redone10k.htm
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
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Page
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1
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2
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The
Company
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2
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Electric
Operations –
OG&E
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4
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|
4
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6
|
|
10
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Fuel
Supply and
Generation
|
11
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Natural Gas Pipeline Operations –
Enogex
|
12
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Environmental
Matters
|
21
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Finance and
Construction
|
24
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Employees
|
27
|
Access to Securities and Exchange Commission
Filings
|
27
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27
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38
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39
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41
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Item
4. Submission of Matters to a Vote of
Security
Holders
|
44
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44
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Item
5. Market for Registrant’s Common
Equity, Related Stockholder Matters and Issuer Purchases
|
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of
Equity
Securities
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47
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|
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Item
6. Selected Financial
Data
|
49
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Item
7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations
|
50
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Item
7A. Quantitative and Qualitative Disclosures About Market
Risk
|
91
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|
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Item
8. Financial Statements and
Supplementary
Data
|
94
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|
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Item
9. Changes In and Disagreements with
Accountants on Accounting and Financial Disclosure
|
155
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155
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159
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Item
10. Directors, Executive Officers and Corporate
Governance
|
159
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159
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Item
12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder
|
|
Matters
|
159
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Item
13. Certain Relationships and Related Transactions,
and Director Independence
|
159
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|
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Item
14. Principal Accounting Fees and
Services
|
159
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Item
15. Exhibits, Financial Statement
Schedules
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159
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167
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FORWARD-LOOKING
STATEMENTS
Except
for the historical statements contained herein, the matters discussed in this
Form 10-K, including those matters discussed in “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations,” are
forward-looking statements that are subject to certain risks, uncertainties and
assumptions. Such forward-looking statements are intended to be
identified in this document by the words “anticipate”, “believe”, “estimate”,
“expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and
similar expressions. Actual results may vary
materially. In addition to the specific risk factors discussed in
“Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” herein, factors that could cause
actual results to differ materially from the forward-looking statements include,
but are not limited to:
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
|
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.
|
The
Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
Introduction
OGE
Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, the
“Company”) is an energy and energy services provider offering physical delivery
and related services for both electricity and natural gas primarily in the south
central United States. The Company conducts these activities through
four business segments: (i) electric utility, (ii) natural gas transportation
and storage, (iii) natural gas gathering and processing and (iv) natural gas
marketing. For financial information regarding these segments, see
Note 12 of Notes to Consolidated Financial Statements. The Company
was incorporated in August 1995 in the state of Oklahoma and its principal
executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City,
Oklahoma 73101-0321; telephone (405) 553-3000.
The
electric utility segment generates, transmits, distributes and sells electric
energy in Oklahoma and western Arkansas. Its operations are conducted
through Oklahoma Gas and Electric Company (“OG&E”) and are subject to rate
regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public
Service Commission (“APSC”) and the Federal Energy Regulatory Commission
(“FERC”). OG&E was incorporated in 1902 under the laws of the
Oklahoma Territory. OG&E is the largest electric utility in
Oklahoma and its franchised service territory includes the Fort Smith, Arkansas
area. OG&E sold its retail gas business in 1928 and is no longer
engaged in the gas distribution business.
Enogex
LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas
midstream services. Enogex is engaged in the business of gathering,
processing, transporting and storing natural gas. Most of Enogex’s
natural gas gathering, processing, transportation and storage assets are
strategically located in the Arkoma and Anadarko basins of Oklahoma and the
Texas Panhandle. Enogex’s operations are organized into two business
segments: (i) natural gas transportation and storage and (ii) natural gas
gathering and processing. Prior to January 1, 2008, Enogex owned OGE
Energy Resources, Inc. (“OERI”), whose primary operations are in natural gas
marketing. On January 1, 2008, Enogex distributed the stock of OERI
to OGE Energy. Also, Enogex holds a 50 percent ownership interest in the Atoka
Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned
subsidiary of Enogex Gathering & Processing LLC. Enogex is a
Delaware single-member limited liability company. Effective July 1,
2009, Enogex LLC formed a new entity, Enogex Gathering & Processing LLC, a
wholly-owned subsidiary of Enogex, for purposes of holding the membership
interests of Enogex Gas Gathering LLC, Enogex Products LLC (“Products”) and
Enogex Atoka LLC, which were previously direct wholly-owned subsidiaries of
Enogex LLC.
In July
2008, OGE Energy and Electric Transmission America, a joint venture of
subsidiaries of American Electric Power and MidAmerican Energy Holdings Co.,
formed a transmission joint venture, conducting business as Tallgrass
Transmission L.L.C. (“Tallgrass”), to construct high-capacity transmission line
projects. The Company owns 50 percent of
Tallgrass. Tallgrass is intended to allow the participating companies
to lead development of renewable wind by sharing capital costs associated with
transmission construction. Tallgrass’ initial projects could include
765 kilovolt (“kV”) lines from Woodward 120 miles northwest to Guymon in the
Oklahoma Panhandle and from Woodward 50 miles north to the Kansas
border. A Southwest Power Pool (“SPP”) study estimates cost for the
two projects if constructed as 765 kV lines to be approximately $500 million, of
which OGE Energy’s portion would be approximately $250 million. See
“Regulation and Rates – Recent Regulatory Matters – Tallgrass Joint Venture” for
a further discussion of Tallgrass.
Company
Strategy
The
Company’s vision is to fulfill its critical role in the nation’s electric
utility and natural gas midstream pipeline infrastructure and meet individual
customers’ needs for energy and related services in a safe, reliable and
efficient manner. The Company intends to execute its vision by focusing on its
regulated electric utility business and unregulated midstream natural gas
business. The Company intends to maintain the majority of its assets
in the regulated utility business complemented by its natural gas pipeline
business. The Company’s financial objectives from 2010 through 2012
include a long-term annual earnings growth rate of five to seven percent on a
weather-normalized basis as well as an annual dividend growth rate of two
percent subject to approval by the Company’s Board of Directors. The
target payout ratio for the Company is to pay out as dividends no more than 60
percent of its normalized earnings on an annual basis. The target
payout ratio has been determined after consideration of numerous factors,
including the largely retail composition of the Company’s shareholder base, the
Company’s financial position, the Company’s growth targets, the composition of
the Company’s assets and investment opportunities. The Company
believes it can accomplish these financial objectives by, among other things,
pursuing multiple avenues to build its business, maintaining a diversified asset
position, continuing to develop a wide range
of skills
to succeed with changes in its industries, providing products and services to
customers efficiently, managing risks effectively and maintaining strong
regulatory and legislative relationships.
OG&E
has been focused on increased investment to preserve system reliability and meet
load growth, leverage unique geographic position to develop renewable energy
resources for wind and transmission, replace infrastructure equipment, replace
aging transmission and distribution systems, provide new products and services,
provide energy management solutions to OG&E’s customers through the Smart
Grid program (discussed below) and deploy newer technology that improves
operational, financial and environmental performance. As part of this
plan, OG&E has taken, or has committed to take, the following
actions:
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.
|
OG&E
continues to pursue additional renewable energy and the construction of
associated transmission facilities required to support this renewable
expansion. OG&E also is promoting Demand Side Management programs
to encourage more efficient use of electricity. See “Recent
Regulatory Matters – OG&E Conservation and Energy Efficiency Programs” for a
further discussion. If these initiatives are successful, OG&E believes it
may be able to defer the construction of any incremental fossil fuel generation
capacity until 2020.
Increases
in generation and the building of transmission lines are subject to numerous
regulatory and other approvals, including appropriate regulatory treatment from
the OCC and, in the case of transmission lines, the SPP. Other
projects involve installing new emission-control and monitoring equipment at
existing OG&E power plants to help meet OG&E’s commitment to comply with
current and future environmental requirements. For additional
information regarding the above items and other regulatory matters, see “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Environmental Laws and Regulations” and Note 14 of Notes to
Consolidated Financial Statements.
Enogex
plans to continue to implement improvements to enhance long-term financial
performance of its mid-continent assets through more efficient operations and
effective commercial management of the assets, capturing growth opportunities
through expansion projects, increased utilization of existing assets and
strategic acquisitions. Enogex also plans to continue to add
additional fee-based business to its portfolio as opportunities become
available. In addition, Enogex is seeking to diversify its gathering,
processing and transportation businesses principally by expanding into other
geographic areas that are complementary with the Company’s strategic
capabilities. Enogex expects to accomplish this
diversification
either by
undertaking organic growth projects or through strategic
acquisitions. Over the past several years, Enogex has been able to
take advantage of numerous organic growth projects within its existing footprint
including:
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.
|
In
addition to focusing on growing its earnings and improving cash flow, Enogex
intends to continue to prudently manage its business and execute on organic
growth initiatives. The Company’s business strategy is to continue
maintaining the diversified asset position of OG&E and Enogex so as to
provide competitive energy products and services to customers primarily in the
south central United States. The Company will continue to focus on
those products and services with limited or manageable commodity price exposure.
Also, the Company believes that many of the risk management practices,
commercial skills and market information available from OERI provide value to
all of the Company’s businesses.
ELECTRIC OPERATIONS -
OG&E
The
electric utility segment generates, transmits, distributes and sells electric
energy in Oklahoma and western Arkansas. Its operations are conducted
through OG&E. OG&E furnishes retail electric service in 269
communities and their contiguous rural and suburban areas. At
December 31, 2009, four other communities and two rural electric cooperatives in
Oklahoma and western Arkansas purchased electricity from OG&E for
resale. The service area covers approximately 30,000 square miles in
Oklahoma and western Arkansas, including Oklahoma City, the largest city in
Oklahoma, and Fort Smith, Arkansas, the second largest city in that
state. Of the 269 communities that OG&E serves, 243 are located
in Oklahoma and 26 in Arkansas. OG&E derived approximately 90 percent of its
total electric operating revenues for the year ended December 31, 2009
from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E’s
system control area peak demand during 2009 was approximately 6,418 MWs on July
13, 2009. OG&E’s load responsibility peak demand was
approximately 5,969 MWs on July 13, 2009. As reflected in the table
below and in the operating statistics that follow, there were approximately 25.9
million megawatt-hour (“MWH”) sales to OG&E’s customers (“system sales”) in
2009, 26.8 million MWH system sales in 2008 and 26.4 million MWH system sales in
2007. Variations in system sales for the three years are reflected in
the following table:
|
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.
|
OG&E
is subject to competition in various degrees from government-owned electric
systems, municipally-owned electric systems, rural electric cooperatives and, in
certain respects, from other private utilities, power marketers and
cogenerators. Oklahoma law forbids the granting of an exclusive
franchise to a utility for providing electricity.
Besides competition from other
suppliers or marketers of electricity, OG&E competes with suppliers of other
forms of energy. The degree of competition between suppliers may vary
depending on relative costs and supplies of other forms of
energy.
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
|
|
(A) Sales
to other utilities and power marketers.
OG&E’s
retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in
Arkansas. The issuance of certain securities by OG&E is also
regulated by the OCC and the APSC. OG&E’s wholesale electric
tariffs, transmission activities, short-term borrowing authorization and
accounting practices are subject to the jurisdiction of the FERC. The
Secretary of the DOE has jurisdiction over some of OG&E’s facilities and
operations. For the year ended December 31, 2009, approximately 89
percent of OG&E’s electric revenue was subject to the jurisdiction of the
OCC, eight percent to the APSC and three percent to the FERC.
The OCC
issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of
the Company. The order required that, among other things, (i) the
Company permit the OCC access to the books and records of the Company and its
affiliates relating to transactions with OG&E, (ii) the Company employ
accounting and other procedures and controls to protect against subsidization of
non-utility activities by OG&E’s customers and (iii) the Company refrain
from pledging OG&E assets or income for affiliate
transactions. In addition, the Energy Policy Act of 2005 enacted the
Public Utility Holding Company Act of 2005, which in turn granted to the FERC
access to the books and records of the Company and its affiliates as the FERC
deems relevant to costs incurred by OG&E or necessary or appropriate for the
protection of utility customers with respect to the FERC jurisdictional
rates.
Recent
Regulatory Matters
OG&E 2009 Oklahoma Rate Case
Filing. On February 27, 2009, OG&E filed its rate case
with the OCC requesting a rate increase of approximately $110
million. On July 24, 2009, the OCC issued an order authorizing: (i)
an annual net increase of approximately $48.3 million in OG&E’s rates to its
Oklahoma retail customers, which includes an increase in the residential
customer charge from $6.50/month to $13.00/month, (ii) creation of a new
recovery rider to permit the recovery of up to $20 million of capital
expenditures and operation and maintenance expenses associated with OG&E’s
smart grid project in Norman, Oklahoma, which was implemented in February 2010,
(iii) continued utilization of a return on equity (“ROE”) of 10.75 percent under
various recovery riders previously approved by the OCC and (iv) recovery through
OG&E’s fuel adjustment clause of approximately $4.8 million annually of
certain expenses that historically had been recovered through base
rates. New electric rates were implemented August 3,
2009. OG&E expects the impact of the rate increase on its
customers and service territory to be minimal over the next 12 months as the
rate increase will be more than offset by lower fuel costs attributable to prior
fuel over recoveries and from lower than forecasted fuel costs in
2010.
OG&E Arkansas Rate Case
Filing. In August 2008, OG&E filed with the APSC an
application for an annual rate increase of approximately $26.4 million to
recover, among other things, costs for investments including in the Redbud
Facility and improvements in its system of power lines, substations and related
equipment to ensure that OG&E can reliably meet growing customer demand for
electricity. On May 20, 2009, the APSC approved a general rate
increase of approximately $13.3 million, which excludes approximately $0.3
million in storm costs. The APSC order also allows implementation of
OG&E’s “time-of-use” tariff which allows participating customers to save on
their electricity bills by shifting some of the electricity consumption to times
when demand for electricity is lowest. OG&E implemented the new
electric rates effective June 1, 2009.
OG&E OU Spirit Wind Power
Project. OG&E
signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine
generators and certain related balance of plant engineering, procurement and
construction services associated with OU Spirit. As discussed below,
OU Spirit is part of OG&E’s goal to increase its wind power generation
portfolio in the near future. On July 30, 2009, OG&E filed an
application with the OCC requesting pre-approval to recover from Oklahoma
customers the cost to construct OU Spirit at a cost of approximately $265.8
million. On October 15, 2009, all parties to this case signed a
settlement agreement that would provide pre-approval of OU Spirit and authorize
OG&E to begin recovering the costs of OU Spirit through a rider mechanism as
the 44 turbines were placed into service in November and December 2009 and began
delivering electricity to OG&E’s customers. The rider will be in
effect until OU Spirit is added to OG&E’s regulated rate base as part of
OG&E’s next general rate case, which is expected to be based on a 2010 test
year and completed in 2011, at which time the rider will cease. The
settlement agreement also assigns to OG&E’s customers the proceeds from the
sale of OU Spirit renewable energy credits to the University of
Oklahoma. The settlement agreement permits the recovery of up to $270
million of eligible construction costs, including recovery of the costs of
the conservation project for the lesser prairie chicken as discussed
below. The net impact on the average residential customer’s 2010
electric bill is estimated to be approximately 90 cents per month, decreasing to
80 cents per month in 2011. On November 25, 2009, OG&E received
an order from the OCC approving the settlement agreement in this case, with the
rider being implemented on December 4, 2009. Capital expenditures
associated with this project were approximately $270 million.
In
connection with OU Spirit, in January 2008, OG&E filed with the SPP for a
Large Generator Interconnection Agreement (“LGIA”) for this project. Since
January 2008, the SPP has been studying this requested interconnection
to
determine
the feasibility of the request, the impact of the interconnection on the SPP
transmission system and the facilities needed to accommodate the
interconnection. Given the backlog of interconnection requests at the SPP,
there has been significant delay in completing the study process and in OG&E
receiving a final LGIA. On May 29, 2009, OG&E executed an interim
LGIA, allowing OU Spirit to interconnect to the transmission grid, subject to
certain conditions. In connection with the interim LGIA, OG&E
posted a letter of credit with the SPP of approximately $10.9 million, which was
later reduced to approximately $9.9 million in October 2009 and further reduced
to approximately $9.2 million in February 2010, related to the costs of upgrades
required for OG&E to obtain transmission service from its new OU Spirit wind
farm. The SPP filed the interim LGIA with the FERC on June 29,
2009. On August 27, 2009, the FERC issued an order accepting the
interim LGIA, subject to certain conditions, which enables OU Spirit to
interconnect into the transmission grid until the final LGIA can be put in
place, which is expected by mid-2010.
In
connection with OU Spirit and to support the continued development of Oklahoma’s
wind resources, on April 1, 2009, OG&E announced a $3.75 million project
with the Oklahoma Department of Wildlife Conservation to help provide a habitat
for the lesser prairie chicken, which ranks as one of Oklahoma’s more imperiled
species. Through its efforts, OG&E hopes to help offset the
effect of wind farm development on the lesser prairie chicken and help ensure
that the bird does not reach endangered status, which could significantly limit
the ability to develop Oklahoma’s wind potential.
OG&E Renewable Energy
Filing. OG&E
announced in October 2007 its goal to increase its wind power generation over
the following four years from its then current 170 MWs to 770 MWs and, as part
of this plan, on December 8, 2008, OG&E issued a request for proposal
(“RFP”) to wind developers for construction of up to 300 MWs of new capability,
which OG&E intends to add to its power-generation portfolio by the end of
2010. In June 2009, OG&E announced that it had selected a short
list of bidders for a total of 430 MWs and that it was considering acquiring
more than the approximately 300 MWs of wind energy originally contemplated in
the initial RFP. On September 29, 2009, OG&E announced that, from
its short list, it had reached agreements with two developers who are to build
two new wind farms, totaling 280 MWs, in northwestern Oklahoma. Under the terms
of the agreements, CPV Keenan is to build a 150 MW wind farm in Woodward County
and Edison Mission Energy is to build a 130 MW facility in Dewey County near
Taloga. The agreements are both 20-year power purchase agreements,
under which the developers are to build, own and operate the wind generating
facilities and OG&E will purchase their electric output. On
October 30, 2009, OG&E filed separate applications with the OCC seeking
pre-approval for the recovery of the costs associated with purchasing power from
these projects. On December 9, 2009, all parties to these cases
signed settlement agreements whereby the stipulating parties requested that the
OCC issue orders: (i) finding that the execution of the power purchase
agreements complied with the OCC competitive bidding rules, are prudent and are
in the public’s interest, (ii) approving the power purchase agreements and (iii)
authorizing OG&E to recover the costs of the power purchase agreements
through OG&E’s fuel adjustment clause. On January 5, 2010,
OG&E received an order from the OCC approving the power purchase agreements
and authorizing OG&E to recover the costs of the power purchase agreements
through OG&E’s fuel adjustment clause. The two wind farms are
expected to be in service by the end of 2010. Negotiations with the
third bidder on OG&E’s short list announced in June, for an additional 150
MWs of wind energy from Texas County were terminated in early
October. OG&E will continue to evaluate renewable opportunities
to add to its power-generation portfolio in the future.
