.3
|
0.3
|
0.2
|
5.0
|
4.0
|
6.1
|
||||||||||
Amortization of unrecognized
|
|||||||||||||||||||
prior service cost
|
0.8
|
0.9
|
5.2
|
0.6
|
0.6
|
0.6
|
1.0
|
1.9
|
2.1
|
||||||||||
Settlement
|
---
|
---
|
16.7
|
---
|
---
|
2.3
|
---
|
---
|
---
|
||||||||||
Net
periodic benefit cost (A)
|
$
|
40.8
|
$
|
16.9
|
$
|
40.9
|
$
|
2.0
|
$
|
2.1
|
$
|
4.2
|
$
|
19.6
|
$
|
19.2
|
$
|
21.4
|
|
(A)
In addition to the approximately $42.8 million, $19.0 million and $45.1
million of net periodic benefit cost recognized in 2009, 2008 and 2007,
respectively, the Company recognized the following:
|
|||||||||||||||||||
Ÿ
|
a
reduction in pension expense in 2009 of approximately $2.2 million, an
increase in pension expense in 2008 of approximately $10.1 million and a
reduction in pension expense in 2007 of approximately $10.1 million to
maintain the allowable amount to be recovered for pension expense in the
Oklahoma jurisdiction which are identified as Deferred Pension Plan
Expenses (see Note 1); and
|
||||||||||||||||||
Ÿ
|
a
reduction in pension expense in 2009 of approximately $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 identified as Deferred Pension Plan Expenses (see Note
1).
|
||||||||||||||||||
The
capitalized portion of the net periodic pension benefit cost was
approximately $8.4 million, $4.0 million and $5.5 million at December 31,
2009, 2008 and 2007, respectively. The capitalized portion of
the net periodic postretirement benefit cost was approximately $4.1
million, $4.6 million and $4.8 million at December 31, 2009, 2008 and
2007, respectively.
|
Pension
Plan and
|
Postretirement
|
|||||
Restoration
of Retirement Income Plan
|
Benefit
Plans
|
|||||
Year
ended December 31
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
Discount
rate
|
5.30%
|
6.25%
|
6.25%
|
6.00%
|
6.25%
|
6.25%
|
Rate
of return on plans’ assets
|
8.50%
|
8.50%
|
8.50%
|
8.50%
|
8.50%
|
8.50%
|
Compensation
increases
|
4.50%
|
4.50%
|
4.50%
|
N/A
|
N/A
|
N/A
|
Assumed
health care cost trend:
|
||||||
Initial
trend
|
N/A
|
N/A
|
N/A
|
9.49%
|
9.00%
|
9.00%
|
Ultimate
trend rate
|
N/A
|
N/A
|
N/A
|
5.00%
|
4.50%
|
4.50%
|
Ultimate
trend year
|
N/A
|
N/A
|
N/A
|
2018
|
2014
|
2013
|
Transportation
|
Gathering
|
|||||||||||||
Electric
|
and
|
and
|
Other
|
|||||||||||
2009
|
Utility
|
Storage
|
Processing
|
Marketing
|
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
|
$
|
1,597.7
|
$
|
866.1
|
$
|
125.2
|
$
|
2,685.4
|
$
|
(3,485.8)
|
$
|
7,266.7
|
Capital
expenditures
|
$
|
600.5
|
$
|
71.4
|
$
|
166.0
|
$
|
---
|
$
|
10.2
|
$
|
(0.3)
|
$
|
847.8
|
Transportation
|
Gathering
|
|||||||||||||
Electric
|
and
|
and
|
Other
|
|||||||||||
2008
|
Utility
|
Storage
|
Processing
|
Marketing
|
Operations
|
Eliminations
|
Total
|
|||||||
(In
millions)
|
||||||||||||||
Operating
revenues
|
$
|
1,959.5
|
$
|
625.9
|
$
|
1,053.2
|
$
|
1,529.4
|
$
|
---
|
$
|
(1,097.3)
|
$
|
4,070.7
|
Cost
of goods sold
|
1,114.9
|
479.7
|
806.4
|
1,509.5
|
---
|
(1,092.5)
|
2,818.0
|
|||||||
Gross
margin on revenues
|
844.6
|
146.2
|
246.8
|
19.9