OG&E Windspeed Transmission Line
Project. OG&E filed an application on May 19, 2008 with the OCC
requesting pre-approval to recover from Oklahoma customers the cost to construct
the Windspeed transmission line at a construction cost of approximately $211
million, plus approximately $7 million in allowance for funds used during
construction (“AFUDC”), for a total of approximately $218
million. This transmission line is a critical first step to increased
wind development in western Oklahoma. In the application, OG&E
also requested authorization to implement a recovery rider to be effective when
the transmission line is completed and in service, which is expected during
April 2010. Finally, the application requested the OCC to approve new
renewable tariff offerings to OG&E’s Oklahoma customers. A
settlement agreement was signed by all parties in the matter on July 31, 2008.
Under the terms of the settlement agreement, the parties agreed that OG&E
will: (i) receive pre-approval for construction of the Windspeed transmission
line and a conclusion that the construction costs of the transmission line are
prudent, (ii) receive a recovery rider for the revenue requirement of the $218
million in construction costs and AFUDC when the transmission line is completed
and in service until new rates are implemented in an expected 2011 rate case and
(iii) to the extent the construction costs and AFUDC for the transmission line
exceed $218 million, OG&E be permitted to show that such additional costs
are prudent and allowed to be recovered. On September 11, 2008, the
OCC issued an order approving the settlement agreement. At December 31, 2009,
the construction costs and AFUDC incurred were approximately $184.9 million.
Separately, on July 29, 2008, the SPP Board of Directors approved the proposed
transmission line discussed above. On February 2, 2009, OG&E received SPP
approval to begin construction of the transmission line and the associated
Woodward District EHV substation. In 2009, OG&E received a
favorable outcome in five local court cases challenging OG&E’s use of
eminent domain to obtain rights-of-way. The capital expenditures
related to this project are presented in the summary of capital expenditures for
known and committed projects in
“Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Future Capital Requirements.”
SPP Transmission/Substation
Projects. The SPP
is a regional transmission organization (“RTO”) under the jurisdiction of the
FERC, which was created to ensure reliable supplies of power, adequate
transmission infrastructure and competitive wholesale prices of
electricity. The SPP does not build transmission though the SPP’s tariff
contains rules that govern the transmission construction process.
Transmission owners complete the construction and then own, operate and
maintain transmission assets within the SPP region. When the SPP Board of
Directors approves a project, the transmission provider in the area where the
project is needed has the first obligation to build.
There are
several studies currently under review at the SPP including the Extra High
Voltage (“EHV”) study that focuses on year 2026 and beyond to address issues of
regional and interregional importance. The EHV study suggests overlaying
the SPP footprint with a 345 kV, 500kV and 765kV transmission system and
integrating it with neighboring regional entities. In 2009, the SPP Board
of Directors approved a new report that recommended restructuring the SPP’s
regional planning processes to focus on the construction of a robust
transmission system, large enough in both scale and geography, to provide
flexibility to meet the SPP’s future needs. OG&E expects to actively
participate in the ongoing study, development and transmission growth that may
result from the SPP’s plans.
In
2007, the SPP notified OG&E to construct approximately 44 miles of new 345
kV transmission line which will originate at the existing OG&E Sooner 345 kV
substation and proceed generally in a northerly direction to the Oklahoma/Kansas
Stateline (referred to as the Sooner-Rose Hill project). At the
Oklahoma/Kansas Stateline, the line will connect to the companion line being
constructed in Kansas by Westar Energy. The line is estimated to be in service
by June 2012. The capital expenditures related to this project are
presented in the summary of capital expenditures for known and committed
projects in “Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Future Capital Requirements.”
In
January 2009, OG&E received notification from the SPP to begin construction
on approximately 50 miles of new 345 kV transmission line and substation
upgrades at OG&E’s Sunnyside substation, among other projects. In April
2009, Western Farmers Electric Cooperative (“WFEC”) assigned to OG&E the
construction of 50 miles of line designated by the SPP to be built by the WFEC.
The new line will extend from OG&E’s Sunnyside substation near
Ardmore, Oklahoma, approximately 100 miles to the Hugo substation owned by the
WFEC near Hugo, Oklahoma. OG&E began preliminary line routing and
acquisition of rights-of-way in June 2009. When construction is completed,
which is expected in April 2012, the SPP will allocate a portion of the annual
revenue requirement to OG&E customers according to the base-plan funding
mechanism as provided in the SPP tariff for application to such
improvements. The capital expenditures related to this project are
presented in the summary of capital expenditures for known and committed
projects in “Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Future Capital Requirements.”
On April
28, 2009, the SPP approved the Balanced Portfolio 3E
projects. Balanced Portfolio 3E includes four projects to be built by
OG&E and includes: (i) construction of approximately 120 miles of
transmission line from OG&E’s Seminole substation in a northeastern
direction to OG&E’s Muskogee substation at a cost of approximately $131
million for OG&E, which is expected to be in service by December 2014, (ii)
construction of approximately 72 miles of transmission line from OG&E’s
Woodward District EHV substation in a southwestern direction to the
Oklahoma/Texas Stateline to a companion transmission line to be built by
Southwestern Public Service to its Tuco substation at a cost of approximately
$120 million for OG&E, which is expected to be in service by April 2014,
(iii) construction of approximately 38 miles of transmission line from
OG&E’s Sooner substation in an eastern direction to the Grand River Dam
Authority Cleveland substation at an estimated cost of approximately $41 million
for OG&E, which is expected to be in service by December 2012 and (iv)
construction of a new substation near Anadarko which is expected to consist of a
345/138 kV transformer and substation breakers and will be built in OG&E’s
portion of the Cimarron-Lawton East Side 345 kV line at an estimated cost of
approximately $8 million for OG&E, which is expected to be in service by
December 2012. On June 19, 2009, OG&E received a notice to
construct the Balanced Portfolio 3E projects from the SPP. On July
23, 2009, OG&E responded to the SPP that OG&E will construct the
Balanced Portfolio 3E projects discussed above beginning in early
2010. The capital expenditures related to the Balanced Portfolio 3E
projects are presented in the summary of capital expenditures for known and
committed projects in “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Future Capital Requirements.”
OG&E Conservation and Energy
Efficiency Programs. In
June and September 2009, OG&E filed applications with the APSC and the OCC
seeking approval of a comprehensive Demand Program portfolio designed to build
on the success of its earlier programs and further promote energy efficiency and
conservation for each class of OG&E customers. Several programs
are proposed in these applications, ranging from residential weatherization to
commercial lighting. In seeking approval of these new programs,
OG&E also seeks recovery of the program and related costs through a rider
that
would be
added to customers’ electric bills. In Arkansas, OG&E’s program is expected
to cost approximately $2 million over an 18-month period and is expected to
increase the average residential electric bill by less than $1.00 per month. In
Oklahoma, OG&E’s program is expected to cost approximately $45 million over
three years and is expected to increase the average residential electric bill by
less than $1.00 per month in 2010 and by approximately $1.40 per month in 2011
and 2012 depending on the success of the programs. In addition to program cost
recovery, the OCC also granted OG&E recovery of: (i) lost revenues resulting
from the reduced KWH sales between rate cases and (ii) performance-based
incentives of 15 percent of the net savings associated with the programs. A
hearing in the APSC matter was held on October 29, 2009 and OG&E received an
order in this matter on February 3, 2010. A settlement agreement was signed in
the OCC matter by several parties to this case on January 15, 2010 with a
hearing being held on January 21, 2010, where the parties who had not previously
signed the settlement agreement indicated that they did not oppose the
settlement agreement. OG&E received an order in the OCC matter on February
10, 2010.
OG&E Smart Grid Application.
In February 2009, the President signed into law the ARRA. Several
provisions of this law relate to issues of direct interest to the Company
including, in particular, financial incentives to develop smart grid technology,
transmission infrastructure and renewable energy. After review of the
ARRA, OG&E filed a grant request on August 4, 2009 for $130 million
with the DOE to be used for the Smart Grid application in OG&E’s service
territory. On October 27, 2009, OG&E received notification from
the DOE that its grant had been accepted by the DOE for the full requested
amount of $130 million. Receipt of the grant monies is contingent
upon successful negotiations with the DOE on final details of the
award. OG&E expects to file an application with the OCC
requesting pre-approval for system-wide deployment of smart grid technology and
a recovery rider, including a credit for the Smart Grid grant during the first
quarter of 2010. Separately, on November 30, 2009, OG&E requested
a grant with a 50 percent match of up to $5 million for a variety of types of
smart grid training for OG&E’s workforce. Recipients of the grant
are expected to be announced in the first quarter of 2010.
Tallgrass Joint Venture. In
July 2008, Tallgrass was formed to construct high-capacity transmission line
projects. The Company owns 50 percent of Tallgrass. Tallgrass is
intended to allow the participating companies to lead development of renewable
wind by sharing capital costs associated with transmission
construction. The Tallgrass projects are subject to creation by the
SPP of a cost allocation method that would spread the total cost across the SPP
region. OGE Energy is uncertain as to the timing of when the cost
allocation method will be developed and approved. OGE Energy filed an
application with the FERC in October 2008 for cost recovery of these projects
subject to SPP and FERC approval for these projects. On December 2,
2008, the FERC granted Tallgrass’ request for transmission rate incentives for
the initial projects, established a base ROE for initial projects, approved
certain accounting treatments for the initial projects and set the formula rate
and accompanying protocols for hearing and settlement
discussions. Tallgrass’ initial projects could include 765 kV lines
from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from
Woodward 50 miles north to the Kansas border. An SPP study estimates
the cost for the two projects if constructed as 765 kV lines to be approximately
$500 million, of which OGE Energy’s portion would be approximately $250
million. The capital expenditures related to the Tallgrass projects
discussed above are excluded from the summary of capital expenditures for known
and committed projects in “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Future Capital
Requirements.” The SPP continues to review the initial Tallgrass
projects and has not made a final determination whether these projects should be
built. The SPP is reviewing these projects as a portion of the list
of “Priority Projects” and the SPP is expected to make decisions on these
projects as to timing and voltage in the second quarter of 2010. If
the SPP determines that the above 765 kV projects should be 345 kV projects,
these projects are expected to be completed by OG&E. In December
2009, the Tallgrass agreement was amended between the joint venture owners to
expand the joint venture from the two potential 765kV projects discussed above
to also include any potential 765 kV projects in Oklahoma that any subsidiary of
the joint venture partners has the right to construct. The period of the
agreement was established for seven years unless earlier terminated via the
conditions precedent, which expire in December of 2011.
See Note
14 of Notes to Consolidated Financial Statements for further discussion of these
matters, as well as a discussion of additional regulatory matters, including,
among other things, system hardening filing, security enhancements filing, FERC
formula rate filing and review of OG&E’s fuel adjustment
clause.
Regulatory
Assets and Liabilities
OG&E,
as a regulated utility, is subject to accounting principles for certain types of
rate-regulated activities, which provide that certain actual or anticipated
costs that would otherwise be charged to expense can be deferred as regulatory
assets, based on the expected recovery from customers in future
rates. Likewise, certain actual or anticipated credits that would
otherwise reduce expense can be deferred as regulatory liabilities, based on the
expected flowback to customers in future rates. Management’s expected
recovery of deferred costs and flowback of deferred credits generally results
from specific decisions by regulators granting such ratemaking
treatment.
OG&E
records certain actual or anticipated costs and obligations as regulatory assets
or liabilities if it is probable, based on regulatory orders or other available
evidence, that the cost or obligation will be included in amounts allowable for
recovery or refund in future rates.
At
December 31, 2009 and 2008, OG&E had regulatory assets of approximately
$451.4 million and $464.3 million, respectively, and regulatory liabilities of
approximately $363.0 million and $164.4 million, respectively. See
Note 1 of Notes to Consolidated Financial Statements for a further
discussion.
Management continuously
monitors the future recoverability of regulatory assets. When in
management’s judgment future recovery becomes impaired, the amount of the
regulatory asset is adjusted, as appropriate. If the Company were
required to discontinue the application of accounting principles for certain
types of rate-regulated activities for some or all of its operations, it could
result in writing off the related regulatory assets; the financial effects of
which could be significant.
Rate
Structures
Oklahoma
OG&E’s
standard tariff rates include a cost-of-service component (including an
authorized return on capital) plus a fuel adjustment clause mechanism that
allows OG&E to pass through to customers variances (either positive or
negative) in the actual cost of fuel as compared to the fuel component in
OG&E’s most recently approved rate case.
OG&E
offers several alternate customer programs and rate options. The
Guaranteed Flat Bill (“GFB”) option for residential and small general service
accounts allows qualifying customers the opportunity to purchase their
electricity needs at a set price for an entire year. Budget-minded
customers that desire a fixed monthly bill may benefit from the GFB
option. A second tariff rate option provides a “renewable energy”
resource to OG&E’s Oklahoma retail customers. This renewable energy resource
is a wind power purchase program and is available as a voluntary option to all
of OG&E’s Oklahoma retail customers. OG&E’s ownership and
access to wind resources makes the renewable wind power option a possible choice
in meeting the renewable energy needs of our conservation-minded customers and
provides the customers with a means to reduce their exposure to increased prices
for natural gas used by OG&E as boiler fuel. Another program
being offered to OG&E’s commercial and industrial customers is a voluntary
load curtailment program called Load Reduction. This program provides
customers with the opportunity to curtail usage on a voluntary basis when
OG&E’s system conditions merit curtailment action. Customers that
curtail their usage will receive payment for their curtailment
response. This voluntary curtailment program seeks customers that can
curtail on most curtailment event days, but may not be able to curtail every
time that a curtailment event is required.
OG&E
also has two rate classes, Public Schools-Demand and Public Schools Non-Demand,
that will provide OG&E with flexibility to provide targeted programs for
load management to public schools and their unique usage patterns. OG&E also
created service level fuel differentiation that allows customers to pay fuel
costs that better reflect operational energy losses related to a specific
service level. Lastly, OG&E implemented a military base rider
that demonstrates Oklahoma’s continued commitment to our military
partners.
The
previously discussed rate options, coupled with OG&E’s other rate choices,
provide many tariff options for OG&E’s Oklahoma retail
customers. The revenue impacts associated with these options
are not determinable in future years because customers
may choose to remain on existing rate options instead of volunteering
for the alternative rate option choices. Revenue variations may occur
in the future based upon changes in customers’ usage characteristics if they
choose alternative rate options. OG&E’s rate choices, reduction
in cogeneration rates, acquisition of additional generation resources and
overall low costs of production and deliverability are expected to provide
valuable benefits for OG&E’s customers for many years to come.
Arkansas
OG&E’s
standard tariff rates include a cost-of service component (including an
authorized return on capital) plus an energy cost recovery mechanism that allows
OG&E to pass through to customers (either positive or negative) the actual
cost of fuel as compared to the fuel component in OG&E’s most recently
approved rate case. OG&E’s Arkansas rate case order in May 2009
allows implementation of OG&E’s “time-of-use” tariff which allows
participating customers to save on their electricity bills by shifting some of
the electricity consumption to times when demand for electricity is
lowest. OG&E also offers certain qualifying customers a
“day-ahead price” rate option which allows participating customers to adjust
their electricity consumption based on a price signal received from OG&E.
The day-ahead price is based on OG&E’s projected next day hourly operating
costs.
Fuel Supply and Generation
During
2009, approximately 60 percent of the OG&E-generated energy was produced by
coal-fired units, 38 percent by natural gas-fired units and two percent by
wind-powered units. Of OG&E’s 6,641 total MW capability reflected
in the table under Item 2. Properties, approximately 3,850 MWs, or 58.0 percent,
are from natural gas generation, approximately 2,570 MWs, or 38.7 percent, are
from coal generation and approximately 221 MWs, or 3.3 percent, are from wind
generation. Though OG&E has a higher installed capability of generation from
natural gas units, it has been more economical to generate electricity for our
customers using lower priced coal. Over the last five years, the
weighted average cost of fuel used, by type, per million British thermal unit
(“MMBtu”) was as follows:
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
|
|
The
decrease in the weighted average cost of fuel in 2009 as compared to 2008 was
primarily due to decreased natural gas prices partially offset by increased coal
transportation rates in 2009 as discussed in Note 13 of Notes to Consolidated
Financial Statements. The increase in the weighted average cost of
fuel in 2008 as compared to 2007 was primarily due to increased natural gas
prices partially offset by decreased amounts of natural gas being
burned. The increase in the weighted average cost of fuel in 2007 as
compared to 2006 was primarily due to increased natural gas
volumes. The decrease in the weighted average cost of fuel in 2006 as
compared to 2005 was primarily due to decreased natural gas prices partially
offset by increased amounts of natural gas being burned. A portion of
these fuel costs is included in the base rates to customers and differs for each
jurisdiction. The portion of these fuel costs that is not included in the base
rates is recoverable through OG&E’s fuel adjustment clauses that are
approved by the OCC, the APSC and the FERC.
Coal
All of
OG&E’s coal-fired units, with an aggregate capability of approximately 2,570
MWs, are designed to burn low sulfur western sub-bituminous
coal. OG&E purchases coal primarily under contracts expiring in
years 2010, 2011 and 2015. In 2009, OG&E purchased approximately 9.9 million
tons of coal from various Wyoming suppliers. The combination of all
coal has a weighted average sulfur content of 0.27 percent and can be burned in
these units under existing Federal, state and local environmental standards
(maximum of 1.2 lbs. of sulfur dioxide (“SO2”) per MMBtu) without the addition
of SO2 removal systems. Based upon the average sulfur content and EPA
certified emission data, OG&E’s coal units have an approximate emission rate
of 0.528 lbs. of SO2 per MMBtu, well within the limitations of the current
provisions of the Federal Clean Air Act discussed in Note 13 of Notes to
Consolidated Financial Statements.
In August
2009, OG&E issued an RFP for coal supply purchases for periods from January
2011 through December 2015. The RFP process was completed during the fourth
quarter of 2009 and resulted in two new coal contracts expiring in
2015. The coal supply purchases account for approximately 50
percent of OG&E’s projected coal requirements during that timeframe.
Additional coal supplies to fulfill OG&E’s remaining 2011 through 2015 coal
requirements will be acquired through additional RFPs.
See “Item
7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Environmental Laws and Regulations” for a discussion of
environmental matters which may affect OG&E in the future, including its
utilization of coal.
Natural
Gas
In August
2009, OG&E issued an RFP for gas supply purchases for periods from November
2009 through March 2010. The gas supply purchases from January through March
2010 account for approximately 18 percent of OG&E’s projected 2010 natural
gas requirements. The RFP process was completed on September 10,
2009. The contracts resulting from this RFP are tied to various gas
price market indices that will expire in 2010. Additional gas supplies to
fulfill OG&E’s remaining 2010 natural gas requirements will be acquired
through additional RFPs in early to mid-2010, along with monthly and daily
purchases, all of which are expected to be made at market prices.
OG&E
utilizes a natural gas storage facility for storage services that allows
OG&E to maximize the value of its generation assets. Storage
services are provided by Enogex as part of Enogex’s gas transportation and
storage contract with OG&E. At December 31, 2009, OG&E had
approximately 1.9 million MMBtu’s in natural gas storage valued at approximately
$7.3 million.
OG&E’s
current wind power portfolio includes: (i) the 120 MW Centennial wind farm, (ii)
the 101 MW OU Spirit wind farm placed in service in November and December 2009
and (iii) access to up to 50 MWs of electricity generated at a wind farm near
Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy
that expires in 2018.
OG&E announced in October 2007 its
goal to increase its wind power generation over the following four years from
its then current 170 MWs to 770 MWs and, as part of this plan, on December 8,
2008, OG&E issued an RFP to wind developers for construction of up to 300
MWs of new capability which OG&E intends to add to its power-generation
portfolio by the end of
2010. As part of this RFP process, on September 29, 2009, OG&E
announced that it had reached agreements with two developers who are to build
two new wind farms, totaling 280 MWs, in northwestern Oklahoma. Under
the terms of the agreements, CPV Keenan is to build a 150 MW wind farm in
Woodward County and Edison Mission Energy is to build a 130 MW facility in Dewey
County near Taloga. The agreements are both 20-year power purchase
agreements, under which the developers are to build, own and operate the wind
generating facilities and OG&E will purchase their electric
output. On January 5, 2010, OG&E received an order from the OCC
approving the power purchase agreements and authorizing OG&E to recover the
costs of the power purchase agreements through OG&E’s fuel adjustment
clause.
Safety
and Health Regulation
OG&E
is subject to a number of Federal and state laws and regulations, including the
Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state
statutes, whose purpose is to protect the safety and health of workers. In
addition, the OSHA hazard communication standard, the U.S. Environmental
Protection Agency (“EPA”) community right-to-know regulations under Title III of
the Federal Superfund Amendment and Reauthorization Act and comparable state
statutes require that information be maintained concerning hazardous materials
used or produced in OG&E’s operations and that this information be provided
to employees, state and local government authorities and citizens. The Company
believes that it is in material compliance with all applicable laws and
regulations relating to worker safety and health.
NATURAL GAS PIPELINE
OPERATIONS - ENOGEX
Overview
Enogex is
a provider of integrated natural gas midstream services. Enogex is
engaged in the business of gathering, processing, transporting and storing
natural gas. Most of Enogex’s natural gas gathering, processing,
transportation and storage assets are strategically located in the Arkoma and
Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s
operations are organized into two business segments: (i) natural gas
transportation and storage and (ii) natural gas gathering and
processing.
Transportation
and Storage
General
Enogex
LLC owns and operates approximately 2,181 miles of intrastate natural gas
transportation pipelines. Enogex also owns and operates two
underground storage facilities currently being operated at a working gas level
of approximately 24 billion cubic feet (“Bcf”). Enogex provides
fee-based firm and interruptible transportation services on both an intrastate
basis and pursuant to Section 311 of the Natural Gas Policy Act (“NGPA”) on
an interstate basis. Enogex’s obligation to provide firm transportation service
means that it is obligated to transport natural gas nominated by the shipper up
to the maximum daily quantity specified in the contract. In exchange for that
obligation on Enogex’s part, the shipper pays a specified demand or reservation
charge, whether or not it utilizes the capacity. In most intrastate firm
contracts, the shipper also pays a transportation or commodity charge with
respect to quantities actually transported by Enogex. Enogex’s obligation to
provide interruptible transportation service means that it is obligated to
transport natural gas nominated by the shipper only to the extent that it has
available capacity. For this service, the shipper pays no demand or reservation
charge but pays a transportation or commodity charge for quantities actually
shipped. Enogex derives a substantial portion of its transportation revenues
from firm transportation services and leased capacity. To the extent pipeline
capacity is not needed for such firm transportation services and leased
capacity, Enogex offers interruptible interstate transportation services
pursuant to Section 311 of the NGPA as well as interruptible intrastate
transportation services.
Enogex
delivers natural gas to most interstate and intrastate pipelines and end-users
connected to its systems from the Arkoma and Anadarko basins (including recent
growth activity 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). At December 31, 2009, Enogex was connected to 13
third-party natural gas pipelines and had 64 interconnect points. These
interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas
Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America,
Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western
Farmers Electric Cooperative, CenterPoint Energy Gas Transmission Co., El Paso
Natural Gas Pipeline, Quest Pipelines (KPC), Ozark Gas Transmission, L.L.C.,
Gulf Crossings Pipeline Company LLC and Midcontinent Express Pipeline, LLC
(“MEP”). Further, Enogex is connected to 24 end-user customers, including 15
natural gas-fired electric generation facilities in Oklahoma.
Enogex
owns and operates two underground natural gas storage facilities in Oklahoma,
the Wetumka Storage Facility and the Stuart Storage Facility. These storage
facilities are currently being operated at a working gas level of approximately
24 Bcf and have approximately 650 million cubic feet per day (“MMcf/d”) of
maximum withdrawal capability and approximately 650 MMcf/d of injection
capability. Enogex offers both fee-based firm and interruptible storage
services. Storage services offered under Section 311 of the NGPA are
pursuant to terms and conditions specified in Enogex’s Statement of Operating
Conditions (“SOC”) for gas storage and at market-based rates.
Enogex
uses its storage assets to meet its contractual obligations under certain load
following transportation and storage contracts, including its transportation
agreement with OG&E. Enogex also periodically conducts an open season to
solicit commitments for contracted storage capacity and deliverability to third
parties.
Customers
and Contracts
Enogex’s
major transportation customers are OG&E and Public Service Company of
Oklahoma (“PSO”), the second largest electric utility in Oklahoma. Enogex
provides gas transmission delivery services to all of PSO’s natural gas-fired
electric generation facilities in Oklahoma under a firm intrastate
transportation contract. The PSO contract and the OG&E contract provide for
a monthly demand charge plus variable transportation charges including
fuel. The PSO contract expires January 1, 2013, unless
extended. The stated term of the OG&E contract expired
April 30, 2009, but the contract remains in effect from year to year
thereafter unless either party provides written notice of termination to the
other party at least 180 days prior to the commencement of the next succeeding
annual period. Because neither party provided notice of termination
180 days prior to May 1, 2010, the contract will remain in effect at least
through April 30, 2011. As part of the no-notice load following
contract with OG&E, Enogex provides natural gas storage services for
OG&E. Enogex has been providing natural gas storage services to OG&E
since August 2002 when it acquired the Stuart Storage Facility. Demand for
natural gas on Enogex’s system is usually greater during the summer, primarily
due to demand by gas-fired electric generation facilities to serve residential
and commercial electricity requirements. In 2009, 2008 and 2007,
revenues from Enogex’s firm intrastate transportation and storage contracts were
approximately $116.8 million, $104.4 million and $103.9 million,
respectively, of which approximately $47.5 million, $47.5 million and
$47.4 million, respectively, was attributed to OG&E and approximately
$15.3 million, $15.3 million and $13.3 million, respectively, was
attributed to PSO. Revenues from Enogex’s firm intrastate
transportation and storage contracts represented approximately 32 percent of
Enogex’s consolidated gross margin on revenues (“gross margin”) in 2009, 27
percent in 2008 and 29 percent in 2007.
Competition
Enogex’s
transportation and storage assets compete with numerous interstate and
intrastate pipelines, including several of the interconnected pipelines
discussed above, and storage facilities in providing transportation and storage
services for natural gas. The principal elements of competition are rates, terms
of services, flexibility and reliability of service. Natural gas-fired electric
generation facilities contribute their highest value when they have the
capability to provide load following service to the customer (i.e., the ability of the
generation facility to regulate generation to respond to and meet the
instantaneous changes in customer demand for electricity). While the physical
characteristics of natural gas-fired electric generation facilities are known to
provide quick start-up, on-line functionality and the ability to efficiently
provide varying levels of electric generation relative to other forms of
generation, a key part of their effectiveness is contingent upon having access
to an integrated pipeline and storage system that can respond quickly to meet
their corresponding fluctuating fuel needs. We believe that Enogex is well
positioned to compete for the needs of these generators due to the ability of
its transportation and storage assets to provide no-notice load following
service.
Natural
gas competes with other forms of energy available to Enogex’s customers and
end-users, including electricity, coal and fuel oils. The primary competitive
factor is price. Changes in the availability or price of natural gas or other
forms of energy as well as weather and other factors affect the demand for
natural gas on Enogex’s system.
Regulation
The
transportation rates charged by Enogex for transporting natural gas in
interstate commerce are subject to the jurisdiction of the FERC under
Section 311 of the NGPA. Rates to provide such service must be “fair and
equitable” under the NGPA and are subject to review and approval by the FERC at
least once every three years. The rate review may, but will not necessarily,
involve an administrative-type hearing before a FERC Staff panel and an
administrative appellate review. In the past, Enogex has successfully settled,
rather than litigated, its Section 311 rate cases. Enogex currently
has two zones under its Section 311 rate structure – an East Zone and a
West Zone. Enogex historically offered only interruptible Section 311
service in both zones. As of April 1, 2009, Enogex also began to
offer firm Section 311 service in the East Zone.
For Section 311 service, Enogex may
charge up to its maximum established zonal East and West interruptible
transportation rates for interruptible transportation in one zone or cumulative
maximum rates for transportation in both zones. Enogex may charge up to its
maximum established firm rate for firm Section 311 transportation in its East
Zone. Finally, Enogex may charge the applicable fixed zonal fuel
percentage(s) for the fuel used in transporting natural gas under Section 311 on
the Enogex system. The fuel percentages are the same for firm and interruptible
Section 311 services.
Enogex
FERC Section 311 2007 Rate Case
On
October 1, 2007, Enogex made its required triennial rate filing at the FERC
to update its Section 311 maximum interruptible transportation rates for
Section 311 service in the East Zone and West Zone. Enogex’s filing requested an
increase in the maximum zonal rates and proposed to place such rates into effect
on January 1, 2008. A number of parties intervened and some also filed
protests. Settlement discussions have continued between the parties.
With respect to the 2007 Section 311 rate case, Enogex did not place the
increased rates set forth in its October 2007 rate filing into effect but rather
continued to provide interruptible Section 311 service under the maximum Section
311 rates for both zones approved by the FERC in the previous rate
case. Neither a final settlement nor an order from the FERC has been
entered for the 2007 triennial filing. With the filing of Enogex’s
2009 rate case discussed below, the rate period for the 2007 rate case became a
limited locked-in period from January 2008 through May 2009.
On
November 13, 2007, one of the protesting intervenors in the 2007 rate case filed
to consolidate the 2007 rate case with a separate Enogex application pending
before the FERC allowing Enogex to lease firm capacity to MEP and with separate
applications filed by MEP with the FERC for a certificate to construct and
operate the new MEP pipeline and to lease firm capacity from
Enogex. Enogex and MEP separately opposed this intervenor’s protests
and assertions in its initial and subsequent pleadings. On July 25,
2008, the FERC issued an order approving the MEP project including the approval
of a limited jurisdiction certificate authorizing the Enogex lease agreement
with MEP denying the request for consolidation and rejecting all claims raised
by protestors regarding the lease agreement. Accordingly, Enogex
proceeded with the construction of facilities necessary to implement this
service. On August 25, 2008, the same protestor sought rehearing
which the FERC denied. Enogex commenced service to MEP under the
lease agreement on June 1, 2009. On July 16, 2009, the protestor
filed, with the United States Court of Appeals for the District of Columbia
Circuit, a petition for review of the FERC’s orders approving the MEP
construction and the MEP lease of capacity from Enogex requesting that such
orders be modified or set aside on the grounds that they are arbitrary,
capricious and contrary to law. The petitioner, the FERC and intervening
parties, including Enogex, have been given an opportunity to brief the
issues. Enogex expects to participate in the filing of a joint intervenors’
brief in support of the FERC’s order in this matter, which final briefing is
scheduled to be completed in the third quarter of 2010.
Enogex
FERC Section 311 2009 Rate Case
On March
27, 2009, Enogex filed a petition for rate approval with the FERC to set the
maximum rates for a new firm East Zone Section 311 transportation service and to
revise the rates for its existing East and West Zone interruptible Section 311
transportation service. In anticipation of offering this new service,
Enogex also filed with the FERC, as required by the FERC’s regulations, a
revised SOC Applicable to Transportation Services to describe the terms,
conditions and operating arrangements for the new service. Enogex made the SOC
filing on February 27, 2009.
Enogex began offering firm East Zone
Section 311 transportation service on April 1, 2009. The revised East and West
Zone zonal rates for the Section 311 interruptible transportation service became
effective June 1, 2009. The rates for the firm East Zone Section 311
transportation service and the increase in the rates for East and West Zone and
interruptible Section 311 service are being collected, subject to refund,
pending the FERC approval of the proposed rates. A number of parties intervened
in both the rate case and the SOC filing and some additionally filed protests.
Enogex filed answers to the interventions and protests in both matters. The FERC
Staff served data requests on Enogex seeking additional information regarding
various aspects of the filing and Enogex has submitted responses. On
August 19, 2009, the FERC issued an order extending the time for action until it
can make a determination whether Enogex’s rates are fair and equitable or until
the
FERC
determines that formal proceedings are necessary. The August 19, 2009
order also directed the FERC Staff to report to the FERC by December 29, 2009 on
the status of settlement negotiations. On January 4, 2010, the FERC
Staff submitted its initial settlement offer (“Offer”) proposing various
adjustments to Enogex’s filed cost of service. Comments in response
to the Offer were due on or before January 15, 2010. On January 14,
2010, Enogex asked the FERC Staff some clarifying questions regarding the
Offer. Only Enogex and one intervenor filed comments on January 15,
2010, and each indicated that they were awaiting the FERC Staff’s responses to
the questions raised by Enogex before submitting substantive comments. The FERC
Staff responded to the questions on January 20, 2010. Enogex
anticipates that settlement discussions will continue.
Enogex
2010 Fuel Filing
Pursuant
to its SOC, Enogex makes an annual fuel filing at the FERC to establish the
zonal fuel percentages for each calendar year. The tracker mechanism
set out in the SOC establishes prospectively the zonal fixed fuel factors
(expressed as a percentage of natural gas shipped in the zone) for the upcoming
calendar year. The collected fuel is later trued-up to actual usage
and based on the value of the fuel at the time of usage.
On
November 23, 2009, Enogex made its annual filing to establish fixed fuel
percentages for its East Zone and West Zone for calendar year 2010
(“2010 Fuel Year”). On December 9, 2009, the FERC issued a notice
establishing December 18, 2009 as the due date for any interventions and
protests. Several parties filed interventions. No protests were
filed, but two intervenors reserved the right to do so, contingent upon the
outcome of additional discussions with Enogex. On December 30, 2009, the
FERC issued a letter order directing Enogex to submit certain additional
information by January 13, 2010. Enogex submitted the information
requested by the FERC and is continuing to discuss the filing with the
intervenors.
The FERC
regulates Enogex’s Section 311 transportation and storage services but does
not regulate Enogex’s gathering services or intrastate transportation
services. A recent FERC order, Order 720A, provides that
companies, such as Enogex, will be required, as of June 30,
2010 to post scheduled volume and design capacity information on a
daily basis for eligible receipt and delivery points
on applicable gathering and intrastate transportation facilities that
meet the requirements established in the order. While
the jurisdictional status of Enogex’s gathering and intrastate
transportation services remains unchanged under this new regulation, the
requirement of the FERC order to post this information subjects
Enogex to the FERC’s review of the requirements of this order. In addition, the OCC,
the APSC and the FERC (all of which approve various electric rates of OG&E)
have the authority to examine the appropriateness of any transportation charges
or other fees paid by OG&E to Enogex which OG&E seeks to recover from
its ratepayers in its cost-of-service for electric service.
Certain
of Enogex’s pipeline operations are subject to various state and Federal safety
and environmental and pipeline transportation laws. For example, the U.S.
Department of Transportation (“DOT”) has adopted regulations requiring pipeline
operators to develop integrity management programs for its applicable
pipelines. During 2009, Enogex incurred approximately $10.8 million
of capital expenditures and operating costs for pipeline integrity
management. Enogex currently estimates that it will incur capital
expenditures and operating costs of approximately $34.2 million between 2010 and
2014 in connection with pipeline integrity management. The estimated capital
expenditures and operating costs include Enogex’s estimates for the assessment,
remediation and prevention or other mitigation that may be determined to be
necessary. At this time, Enogex cannot predict the ultimate costs of its
integrity management program and compliance with this regulation because those
costs will depend on the number and extent of any repairs found to be
necessary. Enogex will continue to assess, remediate and maintain the
integrity of its pipelines. The results of these activities could cause Enogex
to incur significant and unanticipated capital and operating expenditures for
repairs or upgrades deemed necessary to ensure the continued safe and reliable
operations of its pipelines.
Recent
System Expansions
Over the
past several years, Enogex has initiated multiple organic growth projects to
increase capacity across its system.
In
December 2006, Enogex entered into a firm capacity lease agreement with MEP
for a primary term of 10 years (subject to possible extension) that gives
MEP and its shippers access to capacity on Enogex’s system. The
quantity of capacity subject to the MEP lease agreement is currently 272 MMcf/d,
with the quantity ultimately to be leased subject to being increased by mutual
agreement pursuant to the lease agreement. In addition to MEP’s lease
of Enogex’s capacity, the MEP project included construction by MEP of a new
pipeline originating near Bennington, Oklahoma and terminating in Butler,
Alabama. In support of the MEP lease agreement, Enogex constructed
approximately 43 miles of 24-inch steel pipe in Woods and Major counties in
Oklahoma, and added 24,000 horsepower of electric-driven compression in
Bennington,
Oklahoma. Enogex’s capital
expenditures allocated to its support of the MEP lease agreement were
approximately $99 million. Enogex commenced service to MEP under the
lease agreement on June 1, 2009.