|
---
|
(4.8)
|
1,252.7
|
|||||||
Other
operation and maintenance (A)
|
351.6
|
48.2
|
87.3
|
12.9
|
(2.0)
|
(5.8)
|
492.2
|
|||||||
Depreciation
and amortization
|
155.0
|
17.5
|
37.1
|
0.2
|
7.7
|
---
|
217.5
|
|||||||
Impairment
of assets
|
---
|
---
|
0.4
|
---
|
---
|
---
|
0.4
|
|||||||
Taxes
other than income
|
59.7
|
12.7
|
4.6
|
0.4
|
3.1
|
---
|
80.5
|
|||||||
Operating
income (loss)
|
$
|
278.3
|
$
|
67.8
|
$
|
117.4
|
$
|
6.4
|
$
|
(8.8)
|
$
|
1.0
|
$
|
462.1
|
Total
assets
|
$
|
4,851.2
|
$
|
1,265.9
|
$
|
836.9
|
$
|
235.1
|
$
|
2,469.1
|
$
|
(3,139.7)
|
$
|
6,518.5
|
Capital
expenditures
|
$
|
840.1
|
$
|
93.3
|
$
|
240.2
|
$
|
---
|
$
|
12.9
|
$
|
(2.0)
|
$
|
1,184.5
|
Transportation
|
Gathering
|
|||||||||||||
Electric
|
and
|
and
|
Other
|
|||||||||||
2007
|
Utility
|
Storage
(B)
|
Processing
(B)
|
Marketing
|
Operations
|
Eliminations
|
Total
|
|||||||
(In
millions)
|
||||||||||||||
Operating
revenues
|
$
|
1,835.1
|
$
|
529.1
|
$
|
799.4
|
$
|
1,541.2
|
$
|
---
|
$
|
(907.2)
|
$
|
3,797.6
|
Cost
of goods sold
|
1,025.1
|
396.4
|
603.5
|
1,513.4
|
---
|
(903.7)
|
2,634.7
|
|||||||
Gross
margin on revenues
|
810.0
|
132.7
|
195.9
|
27.8
|
---
|
(3.5)
|
1,162.9
|
|||||||
Other
operation and
|
||||||||||||||
maintenance
|
320.7
|
48.5
|
72.1
|
10.1
|
(11.3)
|
(3.3)
|
436.8
|
|||||||
Depreciation and amortization
|
141.3
|
17.0
|
28.7
|
0.2
|
8.1
|
---
|
195.3
|
|||||||
Impairment
of assets
|
---
|
0.5
|
---
|
---
|
---
|
---
|
0.5
|
|||||||
Taxes
other than income
|
56.0
|
11.7
|
3.7
|
0.4
|
3.2
|
---
|
75.0
|
|||||||
Operating
income
|
$
|
292.0
|
$
|
55.0
|
$
|
91.4
|
$
|
17.1
|
$
|
---
|
$
|
(0.2)
|
$
|
455.3
|
Total
assets
|
$
|
3,874.9
|
$
|
1,519.3
|
$
|
931.4
|
$
|
253.2
|
$
|
2,297.6
|
$
|
(3,638.6)
|
$
|
5,237.8
|
Capital
expenditures
|
$
|
377.3
|
$
|
49.0
|
$
|
125.0
|
$
|
0.2
|
$
|
14.5
|
$
|
(8.3)
|
$
|
557.7
|
2015
and
|
||||||||||||||
Year
ended December 31 (In
millions)
|
2010
|
2011
|
2012
|
2013
|
2014
|
Beyond
|
Total
|
|||||||
Operating
lease obligations
|
||||||||||||||
OG&E railcars
|
$
|
3.9
|
$
|
38.0
|
$
|
---
|
$
|
---
|
$
|
---
|
$
|
---
|
$
|
41.9
|
Enogex noncancellable operating
leases
|
2.5
|
1.6
|
0.4
|
---
|
---
|
---
|
4.5
|
|||||||
Total operating lease
obligations
|
$
|
6.4
|
$
|
39.6
|
$
|
0.4
|
$
|
---
|
$
|
---
|
$
|
---
|
$
|
46.4
|
/s/ Ernst
& Young LLP
|
||
Ernst
& Young LLP
|
Quarter
ended (In millions,
except per share data)
|
March
31
|
June
30
|
September
30
|
December
31
|
Total
|
|||||||||||
Operating
revenues
|
2009
|
$
|
606.6
|
$
|
644.1
|
$
|
845.3
|
$
|
773.7
|
$
|
2,869.7
|
|||||
2008
|
994.7
|
1,135.7
|
1,254.3
|
686.0
|
4,070.7
|
|||||||||||
Operating
income
|
2009
|
$
|
52.0
|
$
|
126.4
|
$
|
229.7
|
$
|
83.8
|
$
|
491.9
|
|||||
2008
|
48.1
|
122.7
|
231.2
|
60.1
|
(A)
|
462.1
|
||||||||||
Net
income
|
2009
|
$
|
17.6
|
$
|
70.9
|
$
|
137.5
|
$
|
35.1
|
$
|
261.1
|
|||||
2008
|
14.6
|
58.8
|
141.4
|
22.6
|
(A)
|
237.4
|
||||||||||
Net
income attributable to OGE Energy
|
2009
|
$
|
16.8
|
$
|
70.5
|
$
|
136.8
|
$
|
34.2
|
$
|
258.3