In order
to accommodate additional deliveries to Bennington, Oklahoma, Enogex is planning
to add an incremental 13,800 horsepower of gas turbine compression at its
Bennington compressor station, as well as other system upgrades. This
project is expected to be in service in May 2010. The capital
expenditures associated with these projects are expected to be approximately $24
million.
In 2009,
Enogex began construction of an approximately 36-mile, 16-inch steel intrastate
transportation pipeline and 3,750 horsepower of electric compression. This
transmission pipeline, which is scheduled to be completed by October 2010, will
provide gas delivery to a natural-gas fired electric generation facility being
constructed by Associated Electric Cooperative, Inc. (“AECI”) near Pryor,
Oklahoma. Up to approximately $64 million of Enogex’s construction
costs are subject to reimbursement in full by AECI as the project progresses.
Enogex does not anticipate that the amount of construction costs will exceed $64
million.
Gathering
and Processing
General
Enogex
provides well connect, gathering, measurement, treating, dehydration,
compression and processing services for various types of producing wells owned
by various sized producers who are active in the areas in which Enogex
operates. Most
natural gas produced at the wellhead contains natural gas liquids (“NGLs”).
Natural gas produced in association with crude oil typically contains higher
concentrations of NGLs than natural gas produced from gas wells. This
high-content, or “rich,” natural gas is generally not acceptable for
transportation in the nation’s transmission pipeline system or for commercial
use. The streams of
processable natural gas gathered from wells and other sources are gathered into
Enogex’s gas gathering systems and are delivered to processing plants for the
extraction of NGLs, leaving residual dry gas that meets transmission pipeline
and commercial quality specifications. Enogex is active in the
extraction and marketing of NGLs from natural gas. The liquids extracted include
condensate liquids, marketable ethane, propane, butanes and natural gasoline
mix. The residue gas remaining after the liquid products have been extracted
consists primarily of ethane and methane.
Enogex’s
gathering system includes approximately 5,846 miles of natural gas gathering
pipelines with approximately 1.25 trillion British thermal units per day of
average daily gathered volumes during 2009. Enogex owns and operates
eight natural gas processing plants with a total inlet capacity of approximately
943 MMcf/d, has a 50 percent interest in and operates the Atoka natural gas
processing plant with an inlet capacity of approximately 20 MMcf/d and has
contracted to have access to up to 50 MMcf/d
in two third-party plants, all in Oklahoma. Where the quality of natural gas
received dictates the removal of NGLs, such gas is aggregated through the
gathering system to the inlet of one or more processing plants operated or
utilized by Enogex.
The resulting processed stream of natural gas is then delivered from the
tailgate of each plant into Enogex’s intrastate natural gas transportation
system. For the year ended December 31, 2009, Enogex extracted and sold
approximately 493 million gallons of NGLs.
Enogex’s
gathering and processing business has approximately 332,000 horsepower of owned
compression. Enogex also has its own compression overhaul center and
specialized compression workforce.
Enogex
gathers and processes natural gas pursuant to a variety of arrangements
generally categorized as “fee-based”, “percent-of-proceeds” and
“percent-of-liquids” and “keep-whole”
arrangements. Percent-of-proceeds, percent-of-liquids and keep-whole
arrangements involve commodity price risk to Enogex because Enogex’s margin is
based in part on natural gas and NGLs prices. Enogex seeks to mitigate its
exposure to fluctuations in commodity prices in several ways, including managing
its contract portfolio. In managing its contract portfolio, Enogex classifies
its gathering and processing contracts according to the nature of commodity risk
implicit in the settlement structure of those contracts.
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,
|
processes
the gas and sells the processed gas and/or NGLs at prices based on published
index prices. These arrangements provide upside in high commodity price
environments, but result in lower margins in low commodity price environments.
The price paid to producers is based on an agreed percentage of the proceeds of
the sale of processed natural gas, NGLs or both or the expected proceeds based
on an index price. We refer to contracts in which Enogex shares in specified
percentages of the proceeds from the sale of natural gas and NGLs as
percent-of-proceeds arrangements and in which Enogex receives proceeds from the
sale of NGLs or the NGLs themselves as compensation for its processing services
as percent-of-liquids arrangements. Under percent-of-proceeds arrangements,
Enogex’s margin correlates directly with the prices of natural gas and NGLs.
Under percent-of-liquids arrangements, Enogex’s margin correlates directly with
the prices of NGLs. At December 31, 2009, these arrangements accounted for
approximately 45 percent of Enogex’s natural gas processed volumes.
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.
|
Enogex’s gathering and processing
contracts typically contain terms and conditions that require a “default
processing fee” in the event the gathered gas exceeds downstream interconnect
specifications. Natural gas that is greater than 1,080 Btu per cubic foot coming
out of wells must typically be processed before it can enter an interstate
pipeline. The default processing fee stipulates a fee to be paid to the
processor if the market for NGLs is lower than the gas equivalent Btu value of
the natural gas that is removed from the stream. The default processing fee
helps to minimize the risk of processing gas that is greater than 1,080 Btu per
cubic foot when the price of the NGLs to be extracted and sold is less than the
Btu value of the natural gas that Enogex otherwise would be required to
replace.
Approximately
17 percent of the commercial grade propane produced at Enogex’s processing
plants is sold on the local market. The balance of propane and the other NGLs
produced by Enogex is delivered into pipeline facilities of a third party and
transported to Conway, Kansas or Mont Belvieu, Texas, where they are sold under
contract or on the spot market. Ethane, which may be optionally produced at all
of Enogex’s plants except the Roger Mills and Calumet plants, is also sold under
contract or on the spot market.
Enogex’s
large diameter, rich gas gathering pipelines in western Oklahoma are configured
such that natural gas from the Wheeler County area in the Texas Panhandle can
flow to the Cox City, Thomas or Calumet gas processing plants. These
large-diameter “super-header” gathering systems of Enogex provide gas routing
flexibility for Enogex to optimize the economics of its gas processing and to
improve system utilization and reliability.
As Enogex
experiences increased growth in regions such as the Woodford Shale play, Enogex
will evaluate the need to expand its processing plants in order to meet the
growing needs of its producer customers.
Customers
and Contracts
The
natural gas remaining after processing is primarily taken in kind by the
producer customers into Enogex’s transportation pipelines for redelivery either:
(i) to on-system customers such as the electric generation facilities of
OG&E, PSO, other independent power producers and other end-users or
(ii) into downstream interstate pipelines. Enogex’s NGLs are typically sold
to NGLs marketers and end-users, its condensate liquid production is typically
sold to marketers and refineries and its propane is typically sold in the local
market to wholesale distributors. Enogex’s key natural gas producer customers
include Chesapeake Energy Marketing Inc., Devon Gas Services, L.P., Apache
Corporation, BP America Production Company and Samson Resources
Company. During 2009, these five customers accounted for
approximately 18.6 percent, 13.2 percent, 12.7 percent, 4.0 percent and 3.9
percent, respectively, of Enogex’s gathering and processing volumes. During
2009, Enogex’s top 10 natural gas producer customers accounted for approximately
66.6 percent of Enogex’s gathering and processing volumes.
Competition
Competition
for natural gas supply is primarily based on efficiency and reliability of
operations, customer service, proximity to existing assets, access to markets
and pricing. Competition to gather and process non-dedicated gas is based on
providing the producer with the highest total value, which is primarily a
function of gathering rate, processing value, system reliability, fuel rate,
system run time, construction cycle time and prices at the wellhead. Enogex
believes it will be able to continue to compete effectively. Enogex competes
with gatherers and processors of all types and sizes, including those affiliated
with various producers, other major pipeline companies and various independent
midstream entities. Enogex’s primary competitors are master limited partnerships
who are active in its region, including Atlas Pipeline Partners, L.P., Crosstex
Energy LP, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P., Hiland
Partners, MarkWest Energy Partners, L.P. and Oneok Partners, L.P. In processing
and marketing NGLs, Enogex competes against virtually all other gas processors
extracting and selling NGLs in its market area.
Regulation
State
regulation of natural gas gathering facilities generally includes various
safety, environmental and nondiscriminatory rate and open access requirements
and complaint-based rate regulation. Enogex may be subject to state common
carrier, ratable take and common purchaser statutes. The common carrier and
ratable take statutes generally require gatherers to carry, transport and
deliver, without undue discrimination, natural gas production that may be
tendered to the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers that purchase gas to purchase without undue
discrimination as to source of supply or producer. These statutes may have the
effect of restricting Enogex’s right to decide with whom it contracts to
purchase natural gas or, as an owner of gathering facilities, to decide with
whom it contracts to purchase or gather natural gas.
Oklahoma
and Texas have each adopted a form of complaint-based regulation of gathering
operations that generally allows natural gas producers and shippers to file
complaints with state regulators in an effort to resolve grievances relating to
natural gas gathering open access and rate discrimination. Texas has
also adopted a complaint based regulation (H.B. 1920), known as the Lost and
Unaccounted for Gas (“LUG”) Bill. The LUG Bill expands the types of information
that can be requested and gives the Texas Railroad Commission the authority to
make determinations and issue orders for purposes of preventing waste in
specific situations. To date, neither the gathering nor LUG regulations have had
a significant impact on Enogex’s operations in Oklahoma or
Texas. However, Enogex cannot predict what effect, if any, either of
these regulations might have on its gathering operations in Oklahoma or Texas in
the future.
Enogex’s
gathering operations could be adversely affected should they be subject in the
future to the application of state or Federal regulation of rates and services.
Enogex’s gathering operations could also be subject to additional safety and
operational regulations relating to the design, construction, testing,
operation, replacement and maintenance of gathering facilities. Additional rules
and legislation pertaining to these matters are considered or adopted from time
to time. Enogex cannot predict what effect, if any, such changes might have on
its operations, but the industry could be required to incur additional capital
expenditures and increased costs depending on future legislative and regulatory
changes.
Recent
System Expansions
Over the
past several years, Enogex has initiated multiple organic growth projects.
Currently, in Enogex’s gathering and processing business, organic growth capital
expenditures are focused on expansions on the east side of Enogex’s gathering
system, primarily in the Woodford Shale play in southeastern Oklahoma and 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.
Southeastern
Oklahoma / East Side Expansions
Enogex is
expanding in the Woodford Shale play and has several projects either completed
or scheduled for completion in 2009 and 2010. For example, in
December 2006, Enogex entered into a joint venture arrangement with Pablo
Gathering, LLC, a subsidiary of Pablo Energy II, LLC, a Texas-based exploration
and production company, which resulted in the formation of
Atoka. Atoka constructed, owns and/or operates a gathering system and
processing plant and related facilities relating to production in certain areas
in southeastern Oklahoma. The gathering system and processing plant were placed
in service during the third quarter of 2007. Enogex owns a 50 percent membership
interest in Atoka and acts as the managing member and operator of the facilities
owned by the joint venture. The joint venture plans to expand its
gathering pipeline infrastructure in order to accommodate additional production
in the area. The capital expenditures associated with the pipeline
expansion of Atoka are expected to be approximately $7 million.
In
February 2008, Enogex completed construction of a 20-mile pipeline project that
connected Enogex’s Hughes, Coal and Pittsburgh County gathering system with the
30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex
mainline pipeline to Wilburton, Oklahoma. The gathering project created
additional gathering capacity of 75 MMcf/d for customers desiring low-pressure
services. The pipeline is complemented by approximately 16,000 horsepower of new
gathering compression which was completed in the third quarter of 2008. Also, in June 2009, Enogex
added approximately 16 miles of 20-inch steel pipe to its system with throughput
capacity of approximately 300 MMcf/d. The capital expenditures
associated with these projects were approximately $68 million.
Enogex
plans to construct a new compressor station in Coal County, Oklahoma, as well as
approximately 10 miles of gathering pipe and related treating
facilities. The station would be designed to accommodate up to 6,700
horsepower of low pressure compression and would be supported by approximately
five miles of 20-inch steel pipe and five miles of 12-inch steel
pipe. The new compressor station would also include the lease or
possible purchase of associated gas treating facilities for the incremental gas
in this area. The initial 2,700 horsepower at the compressor station,
and the gathering pipe, are expected to be completed in February 2010, with an
incremental 2,700 horsepower expected to be in service by April
2010. The capital expenditures for this construction are expected to
be between approximately $18 million and $25 million depending on whether Enogex
leases or purchases the equipment.
Texas
Panhandle / West Side Expansions
In
August 2006, Enogex completed a project to expand its gathering pipeline
capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas
area of the Texas Panhandle that has allowed Enogex to benefit from growth
opportunities in that marketplace. Since the pipeline was put in
service, Enogex has completed the construction of five new gas gathering
compressor stations totaling approximately 26,500 horsepower of compression, and
several miles of gathering pipe, including a new 16-inch line that extends the
original pipeline project an additional 20 miles to the west. In
August 2009, Enogex added another 8,000 horsepower of low pressure compression
in Wheeler County, Texas. The capital expenditures associated with the
additional horsepower of low pressure compression were approximately $18
million.
In order
to accommodate the increased drilling activity in Canadian County, Oklahoma,
Enogex completed construction of approximately six miles of 12-inch steel pipe
and another 2,800 horsepower of compression capacity to its Grandview gathering
project in 2009. The capital expenditures associated with the
additional pipe and compression capacity were approximately $8
million.
Enogex
completed construction of a new 120 MMcf/d cryogenic plant equipped with
electric compression near Clinton, Oklahoma. This plant was placed in
service in late October 2009 and is processing new gas developments in the
area. In support of this plant, Enogex has installed approximately 15
miles of gathering pipe, 2.5 miles of transmission pipe and 10,000 horsepower of
inlet compression, as well as other system upgrades. The capital
expenditures associated with these projects were approximately $77
million.
As
additional support for the strong production needs surrounding Enogex’s new
Clinton plant, Enogex plans to build an additional six miles of 16-inch high
pressure gathering pipe and construct a new compressor station designed to
handle 6,700 horsepower of single-stage compression. The initial
4,000 horsepower at the compressor station, and the high pressure gathering
pipe, are expected to be in service in August 2010. The capital
expenditures for this initial stage of the construction are expected to be
approximately $14 million.
Enogex is planning to further expand its gathering
infrastructure in 2010 in the Wheeler County, Texas area with the
construction of approximately nine miles of 10-inch steel pipe and seven
miles of 16-inch steel pipe, as well as the addition of approximately 2,700
horsepower of compression. The gathering pipelines are expected
to be in service in May 2010, while the compression is expected to be
operational by July 2010. The capital expenditures associated with
this project are expected to be approximately $12 million.
Enogex is
planning construction of approximately 26 miles of 16-inch steel pipe and five
miles of 8-inch steel pipe located in Washita and Custer counties in
Oklahoma. This project will provide additional high pressure
gathering capacity to active producers in this growth area. This project is
expected to be in service in September 2010. The capital expenditures
associated with this project are expected to be approximately $19
million.
Enogex
Additional Processing Capacity
In the
fourth quarter of 2009, Enogex began taking delivery of components of a
cryogenic processing plant which, when installed, will be expected to add
another 120 MMcf/d of processing capacity to Enogex’s system. The
capital
expenditures
associated with the purchase of the new processing cryogenic plant are expected
to be approximately $16 million and exclude any expenditures for installation
and ancillary equipment.
Safety
and Health Regulation
Certain
of Enogex’s facilities are subject to Title 49 CFR Transportation Parts 191,
192, 195 and 199, including the Pipeline Safety Improvement Act of 2002 (“PSIA”)
and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006
(“PIPES”). The Pipeline Hazardous Materials Safety Administration (“PHMSA”)
regulates safety requirements in the design, construction, operation and
maintenance of applicable natural gas and hazardous liquid pipeline facilities.
Both the PSIA and the PIPES require mandatory inspections and enforcement for
all U.S. hazardous liquid and natural gas transportation pipelines, including
some gathering lines in high population areas. The DOT has developed regulations
implementing the PSIA that require pipeline operators to implement integrity
management programs, including more frequent inspections and other safety
protections in high-consequence areas where threats pose the greatest risk to
people and their property.
States
may be preempted by Federal law from solely regulating pipeline safety but may
assume responsibility for enforcing Federal intrastate pipeline regulations and
inspection of intrastate pipelines. In the state of Oklahoma, the OCC’s
Transportation Division, acting through the Pipeline Safety Department,
administers the OCC’s intrastate regulatory program to assure the safe
transportation of natural gas, petroleum and other hazardous materials by
pipeline. The OCC develops regulations and other approaches to assure safety in
design, construction, testing, operation, maintenance and emergency response to
pipeline facilities. The OCC derives its authority over intrastate pipeline
operations through state statutes and certification agreements with the DOT. A
similar regime for safety regulation is in place in Texas and administered by
the Texas Railroad Commission. Enogex’s natural gas pipelines have
inspection and audit programs designed to maintain compliance with pipeline
safety and pollution control requirements.
In
addition, Enogex is subject to a number of Federal and state laws and
regulations, including OSHA and comparable state statutes, whose purpose is to
protect the safety and health of workers, both generally and within the pipeline
industry. In addition, the OSHA hazard communication standard, the EPA community
right-to-know regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act and comparable state statutes require that information be
maintained concerning hazardous materials used or produced in Enogex’s
operations and that this information be provided to employees, state and local
government authorities and citizens. Enogex is also subject to OSHA Process
Safety Management regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive, flammable or explosive
chemicals. These regulations apply to any process which involves a chemical at
or above the specified thresholds or any process which involves flammable liquid
or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at
various locations. Enogex has an internal program of inspection designed to
monitor and enforce compliance with worker safety and health requirements.
Enogex believes that it is in material compliance with all applicable laws and
regulations relating to worker safety and health.
MARKETING
- OERI
General
OERI
focuses on serving customers along the natural gas value chain, from producers
to end-users, by purchasing natural gas from suppliers and reselling to
pipelines, local distribution companies and end-users, including the electric
generation sector. The geographic scope of marketing efforts has been
focused largely in the mid-continent area of the United States. These
markets are natural extensions of OERI’s business on the Enogex system.
OERI contracts for pipeline capacity with Enogex and other pipelines to access
multiple interconnections with the interstate pipeline system network that moves
natural gas from the production basins primarily in the south central United
States to the major consumption areas in Chicago, New York and other north
central and mid-Atlantic regions of the United States.
OERI
primarily participates in both intermediate-term markets (less than three years)
and short-term “spot” markets for natural gas. Although OERI
continues to increase its focus on intermediate-term sales, short-term sales of
natural gas are expected to continue to play a critical role in the overall
strategy because they provide an important source of market intelligence as well
as an important portfolio balancing function. OERI’s average daily
sales volumes decreased from approximately 0.6 Bcf in 2008 to approximately 0.4
Bcf in 2009. This reflects selective deal execution to assure adequate
margin in light of credit and other risks in the current commodity price and
credit environment. OERI’s risk management skills afford its
customers the opportunity to tailor the risk profile and composition of their
natural gas portfolio. The Company follows a policy of hedging price risk on gas
purchases or sales contracts entered into by OERI by buying and selling natural
gas futures contracts on the New York Mercantile Exchange futures exchange and
other derivatives in the
over-the-counter market, subject to
daily and monthly trading stop loss limits of $2.5 million and daily
value-at-risk limits of $1.5 million in accordance with corporate
policies.
On
January 1, 2008, Enogex distributed the stock of OERI to OGE
Energy. Enogex has historically utilized, and expects to continue to
utilize, OERI for natural gas marketing, hedging, risk management and other
related activities. For the years ended December 31, 2009, 2008 and 2007, OERI
recorded revenues from Enogex of approximately $45.4 million, $41.9 million and
$95.2 million, respectively, for the sale, at market rates, of natural gas. For
the years ended December 31, 2009, 2008 and 2007, Enogex recorded revenues from
OERI of approximately $165.5 million, $307.2 million, and $304.3 million,
respectively, for the sale, at market rates, of natural gas. Enogex has paid,
and expects to continue to pay, certain fees to OERI for providing natural gas
marketing, hedging, risk management and other related services. OERI
pays Enogex a fee for certain back office functions and administrative
services.
Competition
OERI
competes with major integrated oil companies, commercial banks, national and
local natural gas marketers, distribution companies and marketing affiliates of
interstate and intrastate pipelines in marketing natural
gas. Competition for both natural gas supplies and natural gas sales
is based primarily on reputation, accuracy, flexibility, products offered,
credit support, the availability to transport gas to high-demand markets and the
ability to obtain a satisfactory price for the natural gas.
For the
year ended December 31, 2009, approximately 61.8 percent of OERI’s service
volumes were with electric utilities, local gas distribution companies,
pipelines and producers, of which approximately 36.8 percent was with affiliates
of OERI. The remaining 38.2 percent of service volumes were to
marketers, municipals, cooperatives and industrials. At December 31,
2009, approximately 69.6 percent of the payment exposure was to companies having
investment grade ratings with Standard & Poor’s Ratings Services (“Standard
& Poor’s”) and approximately 2.6 percent was to companies having less than
investment grade ratings. The remaining 27.8 percent of OERI’s
exposure is with privately held companies, municipals or cooperatives that were
not rated by Standard & Poor’s. OERI applies internal credit
analyses and policies to these non-rated companies.
Regulation
The price
at which OERI buys and sells natural gas and NGLs is currently not subject to
Federal regulation and, for the most part, is not subject to state regulation.
However, OERI is required to observe anti-market manipulation laws and related
regulations enforced by the FERC and/or the Commodity Futures Trading Commission
(“CFTC”). The FERC and CFTC hold substantial enforcement authority under the
anti-market manipulation laws and regulations, including the ability to assess
civil penalties of up to $1 million per day per violation, to order disgorgement
of profits and to recommend criminal penalties. Should OERI violate the
anti-market manipulation laws and regulations, it could also be subject to
related third party damage claims by, among other, marketers, royalty owners and
taxing authorities.
General
The
activities of OG&E and Enogex are subject to stringent and complex Federal,
state and local laws and regulations governing environmental protection
including the discharge of materials into the environment. These laws and
regulations can restrict or impact OG&E’s and Enogex’s business activities
in many ways, such as restricting the way it can handle or dispose of its
wastes, requiring remedial action to mitigate pollution conditions that may be
caused by its operations or that are attributable to former operators,
regulating future construction activities to avoid endangered species or
enjoining some or all of the operations of facilities deemed in noncompliance
with permits issued pursuant to such environmental laws and regulations. In most
instances, the applicable regulatory requirements relate to water and air
pollution control or solid waste management measures. Failure to
comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, the imposition of remedial
requirements, and the issuance of orders enjoining future operations. Certain
environmental statutes can impose burdensome liability for costs required to
clean up and restore sites where substances or wastes have been disposed or
otherwise released into the environment. Moreover, it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of substances or
wastes into the environment. OG&E and Enogex handle some materials subject
to the requirements of the Federal Resource Conservation and Recovery Act and
the Federal Water Pollution Control Act of 1972, as amended (“Federal Clean
Water Act”) and comparable state statutes, prepare and file reports and
documents pursuant to the Toxic Substance Control Act and the Emergency Planning
and Community Right to Know Act and obtain permits pursuant to the Federal Clean
Air Act and comparable state air statutes.
OG&E
and Enogex believe that their operations are in substantial compliance with
applicable environmental laws and regulations. The trend in environmental
regulation, however, is to place more restrictions and limitations on activities
that may affect the environment. For example, as discussed below, in 2009, the
EPA adopted a finding that greenhouse gases contribute to pollution and the EPA
proposed rules related to the control of greenhouse gas emissions. OG&E and
Enogex cannot assure that future events, such as changes in existing laws, the
promulgation of new laws, or the development or discovery of new facts or
conditions will not cause it to incur significant costs. Approximately $3.5
million of the Company’s capital expenditures budgeted for 2010 are to comply
with environmental laws and regulations, of which approximately $1.9 million and
$1.6 million are related to OG&E and Enogex, respectively. Approximately
$3.9 million of the Company’s capital expenditures budgeted for 2011 are to
comply with environmental laws and regulations, of which approximately $2.3
million and $1.6 million are related to OG&E and Enogex, respectively. It is
estimated that OG&E’s and Enogex’s total expenditures for capital,
operating, maintenance and other costs associated with environmental quality
will be approximately $20.9 million and $5.7 million, respectively, in 2010 as
compared to approximately $19.9 million and $4.0 million, respectively, in 2009.
Management continues to evaluate its environmental management systems to ensure
compliance with existing and proposed environmental legislation and regulations
and to better position it in a competitive market. See “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Environmental Laws and Regulations” and Note 13 of Notes to Consolidated
Financial Statements for a discussion of environmental matters, including the
impact of existing and proposed environmental legislation and
regulations.
Hazardous
Waste
OG&E’s
and Enogex’s operations generate hazardous wastes that are subject to the
Federal Resource Conservation and Recovery Act of 1976 (“RCRA”) as well as
comparable state laws which impose detailed requirements for the handling,
storage, treatment and disposal of hazardous waste.
For
OG&E, these laws impose strict “cradle to grave” requirements on generators
regarding their treatment, storage and disposal of hazardous
waste. OG&E routinely generates small quantities of hazardous
waste throughout its system that include, but are not limited to, waste paint,
spent solvents, rechargeable batteries and mercury-containing lamps. These
wastes are treated, stored and disposed off-site at facilities that are
permitted to manage them. Occasionally, larger quantities of
hazardous wastes are generated as a result of power generation-related
activities and these larger quantities are managed either on-site or
off-site. Nevertheless, through its waste minimization efforts, the
majority of OG&E’s facilities remain conditionally exempt small quantity
generators of hazardous waste.
For
Enogex, RCRA currently exempts many natural gas gathering and field processing
wastes from classification as hazardous waste. Specifically, RCRA excludes from
the definition of hazardous waste produced waters and other waste associated
with the exploration, development or production of crude oil and natural gas.
However, these oil and gas exploration and production wastes may still be
regulated under state law or the less stringent solid waste requirements of
RCRA. Moreover, ordinary industrial waste such as paint waste, waste solvents
and waste compressor oils may be regulated as hazardous waste. The
transportation of natural gas in pipelines may also generate some hazardous
wastes that are subject to RCRA or comparable state law
requirements.
In
December 2008, an impoundment used for the disposal of coal ash by a coal-fired
power plant in Kingston, Tennessee failed, releasing more than five million
cubic yards of ash onto adjacent land and into a nearby river. Shortly
thereafter, the EPA announced its intention to avert similar incidents by
promulgating rules to regulate coal ash by the end of 2009 pursuant to its
authority under the RCRA. However, in December 2009, the EPA
announced that the deadline for promulgating those rules had been extended
indefinitely due to the complexity of the technical analyses involved in the
rulemaking process. Thus, the extent to which the EPA intends to regulate coal
ash is uncertain at this time. At issue is whether the EPA intends to
regulate coal ash as a hazardous waste pursuant to Subtitle C of the RCRA and
the impact such regulation will have on its future disposal and beneficial use
insofar as OG&E is concerned. OG&E’s coal-fired power plants do not
dispose of coal ash on-site. Instead, the ash is commercially disposed off-site
or is marketed for a variety of beneficial uses including those related to the
cement/concrete manufacturing and road construction industries. Because of the
uncertainty surrounding the EPA’s decision on how coal ash will be regulated,
the financial impact on the Company is uncertain at this time.
Site
Remediation
The
Comprehensive Environmental Response, Compensation and Liability Act of 1980
(“CERCLA”) (also known as “Superfund”) and comparable state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons responsible for the release of hazardous substances
into the environment. Such classes of persons include the current and past
owners or operators of sites where a hazardous substance was released, and
companies that disposed or arranged for disposal of hazardous substances at
offsite locations such as landfills. CERCLA authorizes the EPA
and, in
some cases, third parties to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible classes of
persons the costs they incur. Because OG&E and Enogex utilize various
products and generate wastes that either are or otherwise contain CERCLA
hazardous substances, OG&E and Enogex could be subject to burdensome
liability for the costs of cleaning up and restoring sites where those
substances have been released to the environment. At this time, it is
not anticipated that any associated liability will cause any significant impact
to OG&E or Enogex.
Enogex
currently owns or leases, and has in the past owned or leased, numerous
properties that for many years have been used for the measurement, gathering,
transportation, compression, processing and storage of natural gas and NGLs.
Although Enogex used operating and disposal practices that were standard in the
industry at the time, petroleum hydrocarbons or wastes may have been disposed of
or released on or under the properties owned or leased by us or on or under
other locations where such substances have been taken for disposal. In fact,
there is evidence that petroleum spills or releases have occurred at some of the
properties owned or leased by Enogex. In addition, some of these properties have
been operated by third parties or by previous owners whose treatment and
disposal or release of petroleum hydrocarbon or wastes was not under our
control. These properties and the substances disposed or released on them may be
subject to CERCLA, RCRA and analogous state laws. Under such laws, Enogex could
be required to remove previously disposed wastes (including waste disposed of by
prior owners or operators) or remediate contaminated property (including
groundwater contamination, whether from prior owners or operators or other
historic activities or spills).
Air
Emissions
OG&E’s
and Enogex’s operations are subject to the Federal Clean Air Act, as amended,
and comparable state laws and regulations. These laws and regulations regulate
emissions of air pollutants from various industrial sources, including electric
generating units, natural gas processing plants and compressor stations, and
also impose various monitoring and reporting requirements. Such laws and
regulations may require that OG&E and Enogex obtain pre-approval for the
construction or modification of certain projects or facilities expected to
produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and
operational limitations, install emission control equipment or subject OG&E
and Enogex to monetary penalties, injunctions, conditions or restrictions on
operations, and potentially criminal enforcement actions. OG&E and Enogex
likely will be required to incur certain capital expenditures in the future for
air pollution control equipment and technology in connection with obtaining and
maintaining operating permits and approvals for air emissions. See “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Environmental Laws and Regulations” for a discussion of potentially
significant environmental capital expenditures related to air emissions
particularly as it relates to regional haze.
Water
Discharges
OG&E’s
and Enogex’s operations are subject to the Federal Clean Water Act, and
analogous state laws and regulations. These laws and regulations impose detailed
requirements and strict controls regarding the discharge of pollutants into
state and Federal waters. The discharge of pollutants, including discharges
resulting from a spill or leak incident, is prohibited unless authorized by a
permit or other agency approval. The Federal Clean Water Act and regulations
implemented thereunder also prohibit discharges of dredged and fill material in
wetlands and other waters of the United States unless authorized by an
appropriately issued permit. Any unpermitted release of pollutants from
OG&E’s and Enogex’s power plants, pipelines or facilities could result in
administrative, civil and criminal penalties as well as significant remedial
obligations. See “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Environmental Laws and
Regulations” for a discussion of water intake matters.
Climate
Change
Recent
scientific studies have suggested that emissions of certain gases, commonly
referred to as “greenhouse gases” and including carbon dioxide and methane, may
be contributing to warming of the Earth’s atmosphere. Other nations
have already agreed to regulate emissions of greenhouse gases pursuant to the
United Nations Framework Convention on Climate Change, also known as the “Kyoto
Protocol,” an international treaty pursuant to which participating countries
(not including the United States) have agreed to reduce their emissions of
greenhouse gases to below 1990 levels by 2012. At the end of 2009, an international conference to
develop a successor to the Kyoto Protocol issued a document known as the
Copenhagen Accord. Pursuant to the Copenhagen Accord, the United
States submitted a greenhouse gas emission reduction target of 17 percent
compared to 2005 levels. The U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases. In addition,
several states have declined to wait on Congress to develop and implement
climate control legislation and have already taken legal measures to reduce
emissions of greenhouse gases. For instance, at least nine states in the
Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire,
New Jersey, New York and Vermont) and five states in the West (Arizona,
California, New Mexico, Oregon and Washington) have passed laws,
adopted
regulations
or undertaken regulatory initiatives to reduce the emission of greenhouse gases,
primarily through the planned development of greenhouse gas emission inventories
and/or regional greenhouse gas cap and trade programs. Also, as a result of the
U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA is taking steps to regulate greenhouse gas emissions from mobile sources
(such as cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The enactment
of climate control laws or regulations that restrict emissions of greenhouse
gases in areas in which OG&E and Enogex conduct business could have an
adverse effect on their operations and demand for their services or
products. OG&E reports quarterly its carbon dioxide emissions
from generating units subject to the Federal Acid Rain Program and is continuing
to evaluate various options for reducing, avoiding, off-setting or sequestering
its carbon dioxide emissions. Sulfur hexafluoride and methane are
also characterized by the EPA as greenhouse gases. OG&E is a
partner in the EPA Sulfur Hexafluoride Voluntary Reduction Program and
Enogex is a partner in the EPA Natural Gas STAR Program, both
are voluntary programs to reduce emissions of greenhouse
gases.
In June
2009, the American Clean Energy and Security Act of 2009 (sometimes referred to
as the Waxman-Markey global climate change bill) was passed in the U.S. House of
Representatives. The bill includes many provisions that would
potentially have a significant impact on the Company and its
customers. The bill proposes a cap and trade regime, a renewable
portfolio standard, electric efficiency standards, revised transmission policy
and mandated investments in plug-in hybrid infrastructure and smart grid
technology. Although proposals have been introduced in the U.S.
Senate, including a proposal that would require greater reductions in greenhouse
gas emissions than the American Clean Energy and Security Act of 2009, it is
uncertain at this time whether, and in what form, legislation will be adopted by
the U.S. Senate. Both President Obama and the Administrator of the
EPA have repeatedly indicated their preference for comprehensive legislation to
address this issue and create the framework for a clean energy
economy. Compliance with any new laws or regulations regarding the
reduction of greenhouse gases could result in significant changes to the
Company’s operations, significant capital expenditures by the Company and a
significant increase in our cost of conducting business.
On
September 22, 2009, the EPA announced the adoption of the first comprehensive
national system for reporting emissions of carbon dioxide and other greenhouse
gases produced by major sources in the United States. The new
reporting requirements will apply to suppliers of fossil fuel and industrial
chemicals, manufacturers of motor vehicles and engines, as well as large direct
emitters of greenhouse gases with emissions equal to or greater than a threshold
of 25,000 metric tons per year, which includes certain OG&E and Enogex
facilities. The rule requires the collection of data beginning on
January 1, 2010 with the first annual reports due to the EPA on
March 31, 2011. Certain reporting requirements included in the
initial proposed rules that may have significantly affected capital
expenditures were not included in the final reporting
rule. Additional requirements have been reserved for further review
by the EPA with additional rulemaking possible. The outcome of such
review and cost of compliance of any additional requirements is uncertain at
this time.
On
December 15, 2009, the EPA published their finding that greenhouse gases
contribute to air pollution that may endanger public health or
welfare. Although the endangerment finding is being made in the
context of greenhouse gas emissions from new motor vehicles, the finding is
likely to result in other forms of regulation. Numerous petitions are
pending at the EPA from various state and environmental groups seeking
regulation of a variety of mobile sources (i.e., trucks, airplanes,
ships, boats, equipment, etc.) and stationary sources. With the
endangerment finding issued, the EPA is likely to begin acting on these
petitions in 2010. Additionally, on December 2, 2009 the Center for
Biological Diversity announced a petition with the EPA seeking promulgation of a
greenhouse gas National Ambient Air Quality Standard (“NAAQS”).
On
September 30, 2009, the EPA proposed two rules related to the control of
greenhouse gas emissions. The first proposal, which is related to the
prevention of significant deterioration and Title V tailoring, determines
what sources would be affected by requirements under the Federal Clean Air Act
programs for new and modified sources to control emissions of carbon dioxide and
other greenhouse gas emissions. The second proposal addresses the
December 2008 prevention of significant deterioration interpretive memo by the
EPA, which declared that carbon dioxide is not covered by the prevention of
significant deterioration provisions of the Federal Clean Air
Act. The outcome of these proposals is uncertain at this
time.
Future
Capital Requirements
Capital
Requirements
The
Company’s primary needs for capital are related to acquiring or constructing new
facilities and replacing or expanding existing facilities at OG&E and
Enogex. Other working capital requirements are expected to be
primarily related to maturing debt, operating lease obligations, hedging
activities, delays in recovering unconditional fuel purchase obligations, fuel
clause under and over recoveries and other general corporate
purposes. The Company generally meets its cash needs
through a
combination of cash generated from operations, short-term borrowings (through a
combination of bank borrowings and commercial paper) and permanent
financings. See “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Liquidity and Capital
Requirements” for a discussion of the Company’s capital
requirements.