|
|||||
2008
|
13.0
|
57.1
|
139.5
|
21.8
|
(A)
|
231.4
|
||||||||||
Basic earnings
per average common share
|
||||||||||||||||
attributable to OGE Energy common
|
2009
|
$
|
0.18
|
$
|
0.73
|
$
|
1.42
|
$
|
0.35
|
$
|
2.68
|
|||||
shareholders
(B)
|
2008
|
0.14
|
0.62
|
1.51
|
0.23
|
(A)
|
2.50
|
|||||||||
Diluted
earnings per average common share
|
||||||||||||||||
attributable
to OGE Energy common
|
2009
|
$
|
0.18
|
$
|
0.72
|
$
|
1.40
|
$
|
0.35
|
$
|
2.66
|
|||||
shareholders
(B)
|
2008
|
0.14
|
0.62
|
1.50
|
0.23
|
(A)
|
2.49
|
COMMON
STOCK
|
Ÿ
|
Common
quarterly dividends paid (as declared) in 2009 were $0.3550 each for the
first three quarters of 2009 and was $0.3625 for the fourth quarter of
2009. Common quarterly dividends paid (as declared) in 2008
were $0.3475 each for the first three quarters of 2008 and was $0.3550 for
the fourth quarter of 2008. Common quarterly dividends paid (as
declared) in 2007 were $0.34 each for the first three quarters of 2007 and
was $0.3475 for the fourth quarter of
2007.
|
Ÿ
|
Present
rate – $0.3625
|
Ÿ
|
Payable
30th of January, April, July, and
October
|
/s/
Peter B. Delaney
|
/s/
Danny P. Harris
|
|
Peter
B. Delaney, Chairman of the Board, President
|
Danny
P. Harris, Senior Vice President
|
|
and
Chief Executive Officer
|
and
Chief Operating Officer
|
|
/s/
Sean Trauschke
|
/s/
Scott Forbes
|
|
Sean
Trauschke, Vice President
|
Scott
Forbes, Controller
|
|
and
Chief Financial Officer
|
and
Chief Accounting Officer
|
/s/ Ernst
& Young LLP
|
||
Ernst & Young LLP
|
Ÿ
|
Consolidated
Statements of Income for the years ended December 31, 2009, 2008 and
2007
|
Ÿ
|
Consolidated
Balance Sheets at December 31, 2009 and
2008
|
Ÿ
|
Consolidated
Statements of Capitalization at December 31, 2009 and
2008
|
Ÿ
|
Consolidated
Statements of Changes in Stockholders’ Equity for the years ended December
31, 2009, 2008 and 2007
|
Ÿ
|
Consolidated
Statements of Cash Flows for the years ended December 31, 2009, 2008 and
2007
|
Ÿ
|
Notes
to Consolidated Financial
Statements
|
Ÿ
|
Report
of Independent Registered Public Accounting Firm (Audit of Financial
Statements)
|
Ÿ
|
Management’s
Report on Internal Control Over Financial
Reporting
|
Ÿ
|
Report
of Independent Registered Public Accounting Firm (Audit of Internal
Control)
|
Ÿ
|
Interim
Consolidated Financial Information
|
2. Financial Statement
Schedule (included in Part IV)
|
Page
|
||
Schedule
II - Valuation and Qualifying Accounts
|
166
|
2.01
|
Purchase
Agreement, dated as of May 14, 1999, by and between Tejas Gas, LLC and
Enogex Inc. (Filed as Exhibit 2.01 to OGE Energy’s Form 10-Q for the
quarter ended June 30, 1999 (File No. 1-12579) and incorporated by
reference herein)
|
|
2.02
|
Asset
Purchase Agreement, dated as of August 18, 2003 by and between OG&E
and NRG McClain LLC. (Certain exhibits and schedules were
omitted and registrant agrees to furnish supplementally a copy of such
omitted exhibits and schedules to the Commission upon request) (Filed as
Exhibit 2.01 to OGE Energy’s Form 8-K filed August 20, 2003 (File No.
1-12579) and incorporated by reference herein)
|
|
2.03
|
Amendment
No. 1 to Asset Purchase Agreement, dated as of October 22, 2003 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE
Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.04
|
Amendment
No. 2 to Asset Purchase Agreement, dated as of October 27, 2003 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.04 to OGE
Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.05
|
Amendment
No. 3 to Asset Purchase Agreement, dated as of November 25, 2003 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.05 to OGE
Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.06
|
Amendment
No. 4 to Asset Purchase Agreement, dated as of January 28, 2004 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.06 to OGE
Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.07
|
Amendment
No. 5 to Asset Purchase Agreement, dated as of February 13, 2004 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.07 to OGE
Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.08
|
Amendment
No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE
Energy’s Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.09
|
Amendment
No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE
Energy’s Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.10
|
Amendment
No. 8 to Asset Purchase Agreement, dated as of May 15, 2004 by and between
OG&E and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy’s Form
10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and
incorporated by reference herein)
|
|
2.11
|
Amendment
No. 9 to Asset Purchase Agreement, dated as of June 2, 2004 by and between
OG&E and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy’s Form
10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and
incorporated by reference herein)
|
2.12
|
Amendment
No. 10 to Asset Purchase Agreement, dated as of June 17, 2004 by and
between OG&E and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE
Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.13
|
Stock
purchase agreement dated September 21, 2005 by and between Enogex Inc. and
Atlas Pipeline Partners, L.P. (Filed as Exhibit 10.01 to OGE Energy’s Form
8-K filed September 27, 2005 (File No. 1-12579) and incorporated by
reference herein)
|
|
2.14
|
Asset
purchase agreement dated March 30, 2006, by and between Enogex Gas
Gathering, L.L.C. and Hiland Operating, Inc. (Filed as Exhibit 2.01 to OGE
Energy’s Form 8-K filed April 4, 2006 (File No. 1-12579) and incorporated
by reference herein)
|
|
2.15
|
Purchase
and Sale Agreement, dated as of January 21, 2008, entered into by and
among Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III,
LLC and OG&E. (Certain exhibits and schedules hereto have been omitted
and the registrant agrees to furnish supplementally a copy of such omitted
exhibits and schedules to the Commission upon request) (Filed as Exhibit
2.01 to OGE Energy’s Form 8-K filed January 25, 2008 (File No. 1-12579)
and incorporated by reference herein)
|
|
2.16
|
Asset
Purchase 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. (Certain exhibits and schedules hereto have been omitted
and the registrant agrees to furnish supplementally a copy of such omitted
exhibits and schedules to the Commission upon request) (Filed as Exhibit
2.01 to OGE Energy’s Form 8-K filed January 25, 2008 (File No. 1-12579)
and incorporated by reference herein)
|
|
3.01
|
Copy
of Restated Certificate of Incorporation. (Filed as Exhibit
3.01 to OGE Energy’s Form 10-K for the year ended December 31, 1996 (File
No. 1-12579) and incorporated by reference herein)
|
|
3.02
|
Copy
of Amended OGE Energy Corp. By-laws. (Filed as Exhibit 3.01 to OGE
Energy’s Form 8-K filed January 23, 2007 (File No. 1-12579) and
incorporated by reference herein)
|
|
4.01
|
Trust
Indenture dated October 1, 1995, from OG&E to Boatmen’s First National
Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to Registration
Statement No. 33-61821 and incorporated by reference herein)
|
|
4.02
|
Supplemental
Trust 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.