Capital
Expenditures
The
Company’s consolidated estimates of capital expenditures are
approximately: 2010 - $660 million, 2011 - $620 million, 2012 - $565
million, 2013 - $495 million, 2014 - $420 million and 2015 - $385
million. These capital expenditures represent the base maintenance
capital expenditures (i.e., capital expenditures to
maintain and operate the Company’s businesses) plus capital expenditures for
known and committed projects (collectively referred to as the “Base Capital
Expenditure Plan”). The table below summarizes the capital
expenditures by category:
|
|
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
|
|
(A) These
capital expenditures are contingent upon OCC approval of OG&E’s Positive
Energy Smart Grid program and are net of the Smart Grid $130 million grant
approved by the DOE.
(B) The
Base Capital Expenditure Plan above excludes any environmental expenditures
associated with Best Available Retrofit Technology (“BART”) requirements due to
the uncertainty regarding BART costs. As discussed in “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations – Environmental
Laws and Regulations,” pursuant to a proposed regional haze agreement OG&E
has agreed to install low nitrogen oxide (“NOX”) burners and related equipment at the three affected
generating stations. Preliminary estimates indicate the cost will be
approximately $100 million (plus or minus 30 percent). For further
information, see “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Environmental Laws and
Regulations”.
Additional
capital expenditures beyond those identified in the table above, including
additional incremental growth opportunities in transmission assets, wind
generation assets and at Enogex, will be evaluated based upon their impact upon
achieving the Company’s financial objectives. The capital expenditure
projections related to Enogex in the table above reflect base market conditions
at February 17, 2010 and do not reflect the potential opportunity for a set of
growth projects that could materialize.
Enogex’s
Refinancing of Long-Term Debt and Tender Offer
On
June 24, 2009, Enogex issued $200 million of 6.875% 5-year senior notes in
a transaction exempt from the registration requirements of the Securities Act of
1933. Enogex applied a portion of the net proceeds from the sale of
the new notes to pay the purchase price in a tender offer for its 8.125% notes
due January 15, 2010 with the remainder of the net proceeds being used to repay
a portion of Enogex’s borrowings under its revolving credit agreement and for
general corporate purposes. Pursuant to the tender offer, on July 23, 2009,
Enogex purchased approximately $110.8 million principal amount of the 8.125%
senior notes due January 15, 2010 and those repurchased notes were retired and
cancelled.
On
November 10, 2009, Enogex issued $250 million of 6.25% 10-year senior notes in a
transaction exempt from the registration requirements of the Securities Act of
1933. Enogex applied the net proceeds from the sale of the new notes
to repay borrowings under its revolving credit agreement, with any excess net
proceeds being invested at the OGE Energy level. Enogex’s permanent use of the
net proceeds from this debt issuance was to repay a portion of the $289.2
million outstanding aggregate principal amount of Enogex’s 8.125% senior notes,
which matured on January 15, 2010. On January 15, 2010, the $289.2 million
outstanding aggregate principal amount of Enogex’s 8.125% senior notes was
repaid.
Pension
and Postretirement Benefit Plans
During
each of 2009 and 2008, the Company made contributions to its pension plan of
approximately $50.0 million to help ensure that the pension plan maintains an
adequate funded status. During 2010, the Company may contribute up to
$50.0 million to its pension plan. See “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Liquidity and Capital Requirements” for a discussion of the Company’s pension
and postretirement benefit plans.
Future
Sources of Financing
Management
expects that cash generated from operations, proceeds from the issuance of long
and short-term debt and proceeds from the sales of common stock to the public
through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan
(“DRIP/DSPP”) or other offerings will be adequate over the next three years to
meet anticipated cash needs. The Company utilizes short-term
borrowings (through a combination of bank borrowings and commercial paper) to
satisfy temporary working capital needs and as an interim source of financing
capital expenditures until permanent financing is arranged.
Short-Term
Debt
Short-term
borrowings generally are used to meet working capital
requirements. The Company borrows on a short-term basis, as
necessary, by the issuance of commercial paper and by borrowings under its
revolving credit agreements. The short-term debt balance was
approximately $175.0 million and $298.0 million at December 31, 2009 and 2008,
respectively. The December 31, 2009 short-term debt balance of
approximately $175.0 million is comprised entirely of outstanding commercial
paper borrowings at OGE Energy. The December 31, 2008 short-term debt balance of
approximately $298.0 million is comprised entirely of outstanding borrowings
under OGE Energy’s revolving credit agreement. At December 31, 2009,
there were no outstanding borrowings under Enogex’s revolving credit
agreement. At December 31, 2008, Enogex had approximately $120.0
million in outstanding borrowings under its revolving credit
agreement. Also, OG&E has the necessary regulatory approvals to
incur up to $800 million in short-term borrowings at any time for a two-year
period beginning January 1, 2009 and ending December 31, 2010. See
Note 10 of Notes to the Consolidated Financial Statements for a discussion of
the Company’s short-term debt activity. The Company has approximately
$58.1 million and $174.4 million of cash and cash equivalents at December 31,
2009 and 2008, respectively.
Registration
Statement Filing
During
the first half of 2010, the Company expects to file a Form S-3 Registration
Statement to register debt and equity securities for sale by the Company and
OG&E.
Expected
Issuance of OG&E Long-Term Debt
OG&E
expects to issue approximately $250 million of long-term debt in mid-2010,
depending on market conditions, to fund capital expenditures, repay short-term
borrowings and for general corporate purposes.
The
Company expects to issue between approximately $12 million and $15 million in
its DRIP/DSPP in 2010. See Note 8 of Notes to Consolidated Financial Statements
for a discussion of the Company’s common stock activity.
EMPLOYEES
The
Company and its subsidiaries had 3,363 employees at December 31,
2009.
ACCESS TO SECURITIES AND EXCHANGE COMMISSION
FILINGS
The
Company’s web site address is www.oge.com. Through
the Company’s web site under the heading “Investor Relations”, “SEC Filings,”
the Company makes available, free of charge, its annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments
to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Exchange Act as soon as reasonably practicable after such material is
electronically filed with or furnished to the SEC. Our Internet
website and the information contained therein or connected thereto are not
intended to be incorporated into this Form 10-K and should not be considered a
part of this Form 10-K.
In
the discussion of risk factors set forth below, unless the context otherwise
requires, the terms “OGE Energy”, “we”, “our” and “us” refer to OGE Energy
Corp., “OG&E” refers to our subsidiary Oklahoma Gas and Electric Company and
“Enogex” refers to our subsidiary Enogex LLC and its subsidiaries. In
addition to the other information in this Annual Report on Form 10-K and other
documents filed by us and/or our subsidiaries with the SEC from time to time,
the following factors should be carefully considered in evaluating OGE Energy
and its subsidiaries. Such factors could affect actual results and
cause results to differ materially from those expressed in any forward-looking
statements made by or on behalf of us or our subsidiaries. Additional
risks and uncertainties not currently known to us or that we currently view as
immaterial may also impair our business operations.
REGULATORY
RISKS
Our
profitability depends to a large extent on the ability of OG&E to fully
recover its costs from its customers and there may be changes in the regulatory
environment that impair its ability to recover costs from its
customers.
We are
subject to comprehensive regulation by several Federal and state utility
regulatory agencies, which significantly influences our operating environment
and OG&E’s ability to fully recover its costs from utility
customers. With rising fuel costs, recoverability of under recovered
amounts from our customers is a significant risk. The utility
commissions in the states where OG&E operates regulate many aspects of our
utility operations including siting and construction of facilities, customer
service and the rates that we can charge customers. The profitability
of our utility operations is dependent on our ability to fully recover costs
related to providing energy and utility services to our customers.
In recent
years, the regulatory environments in which we operate have received an
increased amount of public attention. It is possible that there could
be changes in the regulatory environment that would impair our ability to fully
recover costs historically absorbed by our customers. State utility
commissions generally possess broad powers to ensure that the needs of the
utility customers are being met. We cannot assure that the OCC, APSC
and the FERC will grant us rate increases in the future or in the amounts we
request, and they could instead lower our rates.
We are
unable to predict the impact on our operating results from the future regulatory
activities of any of the agencies that regulate us. Changes in
regulations or the imposition of additional regulations could have an adverse
impact on our results of operations.
OG&E’s
rates are subject to rate regulation by the states of Oklahoma and Arkansas, as
well as by a Federal agency, whose regulatory paradigms and goals may not be
consistent.
OG&E
is currently a vertically integrated electric utility and most of its revenue
results from the sale of electricity to retail customers subject to bundled
rates that are approved by the applicable state utility commission and from the
sale of electricity to wholesale customers subject to rates and other matters
approved by the FERC.
OG&E
operates in Oklahoma and western Arkansas and is subject to rate regulation by
the OCC and the APSC, in addition to the FERC. Exposure to
inconsistent state and Federal regulatory standards may limit our ability to
operate
profitably. Further
alteration of the regulatory landscape in which we operate may harm our
financial position and results of operations.
Costs
of compliance with environmental laws and regulations are significant and the
cost of compliance with future environmental laws and regulations may adversely
affect our results of operations, consolidated financial position, or
liquidity.
We are
subject to extensive Federal, state and local environmental statutes, rules and
regulations relating to air quality, water quality, waste management, wildlife
mortality, natural resources and health and safety that could, among other
things, restrict or limit the output of certain facilities or the use of certain
fuels required for the production of electricity and/or require additional
pollution control equipment and otherwise increase costs. There are
significant capital, operating and other costs associated with compliance with
these environmental statutes, rules and regulations and those costs may be even
more significant in the future. For example, the EPA has proposed
lowering the ambient standards for ozone and SO2. If these standards
are adopted, reductions in emissions from OG&E’s electric generating
facilities could be required, which may result in significant capital and
operating expenditures.
There is
inherent risk of the incurrence of environmental costs and liabilities in our
operations due to our handling of natural gas, air emissions related to our
operations and historical industry operations and waste disposal practices. For
example, an accidental release from one of our facilities could subject us to
substantial liabilities arising from environmental cleanup and restoration
costs, claims made by neighboring landowners and other third parties for
personal injury and property damage and fines or penalties for related
violations of environmental laws or regulations. We may be unable to
recover these costs from insurance. Moreover, the possibility exists
that stricter laws, regulations or enforcement policies could significantly
increase compliance costs and the cost of any remediation that may become
necessary.
There
also is growing concern nationally and internationally about global climate
change and the contribution of emissions of greenhouse gases including, most
significantly, carbon dioxide. This concern has led to increased
interest in legislation at the Federal level, actions at the state level,
litigation relating to greenhouse gas emissions and pressure for greenhouse gas
emission reductions from investor organizations and the international
community. Recently, two Federal courts of appeal have reinstated
nuisance-type claims against emitters of carbon dioxide, including several
utility companies, alleging that such emissions contribute to global
warming. Although the Company is not a defendant in either
proceeding, additional litigation in Federal and state courts over these issues
is expected.
OG&E
reports quarterly its carbon dioxide emissions from its generating stations
under the EPA’s acid rain program and is continuing to evaluate various options
for reducing, avoiding, off-setting or sequestering its carbon dioxide
emissions. Additional reporting is required by a rule issued by the
EPA in 2009, and the EPA has proposed rules that could regulate carbon dioxide
emissions under the Federal Clean Air Act. For a further discussion
of environmental matters that may affect the Company, see “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Environmental Laws and Regulations” and “Environmental Laws and Regulations” in
Note 13 of Notes to Consolidated Financial Statements. If legislation
or regulations are passed at the Federal or state levels in the future requiring
mandatory reductions of carbon dioxide and other greenhouse gases on generation
facilities to address climate change, this could result in significant
additional compliance costs that would affect our future consolidated financial
position, results of operations and cash flows if such costs are not recovered
through regulated rates.
We
are subject to physical and financial risks associated with climate
change.
There is a growing concern that
emissions of greenhouse gases are linked to global climate change. Climate
change creates physical and financial risk. Physical risks from climate change
could include an increase in sea level and changes in weather conditions, such
as an increase in changes in precipitation and extreme weather
events. OG&E’s operations are not sensitive to potential future
sea-level rise as it does not operate in coastal areas. However, OG&E’s
power delivery systems are vulnerable to damage from extreme weather events,
such as ice storms, tornadoes and severe thunderstorms. These types of extreme
weather events are common on the OG&E system, so OG&E includes storm
restoration in its budgeting process as a normal business expense. To the extent
the frequency of extreme weather events increases, this could increase
OG&E’s cost of providing service. OG&E’s electric generating
facilities are designed to withstand the effects of extreme weather events,
however, extreme weather conditions increase the stress placed on such systems.
If climate change results in temperature increases in OG&E’s service
territory, OG&E could expect increased electricity demand due to the
increase in temperature and longer warm seasons. While this increase in demand
could lead to increased energy consumption, it could also create a physical
strain on OG&E’s generating resources. At the same time, OG&E could face
restrictions on the ability to meet that demand if, due to drought severity,
there is a lack of sufficient water for use in cooling during the electricity
generating process.
In addition to the above cited risks,
to the extent that any climate change adversely affects the national or regional
economic health through increased rates caused by the inclusion of additional
regulatory imposed costs (carbon dioxide taxes or costs associated with
additional regulatory requirements), the Company may be adversely impacted. A
declining economy could adversely impact the overall financial health of the
Company because of lack of load growth and decreased sales
opportunities.
To the extent financial markets view
climate change and emissions of greenhouse gases as a financial risk, this could
negatively affect our ability to access capital markets or cause us to receive
less than ideal terms and conditions.
We
may not be able to recover the costs of our substantial planned investment in
capital improvements and additions.
Our
business plan for OG&E calls for extensive investment in capital
improvements and additions, including the installation of environmental upgrades
and retrofits and modernizing existing infrastructure as well as other
initiatives. Significant portions of OG&E’s facilities were
constructed many years ago. Older generation equipment, even if
maintained in accordance with good engineering practices, may require
significant capital expenditures to maintain efficiency, to comply with changing
environmental requirements or to provide reliable
operations. OG&E currently provides service at rates approved by
one or more regulatory commissions. If these regulatory commissions
do not approve adjustments to the rates we charge, we would not be able to
recover the costs associated with our planned extensive
investment. This could adversely affect our results of operations and
financial position. While we may seek to limit the impact of any
denied recovery by attempting to reduce the scope of our capital investment,
there can no assurance as to the effectiveness of any such mitigation efforts,
particularly with respect to previously incurred costs and
commitments.
Our
planned capital investment program coincides with a material increase in the
historic prices of the fuels used to generate electricity. Many of our
jurisdictions have fuel clauses that permit us to recover these increased fuel
costs through rates without a general rate case. While prudent
capital investment and variable fuel costs each generally warrant recovery, in
practical terms our regulators could limit the amount or timing of increased
costs that we would recover through higher rates. Any such limitation
could adversely affect our results of operations and financial
position.
The
construction by Enogex of additions or modifications to its existing systems,
and the construction of new midstream assets, involves numerous regulatory,
environmental, political and legal uncertainties, many of which are beyond
Enogex’s control and may require the expenditure of significant amounts of
capital. These projects, once undertaken, may not be completed on schedule or at
the budgeted cost, or at all. Moreover, Enogex’s revenues and cash flows may not
increase immediately upon the expenditure of funds on a particular project. For
instance, if Enogex expands an existing pipeline or constructs a new pipeline,
the construction may occur over an extended period of time, and Enogex may not
receive any material increases in revenues or cash flows until the project is
completed. In addition, Enogex may construct facilities to capture anticipated
future growth in production in a region in which such growth does not
materialize. Since Enogex is not engaged in the exploration for and development
of natural gas, Enogex often does not have access to third-party estimates of
potential reserves in areas to be developed prior to constructing facilities in
those areas. To the extent Enogex relies on estimates of future production in
deciding to construct additions to its systems, those estimates may prove to be
inaccurate because there are numerous uncertainties inherent in estimating
future production. As a result, new facilities may not be able to attract
sufficient throughput to achieve expected investment return, which could
adversely affect Enogex’s results of operations, consolidated financial position
and cash flows. In addition, the construction of additions to
existing gathering and transportation assets may require new rights-of-way prior
to construction. Those rights-of-way to connect new natural gas supplies to
existing gathering lines may be unavailable and Enogex may not be able to
capitalize on attractive expansion opportunities. Additionally, it may become
more expensive to obtain new rights-of-way or to renew existing rights-of-way.
If the cost of renewing or obtaining new rights-of-way increases, Enogex’s
consolidated financial position, results of operations and cash flows could be
adversely affected.
The
regional power market in which OG&E operates has changing transmission
regulatory structures, which may affect the transmission assets and related
revenues and expenses.
OG&E
currently owns and operates transmission and generation facilities as part of a
vertically integrated utility. OG&E is a member of the SPP RTO
and has transferred operational authority (but not ownership) of OG&E’s
transmission facilities to the SPP RTO. The SPP RTO implemented a
regional energy imbalance service market on February 1,
2007. OG&E has participated, and continues to participate, in the
SPP energy imbalance service market to aid in the optimization of its physical
assets to serve OG&E’s customers. OG&E has not participated in the
SPP energy imbalance service market for any speculative trading
activities. The SPP purchases and sales are not allocated to individual
customers. OG&E records the hourly sales to the SPP at market
rates in Operating Revenues and the hourly purchases from the SPP at market
rates in Cost of Goods Sold in its Consolidated Financial
Statements. OG&E’s revenues, expenses, assets and liabilities may
be adversely affected by changes in the organization, operation and regulation
by the FERC or the SPP RTO.
Increased
competition resulting from restructuring efforts could have a significant
financial impact on us and OG&E and consequently decrease our
revenue.
We have
been and will continue to be affected by competitive changes to the utility and
energy industries. Significant changes already have occurred and
additional changes have been proposed to the wholesale electric
market. Although retail restructuring efforts in Oklahoma and
Arkansas have been postponed for the time being, if such efforts were renewed,
retail competition and the unbundling of regulated energy service could have a
significant financial impact on us due to possible impairments of assets, a loss
of retail customers, lower profit margins and/or increased costs of
capital. Any such restructuring could have a significant impact on
our consolidated financial position, results of operations and cash flows. We
cannot predict when we will be subject to changes in legislation or regulation,
nor can we predict the impact of these changes on our consolidated financial
position, results of operations or cash flows.
A
change in the jurisdictional characterization of some of Enogex’s assets by
Federal, state or local regulatory agencies or a change in policy by those
agencies may result in increased regulation of its assets, which may cause its
revenues to decline and operating expenses to increase.