|
|
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 Amended and Restated Rights Agreement, dated as of October 10, 2000
between OGE Energy Corp. and Chase Mellon Shareholder Services, LLC. (now
BNY Mellon Shareowner Services), as Rights Agent. (Filed as Exhibit 4.1 to
OGE Energy’s Form 8-K filed November 1, 2000 (File No. 1-12579) and
incorporated by reference herein)
|
|
10.05
|
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)
|
|
10.06
|
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)
|
|
10.07
|
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)
|
|
10.08
|
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)
|
|
10.09*
|
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)
|
|
10.10
|
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)
|
|
10.11
|
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)
|
|
10.12*
|
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,
2009 (File No. 1-12579) and incorporated by reference herein)
|
|
10.13*
|
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)
|
|
10.14
|
Credit
agreement dated December 6, 2006, by and between the Company, the Lenders
thereto, Wachovia Bank, National Association, as Administrative Agent,
JPMorgan Chase Bank, N.A., as Syndication Agent, and The Royal Bank of
Scotland plc, UBS Securities LLC and Union Bank of California, N.A., as
Co-Documentation Agents. (Filed as Exhibit 99.01 to OGE
Energy’s Form 8-K filed December 12, 2006 (File No. 1-12579) and
incorporated by reference herein)
|
|
10.15
|
Credit
agreement dated December 6, 2006, by and between OG&E, the Lenders
thereto, Wachovia Bank, National Association, as Administrative Agent,
JPMorgan Chase Bank, N.A., as Syndication Agent, and The Royal Bank of
Scotland plc, Mizuho Corporate Bank and Union Bank of California, N.A., as
Co-Documentation Agents. (Filed as Exhibit 99.02 to OGE
Energy’s Form 8-K filed December 12, 2006 (File No. 1-12579) and
incorporated by reference herein)
|
|
10.16*
|
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)
|
|
10.17*
|
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)
|
|
10.18
|
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)
|
|
10.19
|
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)
|
|
10.20
|
Letter
of extension for the Company’s credit agreement dated November 11, 2007,
by and between the Company and the Lenders thereto, related to the
Company’s credit agreement dated December 6, 2006. (Filed as Exhibit 10.35
to OGE Energy’s Form 10-K for the year ended December 31, 2007 (File No.
1-12579) and incorporated by reference herein)
|
|
10.21
|
Letter
of extension for OG&E’s credit agreement dated November 11, 2007, by
and between OG&E and the Lenders thereto, related to OG&E’s credit
agreement dated December 6, 2006. (Filed as Exhibit 10.36 to OGE Energy’s
Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and
incorporated by reference herein)
|
|
10.22
|
Credit
Agreement dated as of April 1, 2008, by and among Enogex LLC, the Lenders
thereto, Wachovia Bank, National Association, as Administrative Agent, The
Royal Bank of Scotland plc, as Syndication Agent, and
|
|
JPMorgan
Chase Bank, N.A, Mizuho Corporate Bank, LTD. and Union Bank of California,
as Co-Documentation Agents. (Filed as Exhibit 10.01 to OGE Energy’s Form
8-K filed April 7, 2008 (File No. 1-12579) and incorporated by reference
herein)
|
|
10.23*
|
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)
|
|
10.24*
|
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)
|
|
10.25*
|
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)
|
|
10.26*
|
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)
|
|
10.27*
|
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)
|
|
10.28*
|
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)
|
|
10.29*
|
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)
|
|
10.30*
|
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)
|
|
10.31*
|
Form
of Amended and Restated Change of Control Agreement with current officers
of the Company. (Filed as Exhibit 10.01 to OGE Energy’s Form 10-Q for the
quarter ended June 30, 2008 (File No. 1-12579) and incorporated by
reference herein)
|
|
10.32*
|
Amended
and Restated Change of Control Agreement with Peter B. Delaney. (Filed as
Exhibit 10.02 to OGE Energy’s Form 10-Q for the quarter ended June 30,
2008 (File No. 1-12579) and incorporated by reference herein)
|
|
10.33*
|
Form
of Change of Control Agreement with future officers of the Company. (Filed
as Exhibit 10.02 to OGE Energy’s Form 10-Q for the quarter ended June 30,
2009 (File No. 1-12579) and incorporated by reference herein)
|
|
10.34*
|
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)
|
|
10.35*
|
Directors’
Compensation.
|
|
10.36*
|
Executive
Officer Compensation.
|
|
10.37*
|
Employment
Arrangement between the Company and Sean Trauschke, the Company’s Chief
Financial Officer. (Filed as Exhibit 10.01 to OGE Energy’s Form 10-Q for
the quarter ended March 31, 2009 (File No. 1-12579) and incorporated by
reference herein)
|
|
10.38*
|
Change
of Control Arrangement between the Company and Sean Trauschke, the
Company’s Chief Financial Officer. (Filed as Exhibit 10.01 to OGE Energy’s
Form 8-K filed May 8, 2009 (File No. 1-12579) and incorporated by
reference herein)
|
10.39
|
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)
|
|
10.40*
|
Amendment
No. 1 to the Company’s Restoration of Retirement Income Plan.
|
|
10.41*
|
Amendment
No. 1 to the Company’s Deferred Compensation Plan.
|
|
12.01
|
Calculation
of Ratio of Earnings to Fixed Charges.
|
|
18.01
|
Letter
from Ernst & Young LLP related to a change in accounting principle.
(Filed as Exhibit 18.01 to OGE Energy’s Form 10-Q for the quarter ended
March 31, 2008 (File No. 1-12579) and incorporated by reference
herein)
|
|
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-15(e)/15d-15(e) 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 May 27, 2009 (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)
|
OGE
ENERGY CORP.
|
|||||||||||||||
SCHEDULE
II - Valuation and Qualifying Accounts
|
|||||||||||||||
Additions
|
|||||||||||||||
Balance
at
|
Charged
to
|
Charged
to
|
Balance
at
|
||||||||||||
Beginning
|
Costs
and
|
Other
|
End
of
|
||||||||||||
Description
|
of
Period
|
Expenses
|
Accounts
|
Deductions
|
Period
|
||||||||||
(In
millions)
|
|||||||||||||||
Year
Ended December 31, 2007
|
|||||||||||||||
Reserve
for Uncollectible Accounts
|
$
|
4.4
|
$
|
6.0
|
$
|
---
|
$
|
6.6 (A)
|
$
|
3.8
|
|||||
Year
Ended December 31, 2008
|
|||||||||||||||
Reserve
for Uncollectible Accounts
|
$
|
3.8
|
$
|
5.0
|
$
|
---
|
$
|
5.6 (A)
|
$
|
3.2
|
|||||
Year
Ended December 31, 2009
|
|||||||||||||||
Reserve
for Uncollectible Accounts
|
$
|
3.2
|
$
|
3.1
|
$
|
---
|
$
|
3.9
(A)
|
$
|
2.4
|
|||||
(A) Uncollectible
accounts receivable written off, net of
recoveries.
|
OGE
ENERGY CORP.
|
||
(Registrant)
|
||
By /s/
Peter B.
Delaney
|
||
Peter
B.
Delaney
|
||
Chairman
of the Board, President
|
||
and
Chief Executive Officer
|
||
Signature
|
Title
|
Date
|
|||
/ s
/ Peter B. Delaney
|
|||||
Peter
B. Delaney
|
Principal
Executive
|
||||
Officer
and Director;
|
February
18, 2010
|
||||
/ s
/ Sean Trauschke
|
|||||
Sean
Trauschke
|
Principal
Financial Officer; and
|
February
18, 2010
|
|||
/ s
/ Scott Forbes
|
|||||
Scott
Forbes
|
Principal
Accounting Officer.
|
February
18, 2010
|
|||
Wayne
H. Brunetti
|
Director;
|
||||
Luke
R. Corbett
|
Director;
|
||||
John
D. Groendyke
|
Director;
|
||||
Kirk
Humphreys
|
Director;
|
||||
Robert
Kelley
|
Director;
|
||||
Linda
P. Lambert
|
Director;
|
||||
Robert
O. Lorenz
|
Director;
|
||||
Leroy
C. Richie
|
Director;
and
|
||||
J.
D. Williams
|
Director.
|
/ s
/ Peter B. Delaney
|
|||||
By
Peter B. Delaney (attorney-in-fact)
|
February
18, 2010
|
|