Enogex’s
natural gas gathering and intrastate transportation operations are generally
exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938, but
the FERC regulation may indirectly impact these businesses and the markets for
products derived from these businesses. The FERC’s policies and practices across
the range of its oil and natural gas regulatory activities, including, for
example, its policies on interstate open access transportation, ratemaking and
capacity release and its promotion of market centers, may indirectly affect
intrastate markets. In recent years, the FERC has aggressively pursued
pro-competitive policies in its regulation of interstate oil and natural gas
pipelines. However, we cannot assure that the FERC will continue to pursue these
same objectives as it considers matters such as pipeline rates and rules and
policies that may indirectly affect the intrastate natural gas transportation
business.
Enogex’s
natural gas transportation and storage operations are subject to regulation by
the FERC pursuant to Section 311 of the NGPA, which could have an adverse impact
on its ability to establish transportation and storage rates that would allow it
to recover the full cost of operating its transportation and storage facilities,
including a reasonable return, and an adverse impact on its consolidated
financial position, results of operations or cash flows.
The FERC
has jurisdiction over transportation rates charged by Enogex for transporting
natural gas in interstate commerce under Section 311 of the NGPA. Rates to
provide such service must be “fair and equitable” under the NGPA and are subject
to review and approval by the FERC at least once every three
years. See Note 14 of Notes to Consolidated Financial Statements for
a further discussion of Enogex’s FERC Section 311 proceedings. There
can be no assurance that the FERC will approve Enogex’s requested
rates.
Enogex’s
natural gas transportation, storage and gathering operations are subject to
regulation by agencies in Oklahoma and Texas, and that regulation could have an
adverse impact on its ability to establish rates that would allow it to recover
the full cost of operating its facilities, including a reasonable return, and
its consolidated financial position, results of operations or cash
flows.
State
regulation of natural gas transportation, storage and gathering facilities
generally focuses on various safety, environmental and, in some circumstances,
nondiscriminatory access requirements and complaint-based rate regulation.
Natural gas gathering may receive greater regulatory scrutiny at the state
level; therefore, Enogex’s natural gas gathering operations could be adversely
affected should they become subject to the application of state regulation of
rates and services. Enogex’s gathering operations could also be subject to
safety and operational regulations relating to the design, construction,
testing, operation, replacement and maintenance of gathering facilities.
Additional rules and legislation pertaining to these matters are considered and,
in some instances, adopted from time to time. We cannot predict what effect, if
any, such changes might have on Enogex’s operations, but Enogex could be
required to incur additional capital expenditures and increased costs depending
on future legislative and regulatory changes. Other state and local regulations
also may affect Enogex’s business. Any such state regulation could have an
adverse impact on Enogex’s business and its consolidated financial position,
results of operations or cash flows.
Enogex
may incur significant costs and liabilities resulting from pipeline integrity
programs and related repairs.
Pursuant
to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations
requiring pipeline operators to develop integrity management programs for
applicable pipelines. The regulations require operators to:
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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;
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develop
a baseline plan to prioritize the assessment of a covered pipeline
segment;
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gather
data and identify and characterize applicable threats that could impact a
covered pipeline segment;
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discover,
evaluate and remediate problems in accordance with the program
requirements;
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continuously
improve all elements of the integrity
program;
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continuously
perform preventative and mitigation
actions;
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maintain
a quality assurance process and management-of-change process;
and
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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.
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During
2009, Enogex incurred approximately $10.8 million of capital expenditures and
operating costs for pipeline integrity management. Enogex currently estimates
that it will incur capital expenditures and operating costs of approximately
$34.2 million between 2010 and 2014 in connection with pipeline integrity
management. The estimated capital expenditures and operating costs include
Enogex’s estimates for the assessment, remediation, prevention or other
mitigation that may be determined to be necessary. At this time, we cannot
predict the ultimate costs of its integrity management program and compliance
with this regulation because those costs will depend on the number and extent of
any repairs found to be necessary. Enogex will continue to assess,
remediate and maintain the integrity of its pipelines. The results of these
activities could cause Enogex to incur significant and unanticipated capital and
operating expenditures for repairs or upgrades deemed necessary to ensure the
continued safe and reliable operations of its pipelines.
Events
that are beyond our control have increased the level of public and regulatory
scrutiny of our industry. Governmental and market reactions to these
events may have negative impacts on our business, consolidated financial
position, cash flows and access to capital.
As a
result of accounting irregularities at public companies in general, and energy
companies in particular, and investigations by governmental authorities into
energy trading activities, public companies, including those in the regulated
and unregulated utility business, have been under an increased amount of public
and regulatory scrutiny and suspicion. The accounting irregularities
have caused regulators and legislators to review current accounting practices,
financial disclosures and relationships between companies and their independent
auditors. The capital markets and rating agencies also have increased
their level of scrutiny. We believe that we are complying with all
applicable laws and accounting standards, but it is difficult or impossible to
predict or control what effect these types of events may have on our business,
consolidated financial position, cash flows or access to the capital
markets. It is unclear what additional laws or regulations may
develop, and we cannot predict the ultimate impact of any future changes in
accounting regulations or practices in general with respect to public companies,
the energy industry or our operations specifically. Any new
accounting standards could affect the way we are required to record revenues,
expenses, assets, liabilities and equity. These changes in accounting
standards could lead to negative impacts on reported earnings or decreases in
assets or increases in liabilities that could, in turn, affect our results of
operations and cash flows.
We
are subject to substantial utility and energy regulation by governmental
agencies. Compliance with current and future utility and energy
regulatory requirements and procurement of necessary approvals, permits and
certifications may result in significant costs to us.
We are
subject to substantial regulation from Federal, state and local regulatory
agencies. We are required to comply with numerous laws and
regulations and to obtain numerous permits, approvals and certificates from the
governmental agencies that regulate various aspects of our businesses, including
customer rates, service regulations, retail service territories, sales of
securities, asset acquisitions and sales, accounting policies and practices and
the operation of generating facilities. We believe the necessary
permits, approvals and certificates have been obtained for our existing
operations and that our business is conducted in accordance with applicable
laws; however, we are unable to predict the impact on our operating results from
future regulatory activities of these agencies.
The
Energy Policy Act of 2005 gave the FERC authority to establish mandatory
electric reliability rules enforceable with significant monetary
penalties. The FERC has approved the North American Electric
Reliability Corporation (“NERC”) as the Electric Reliability Organization for
North America and delegated to it the development and enforcement of electric
transmission reliability rules. It is the Company’s intent to comply
with all applicable reliability rules and expediently correct a violation should
it occur. OG&E is subject to a NERC compliance audit every three
years as well as periodic spot check audits and cannot predict the outcome of
those audits.
OPERATIONAL
RISKS
Our
results of operations may be impacted by disruptions beyond our
control.
We are
exposed to risks related to performance of contractual obligations by our
suppliers. We are dependent on coal for much of our electric
generating capacity. We rely on suppliers to deliver coal in
accordance with short and long-term contracts. We have certain coal
supply contracts in place; however, there can be no assurance that the
counterparties to these agreements will fulfill their obligations to supply coal
to us. The suppliers under these agreements may experience financial
or technical problems that inhibit their ability to fulfill their obligations to
us. In addition, the suppliers under these agreements may not be
required to supply coal to us under certain circumstances, such as in the event
of a natural disaster. Coal delivery may be subject to short-term
interruptions or reductions due to various factors, including transportation
problems, weather and availability of equipment. Failure or delay by
our suppliers of coal deliveries could disrupt our ability to deliver
electricity and require us to incur additional expenses to meet the needs of our
customers. In addition, as agreements with our suppliers expire, we
may not be able to enter into new agreements for coal delivery on equivalent
terms.
Also,
because our generation and transmission systems are part of an interconnected
regional grid, we face the risk of possible loss of business due to a disruption
or black-out caused by an event (severe storm, generator or transmission
facility outage) on a neighboring system or the actions of a neighboring
utility. Any such disruption could result in a significant decrease
in revenues and significant additional costs to repair assets, which could have
a material adverse impact on our consolidated financial position and results of
operations.
Economic
conditions could negatively impact our business.
Our
operations are affected by local, national and worldwide economic conditions.
The consequences of a prolonged recession could include a lower level of
economic activity and uncertainty regarding energy prices and the capital and
commodity markets. A lower level of economic activity could result in
a decline in energy consumption, which could adversely affect our revenues and
future growth. Instability in the financial markets, as a result of
recession or otherwise, also could affect the cost of capital and our ability to
raise capital.
Current
economic conditions may be exacerbated by insufficient financial sector
liquidity leading to potential increased unemployment, which could impact the
ability of our customers to pay timely, increase customer bankruptcies, and
could lead to increased bad debt. If such circumstances occur, we
expect that commercial and industrial customers would be impacted first, with
residential customers following.
We
are subject to information security risks.
A
security breach of our information systems could impact the reliability of the
generation fleet and/or reliability of the transmission and distribution system
or subject us to financial harm associated with theft or inappropriate release
of certain types of operating or customer information. We cannot accurately
assess the probability that a security breach may occur, despite the measures we
have taken to prevent such a breach, and we are unable to quantify the potential
impact of such an event.
Terrorist
attacks, and the threat of terrorist attacks, have resulted in increased costs
to our business. Continued hostilities in the Middle East or other sustained
military campaigns may adversely impact our consolidated financial position,
results of operations and cash flows.
The
long-term impact of terrorist attacks, such as the attacks that occurred on
September 11, 2001, and the magnitude of the threat of future terrorist attacks
on the electric utility and natural gas midstream industry in general, and on us
in particular, cannot be known. Increased security measures taken by us as a
precaution against possible terrorist attacks have resulted in increased costs
to our business. Uncertainty surrounding continued hostilities in the Middle
East or other sustained military campaigns may affect our operations in
unpredictable ways, including disruptions of supplies and markets for our
products, and the possibility that our infrastructure facilities could be direct
targets of, or indirect casualties of, an act of terror. Changes in the
insurance markets attributable to terrorist attacks may make certain types of
insurance more difficult for us to obtain. Moreover, the insurance
that may be available to us may be significantly more expensive than existing
insurance coverage.
Enogex
does not own all of the land on which its pipelines and facilities are located,
which could disrupt its operations.
Enogex
does not own all of the land on which its pipelines and facilities have been
constructed, and it is therefore subject to the possibility of more onerous
terms and/or increased costs to retain necessary land use if it does not have
valid
rights-of-way
or if such rights-of-way lapse or terminate. Enogex obtains the rights to
construct and operate its pipelines on land owned by third parties and
governmental agencies sometimes for a specific period of time. A loss of these
rights, through Enogex’s inability to renew right-of-way contracts or otherwise,
could cause Enogex to cease operations temporarily or permanently on the
affected land, increase costs related to the construction and continuing
operations elsewhere, reduce its revenue and impair its cash flows.
Weather
conditions such as tornadoes, thunderstorms, ice storms, wind storms, as well as
seasonal temperature variations may adversely affect our consolidated financial
position, results of operations and cash flows.
Weather
conditions directly influence the demand for electric power. In
OG&E’s service area, demand for power peaks during the hot summer months,
with market prices also typically peaking at that time. As a result,
overall operating results may fluctuate on a seasonal and quarterly
basis. In addition, we have historically sold less power, and
consequently received less revenue, when weather conditions are
milder. Unusually mild weather in the future could reduce our
revenues, net income, available cash and borrowing ability. Severe
weather, such as tornadoes, thunderstorms, ice storms and wind storms, may cause
outages and property damage which may require us to incur additional costs that
are generally not insured and that may not be recoverable from
customers. The effect of the failure of our facilities to operate as
planned, as described above, would be particularly burdensome during a peak
demand period.
Natural
gas and NGLs prices are volatile, and changes in these prices could negatively
affect Enogex’s and OERI’s results of operations and cash flows.
Enogex’s
and OERI’s results of operations and cash flows could be negatively affected by
adverse movements in the prices of natural gas and NGLs depending on factors
that are beyond our control. These factors include demand for these
commodities, which fluctuates with changes in market and economic conditions and
other factors, including the impact of seasonality and weather, general economic
conditions, the level of domestic and offshore natural gas production and
consumption, the availability of imported natural gas, liquified natural gas and
NGLs, actions taken by foreign oil and gas producing nations, the availability
of local, intrastate and interstate transportation systems, the availability and
marketing of competitive fuels, the impact of energy conservation efforts,
technological advances affecting energy consumption and the extent of
governmental regulation and taxation.
Enogex’s
keep-whole natural gas processing arrangements, which constituted approximately
six percent of its gross margin and accounted for approximately 35 percent of
its natural gas processed volumes during 2009, expose it to fluctuations in the
pricing spreads between NGLs prices and natural gas prices. Keep-whole
processing arrangements generally require a processor of natural gas to keep its
shippers whole on a Btu basis by replacing the Btu’s of the NGLs extracted from
the production stream with Btu’s of natural gas. Therefore, if natural gas
prices increase and NGLs prices do not increase by a corresponding amount, the
processor has to replace the Btu’s of natural gas at higher prices and
processing margins are negatively affected.
Enogex’s
percent-of-proceeds and percent-of-liquids natural gas processing agreements
constituted approximately seven percent of its gross margin and accounted for
approximately 45 percent of its natural gas processed volumes during 2009. Under
these arrangements, Enogex generally gathers raw natural gas from producers at
the wellhead, transports the gas through its gathering system, processes the gas
and sells the processed gas and/or NGLs at prices based on published index
prices. The price paid to producers is based on an agreed percentage of the
proceeds of the sale of processed natural gas, NGLs or both or the expected
proceeds based on an index price. Enogex refers to contracts in which it shares
in specified percentages of the proceeds from the sale of natural gas and NGLs
as percent-of-proceeds arrangements and in which it receives proceeds from the
sale of NGLs or the NGLs themselves as compensation for its processing services
as percent-of-liquids arrangements. These arrangements expose Enogex to risks
associated with the price of natural gas and NGLs.
At any
given time, Enogex’s overall portfolio of processing contracts may reflect a net
short position in natural gas (meaning that Enogex was a net buyer of natural
gas) and a net long position in NGLs (meaning that Enogex was a net seller of
NGLs). As a result, Enogex’s margins could be negatively impacted to the extent
the price of NGLs decreases in relation to the price of natural
gas.
Because
of the natural decline in production from existing wells connected to Enogex’s
systems, Enogex’s success depends on its ability to gather new sources of
natural gas, which depends on certain factors beyond its control. Any decrease
in supplies of natural gas could adversely affect Enogex’s business and results
of operations and cash flows.
Enogex’s
gathering and transportation systems are connected to or dependent on the level
of production from natural gas wells, from which production will naturally
decline over time. As a result, Enogex’s cash flows associated with these wells
will also decline over time. To maintain or increase throughput levels on its
gathering and transportation systems and
the asset
utilization rates at its natural gas processing plants, Enogex must continually
obtain new natural gas supplies. The primary factors affecting Enogex’s ability
to obtain new supplies of natural gas and attract new customers to its assets
depends in part on the level of successful drilling activity near these systems,
Enogex’s ability to compete for volumes from successful new wells and Enogex’s
ability to expand capacity as needed. If Enogex is not able to obtain new
supplies of natural gas to replace the natural decline in volumes from existing
wells, throughput on its gathering, processing and transportation facilities
would decline, which could have a material adverse effect on its business,
results of operations and cash flows.
Enogex’s
businesses are dependent, in part, on the drilling decisions of
others.
All of
Enogex’s businesses are dependent on the continued availability of natural gas
production. Enogex does not have control over the level of drilling activity in
the areas of its operations, the amount of reserves associated with the wells or
the rate at which production from a well will decline. The primary factor that
impacts drilling decisions is natural gas prices. Natural gas prices reached
relatively high levels in mid-2008 due to the impact of rising demand for
natural gas but have returned to the near $4.50 per MMBtu level due to a rapid
decline in demand for natural gas. A sustained decline in natural gas prices
could result in a decrease in exploration and development activities in the
fields served by Enogex’s gathering, processing and transportation facilities,
which would lead to reduced utilization of these assets. Other factors that
impact production decisions include producers’ capital budgets, access to
credit, the ability of producers to obtain necessary drilling and other
governmental permits, costs of steel and other commodities, geological
considerations, demand for hydrocarbons, the level of reserves, other production
and development costs and regulatory changes. Because of these factors, even if
new natural gas reserves are discovered in areas served by Enogex’s assets,
producers may choose not to develop those reserves.
The
Company engages in commodity hedging activities to minimize the impact of
commodity price risk, which may have a volatile effect on its earnings and cash
flows.
The
Company is exposed to changes in commodity prices in its operations. To minimize
the risk of commodity prices, the Company may enter into physical forward sales
or financial derivative contracts to hedge purchase and sale commitments, fuel
requirements, contractual long/short obligations, keep-whole positions,
percent-of-liquids positions and inventories of natural gas.
Enogex
has instituted a hedging program that is intended to reduce the commodity price
risk associated with Enogex’s keep-whole and percent-of-liquids
arrangements. At December 31, 2009, Enogex had hedged a majority of
its expected non-ethane NGLs volumes attributable to these arrangements, along
with the natural gas MMBtu equivalent for keep-whole volumes, for 2010 and 2011.
At December 31, 2009, Enogex had not hedged any of its expected ethane volumes
attributable to these arrangements, along with the natural gas MMBtu equivalent
for keep-whole volumes. Enogex has the option to reject ethane if processing it
is not economical. Management will continue to evaluate whether to
enter into any new hedging arrangements, and there can be no assurance that
Enogex will enter into any new hedging arrangements. Also, Enogex may seek in
the future to further limit its exposure to changes in natural gas and NGLs
commodity prices and interest rates by using financial derivative instruments
and other hedging mechanisms. To the extent Enogex hedges its commodity price
and interest rate exposures, Enogex may forego the benefits that otherwise would
be experienced if commodity prices or interest rates were to change in Enogex’s
favor. In addition, even though management monitors Enogex’s hedging activities,
these activities can result in substantial losses. Such losses could occur under
various circumstances, including if a counterparty does not perform its
obligations under the applicable hedging arrangement, the hedging arrangement is
imperfect or ineffective, or the hedging policies and procedures are not
followed or do not work as planned.
Enogex
depends on certain key natural gas producer customers for a significant portion
of its supply of natural gas and NGLs. The loss of, or reduction in volumes
from, any of these customers could result in a decline in its consolidated
financial position, results of operations or cash flows.
Enogex
relies on certain key natural gas producer customers for a significant portion
of its natural gas and NGLs supply. During 2009, Chesapeake Energy Marketing
Inc., Devon Gas Services, L.P., Apache Corporation, BP America Production
Company and Samson Resources Company accounted for approximately 52.4 percent of
Enogex’s natural gas and NGLs supply. The loss of the natural gas and NGLs
volumes supplied by these customers, the failure to extend or replace these
contracts or the extension or replacement of these contracts on less favorable
terms, as a result of competition or otherwise, could have a material adverse
effect on Enogex’s consolidated financial position, results of operations and
cash flows.
Enogex
depends on two customers for a significant portion of its firm intrastate
transportation and storage services. The loss of, or reduction in volumes from,
either of these customers could result in a decline in Enogex’s transportation
and storage services and its consolidated financial position, results of
operations or cash flows.
Enogex
provides firm intrastate transportation and storage services to several
customers on its system. Enogex’s major customers are OG&E and PSO, which is
the second largest electric utility in Oklahoma and serves the Tulsa market. As
part of the no-notice load following contract with OG&E, Enogex provides
natural gas storage services for OG&E. Enogex provides gas transmission
delivery services to all of PSO’s natural gas-fired electric generation
facilities in Oklahoma under a firm intrastate transportation contract. In 2009,
2008 and 2007, revenues from Enogex’s firm intrastate transportation and storage
contracts were approximately $116.8 million, $104.4 million and $103.9 million,
respectively, of which approximately $47.5 million, $47.5 million and $47.4
million, respectively, was attributed to OG&E and approximately $15.3
million, $15.3 million and $13.3 million, respectively, was attributed to PSO.
Enogex’s current contract with PSO expires January 1, 2013, unless
extended. The stated term of Enogex’s current contract with OG&E
expired April 30, 2009, but the contract will remain in effect from year to year
thereafter unless either party provides written notice of termination to the
other party at least 180 days prior to the commencement of the next succeeding
annual period. Because neither party provided notice of termination
180 days prior to May 1, 2010, the contract will remain in effect at least
through April 30, 2011. The loss of all or even a portion of the
intrastate transportation and storage services for either of these customers,
the failure to extend or replace these contracts or the extension or replacement
of these contracts on less favorable terms, as a result of competition or
otherwise, could have a material adverse effect on Enogex’s consolidated
financial position, results of operations and cash flows.
If
third-party pipelines and other facilities interconnected to Enogex’s gathering,
processing or transportation facilities become partially or fully unavailable,
Enogex’s revenues and cash flows could be adversely affected.
Enogex
depends upon third-party natural gas pipelines to deliver gas to, and take gas
from, its transportation system. Enogex also depends on third-party facilities
to transport and fractionate NGLs that it delivers to the third party at the
tailgates of its processing plants. Fractionation is the separation of the
heterogeneous mixture of extracted NGLs into individual components for end-use
sale. Since Enogex does not own or operate any of these third-party pipelines or
other facilities, their continuing operation is not within Enogex’s control. If
any of these third-party pipelines or other facilities become partially or fully
unavailable, Enogex’s revenues and cash flows could be adversely
affected.
Enogex’s
industry is highly competitive, and increased competitive pressure could
adversely affect its consolidated financial position, results of operations or
cash flows.
Enogex
competes with similar enterprises in its respective areas of operation. Some of
these competitors are large oil, natural gas and petrochemical companies that
have greater financial resources and access to supplies of natural gas and NGLs
than Enogex. Some of these competitors may expand or construct gathering,
processing, transportation and storage systems that would create additional
competition for the services Enogex provides to its customers. In addition,
Enogex’s customers who are significant producers of natural gas may develop
their own gathering, processing, transportation and storage systems in lieu of
using Enogex’s. Enogex’s ability to renew or replace existing contracts with its
customers at rates sufficient to maintain current revenues and cash flows could
be adversely affected by the activities of its competitors and customers. All of
these competitive pressures could have a material adverse effect on Enogex’s
consolidated financial position, results of operations and cash
flows.
Gathering,
processing, transporting and storing natural gas involves many hazards and
operational risks, some of which may not be fully covered by insurance. If a
significant accident or event occurs that is not fully insured, Enogex’s
operations and financial results could be adversely affected.
Gathering,
processing, transporting and storing natural gas involves many hazards and
operational risks, including:
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damage
to pipelines and plants, related equipment and surrounding properties
caused by tornadoes, floods, earthquakes, fires and other natural
disasters and acts of terrorism;
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inadvertent
damage from third parties, including construction, farm and utility
equipment;
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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;
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These and
other risks could result in substantial losses due to personal injury and loss
of life, severe damage to and destruction of property and equipment and
pollution or other environmental damage and may result in curtailment or
suspension of Enogex’s related operations. Enogex’s insurance is currently
provided under the Company’s insurance
programs.
Enogex is not fully insured against all risks inherent to its business. Enogex
is not insured against all environmental accidents that might occur, which may
include toxic tort claims. In addition, Enogex may not be able to maintain or
obtain insurance of the type and amount desired at reasonable rates. Moreover,
in some instances, significant claims by the Company may limit or eliminate the
amount of insurance proceeds available to Enogex. As a result of market
conditions, premiums and deductibles for certain of the Company’s insurance
policies have increased substantially, and could escalate further. In
some instances, insurance could become unavailable or available only for reduced
amounts of coverage. If a significant accident or event occurs that is not fully
insured, it could adversely affect Enogex’s operations and financial
results.
Market
performance, increased retirements, changes in retirement plan regulations and
increasing costs associated with our defined benefit retirement plans, health
care plans and other employee-related benefits may adversely affect our results
of operations, consolidated financial position or liquidity.
We have a
qualified defined benefit retirement plan (“Pension Plan”) that covers
substantially all of our employees hired before December 1, 2009. In
October 2009, our Pension Plan and our qualified defined contribution retirement
plan (“401(k) Plan”) were amended, effective December 31, 2009, to offer a
one-time irrevocable election for eligible employees, depending on their hire
date, to select a future retirement benefit combination from our Pension Plan
and our 401(k) Plan. Also, effective December 1, 2009, our
Pension Plan is no longer being offered to future employees of the
Company. We also have defined benefit postretirement plans that cover
substantially all of our employees. Assumptions related to future
costs, returns on investments, interest rates and other actuarial assumptions
with respect to the defined benefit retirement and postretirement plans
have a significant impact on our earnings and funding
requirements. Based on our assumptions at December 31, 2009, we
expect to continue to make future contributions to maintain required funding
levels. It is our practice to also make voluntary contributions to
maintain more prudent funding levels than minimally required. These
amounts are estimates and may change based on actual stock market performance,
changes in interest rates and any changes in governmental
regulations.
On August
17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension
Protection Act”) into law. The Pension Protection Act makes changes
to important aspects of qualified retirement plans. Many of the
changes enacted as part of the Pension Protection Act were required to be
implemented as of the first plan year beginning in 2008. The Company has
implemented all of the required changes as part of the Pension Protection Act as
discussed in Note 11 of Notes to Consolidated Financial Statements.
All
employees hired prior to February 1, 2000 participate in defined benefit
postretirement plans. If these employees retire when they become
eligible for retirement over the next several years, or if our plan experiences
adverse market returns on its investments, or if interest rates materially fall,
our pension expense and contributions to the plans could rise substantially over
historical levels. The timing and number of employees retiring and selecting the
lump-sum payment option could result in pension settlement charges that could
materially affect our results of operations if we are unable to recover these
costs through our electric rates. In addition, assumptions related to
future costs, returns on investments, interest rates and other actuarial
assumptions, including projected retirements, have a significant impact on our
results of operations and consolidated financial position. Those
factors are outside of our control.
In
addition to the costs of our retirement plans, the costs of providing health
care benefits to our employees and retirees have increased substantially in
recent years. We believe that our employee benefit costs, including
costs related to health care plans for our employees and former employees, will
continue to rise. The increasing costs and funding requirements with
our defined benefit retirement plan, health care plans and other employee
benefits may adversely affect our results of operations, consolidated financial
position, or liquidity.
We
face certain human resource risks associated with the availability of trained
and qualified labor to meet our future staffing requirements.
Workforce
demographic issues challenge employers nationwide and are of particular concern
to the electric utility and natural gas pipeline industry. The median age of
utility and natural gas pipeline workers is significantly higher than the
national average. Over the next three years, approximately 30 percent
of our current employees will be eligible to retire with full pension
benefits. Failure to hire and adequately train replacement employees,
including the transfer of significant internal historical knowledge and
expertise to the new employees, may adversely affect our ability to manage and
operate our business.
We
are a holding company with our primary assets being investments in our
subsidiaries.
We are a
holding company and thus our investments in our subsidiaries are our primary
assets. Substantially all of our operations are conducted by our
subsidiaries. Consequently, our operating cash flow and our ability
to pay our dividends and service our indebtedness depends upon the operating
cash flow of our subsidiaries and the payment of funds by them to us in the form
of dividends. At December 31, 2009, the Company and its
subsidiaries had outstanding indebtedness and other liabilities of approximately
$5.2 billion. Our subsidiaries are separate legal entities that have
no obligation to pay any amounts due on our indebtedness or to make any funds
available for that purpose, whether by dividends or otherwise. In addition, each
subsidiary’s ability to pay dividends to us depends on any statutory and
contractual restrictions that may be applicable to such subsidiary, which may
include requirements to maintain minimum levels of working capital and other
assets. Claims of creditors, including general creditors, of our
subsidiaries on the assets of these subsidiaries will have priority over our
claims generally (except to the extent that we may be a creditor of the
subsidiaries and our claims are recognized) and claims by our
shareowners.
In
addition, as discussed above, OG&E is regulated by state utility commissions
in Oklahoma and Arkansas which generally possess broad powers to ensure that the
needs of the utility customers are being met. To the extent that the
state commissions attempt to impose restrictions on the ability of OG&E to
pay dividends to us, it could adversely affect our ability to continue to pay
dividends.
Certain
provisions in our charter documents and rights plan have anti-takeover
effects.
Certain
provisions of our certificate of incorporation and bylaws, as well as the
Oklahoma corporations statute, may have the effect of delaying, deferring or
preventing a change in control of the Company. Such provisions, including those
regulating the nomination of directors, limiting who may call special
stockholders’ meetings and eliminating stockholder action by written consent,
together with the possible issuance of preferred stock of the Company without
stockholder approval, may make it more difficult for other persons, without the
approval of our board of directors, to make a tender offer or otherwise acquire
substantial amounts of our common stock or to launch other takeover attempts
that a stockholder might consider to be in such stockholder’s best interest.
Additionally, our rights plan may also delay, defer or prevent a change of
control of the Company. Under the rights plan, each outstanding share of common
stock has one half of a right attached that trades with the common stock. Absent
prior action by our board of directors to redeem the rights or amend the rights
plan, upon the consummation of certain acquisition transactions, the rights
would entitle the holder thereof (other than the acquiror) to purchase shares of
common stock at a discounted price in a manner designed to result in substantial
dilution to the acquiror. These provisions could limit the price that investors
might be willing to pay in the future for shares of our common stock, discourage
third party bidders from bidding for us and could significantly impede the
ability of the holders of our common stock to change our
management.
We
and our subsidiaries may be able to incur substantially more indebtedness, which
may increase the risks created by our indebtedness.
The terms
of the indentures governing our debt securities do not fully prohibit us or our
subsidiaries from incurring additional indebtedness. If we or our subsidiaries
are in compliance with the financial covenants set forth in our revolving credit
agreements and the indentures governing our debt securities, we and our
subsidiaries may be able to incur substantial additional indebtedness. If we or
any of our subsidiaries incur additional indebtedness, the related risks that we
and they now face may intensify.
Any
reductions in our credit ratings could increase our financing costs and the cost
of maintaining certain contractual relationships or limit our ability to obtain
financing on favorable terms.
We cannot
assure that any of our current ratings or the ratings of our subsidiaries’ will
remain in effect for any given period of time or that a rating will not be
lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances so warrant. Our ability to access the commercial paper
market could be adversely impacted by a credit ratings downgrade or major market
disruption as experienced with the market turmoil in late 2008 and early
2009. Pricing grids associated with our credit facilities could cause
annual fees and borrowing rates to increase if an adverse ratings impact occurs.
The impact of any future downgrade would result in an increase in the cost of
short-term borrowings but would not result in any defaults or accelerations as a
result of the rating changes. Any future downgrade would also lead to
higher long-term borrowing costs and, if below investment grade, would require
us to post cash collateral or letters of
credit.
Our
debt levels may limit our flexibility in obtaining additional financing and in
pursuing other business opportunities.
We have
revolving credit agreements for working capital, capital expenditures, including
acquisitions, and other corporate purposes. The levels of our debt
could have important consequences, including the following:
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.
|
We
are exposed to the credit risk of our key customers and counterparties, and any
material nonpayment or nonperformance by our key customers and counterparties
could adversely affect our consolidated financial position, results of
operations and cash flows.
We are
exposed to credit risks in our generation, retail distribution, pipeline and
energy trading operations. Credit risk includes the risk that
customers and counterparties that owe us money or energy will breach their
obligations. If such parties to these arrangements fail to perform,
we may be forced to enter into alternative arrangements. In that
event, our financial results could be adversely affected, and we could incur
losses.
Item 1B. Unresolved Staff
Comments.
None.
OG&E
OG&E
owns and operates an interconnected electric generation, transmission and
distribution system, located in Oklahoma and western Arkansas, which included 11
generating stations with an aggregate capability of approximately 6,641 MWs at
December 31, 2009. The following tables set forth information with
respect to OG&E’s electric generating facilities, all of which are located
in Oklahoma.
|
|
|
|
|
|
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.
|
At
December 31, 2009, OG&E’s transmission system included: (i) 48 substations
with a total capacity of approximately 9.9 million kilo Volt-Amps (“kVA”) and
approximately 4,064 structure miles of lines in Oklahoma and (ii) seven
substations with a total capacity of approximately 2.5 million kVA and
approximately 271 structure miles of lines in Arkansas. OG&E’s
distribution system included: (i) 348 substations with a total capacity of
approximately 8.9 million kVA, 26,316 structure miles of overhead lines, 1,729
miles of underground conduit and 8,806 miles of underground conductors in
Oklahoma and (ii) 38 substations with a total capacity of approximately 1.1
million kVA, 2,239 structure miles of overhead lines, 187 miles of underground
conduit and 567 miles of underground conductors in Arkansas.
OG&E
owns 140,133 square feet of office space at its executive offices at 321 North
Harvey, Oklahoma City, Oklahoma 73101. In addition to its executive
offices, OG&E owns numerous facilities throughout its service territory that
support its operations. These facilities include, but are not limited
to, district offices, fleet and equipment service facilities, operation support
and other properties.
Enogex
Enogex’s
real property falls into two categories: (i) parcels that it owns in fee and
(ii) parcels in which Enogex’s interest derives from leases, easements,
rights-of-way, permits or licenses from landowners or governmental authorities
permitting the use of such land for its operations. Certain of Enogex’s
processing plants and related facilities are located on land Enogex owns in fee
title, and Enogex believes that it has satisfactory title to these lands. The
remainder of the land on which Enogex’s plants and related facilities are
located is held by Enogex pursuant to ground leases between Enogex, as lessee,
and the fee owner of the lands, as lessors. Enogex, or its predecessors, have
leased these lands for many years without any material challenge known to us or
Enogex relating to the title to the land upon which the assets are located, and
Enogex believes that it has satisfactory leasehold estates to such lands. Enogex
has no knowledge of any challenge to the underlying fee title of any material
lease, easement, right-of-way, permit or license held by Enogex or to its title
to any material lease, easement, right-of-way, permit or lease, and Enogex
believes that it has satisfactory title to all of its material leases,
easements, rights-of-way, permits and licenses.
Record
title to some of Enogex’s assets may reflect names of prior owners until Enogex
has made the appropriate filings in the jurisdictions in which such assets are
located. Title to some of Enogex’s assets may be subject to encumbrances. We
believe that none of such encumbrances should materially detract from the value
of Enogex’s properties or our interest in those properties or should materially
interfere with Enogex’s use of them in the operation of its business.
Substantially all of Enogex’s pipelines are constructed on rights-of-way granted
by the apparent owners of record of the properties. Lands over which pipeline
rights-of-way have been obtained may be subject to prior liens that have not
been subordinated to the rights-of-way grants.
At
December 31, 2009, Enogex and its subsidiaries owned: (i)
approximately 5,846 miles of intrastate natural gas gathering pipelines in
Oklahoma and Texas, (ii) approximately 2,181 miles of intrastate natural gas
transportation pipelines in Oklahoma and Texas, (iii) two underground natural
gas storage facilities in Oklahoma operating at a working gas level of
approximately 24 Bcf with approximately 650 MMcf/d of maximum withdrawal
capacity and approximately 650 MMcf/d of injection capacity and (iv) eight
operating natural gas processing plants, with a total inlet capacity of
approximately 943 MMcf/d, a 50 percent interest in the Atoka natural gas
processing plant with an inlet capacity of approximately 20 MMcf/d and two idle
natural gas processing plants, all located in Oklahoma. The following
table sets forth information with respect to Enogex’s active natural gas
processing plants:
|
|
|
|
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.
|
Enogex
occupies 116,184 square feet of office space at its executive offices at 515
Central Park Drive, Suite 110, Oklahoma City, Oklahoma 73105 under a lease that
expires March 31, 2012. Although Enogex may require additional office
space as its business expands, Enogex believes that its existing facilities are
adequate to meet its needs for the immediate future. In addition to
its executive offices, Enogex owns numerous facilities throughout its service
territory that support its operations. These facilities include, but
are not limited to, district offices, fleet and equipment service facilities,
compressor station facilities, operation support and other
properties.
During
the three years ended December 31, 2009, the Company’s gross property, plant and
equipment (excluding construction work in progress) additions were approximately
$2.5 billion and gross retirements were approximately $157.5
million. These additions were provided by cash generated from
operations, short-term borrowings (through a combination of bank borrowings and
commercial paper), long-term borrowings and permanent financings. The
additions during this three-year period amounted to approximately 29.3 percent
of gross property, plant and equipment (excluding construction work in progress)
at December 31, 2009.
Item 3. Legal
Proceedings.
In the
normal course of business, the Company is confronted with issues or events that
may result in a contingent liability. These generally relate to
lawsuits, claims made by third parties, environmental actions or the action of
various regulatory agencies. Management consults with legal counsel
and other appropriate experts to assess the claim. If in management’s
opinion, the Company has incurred a probable loss as set forth by accounting
principles generally accepted in the United States, an estimate is made of the
loss and the appropriate accounting entries are reflected in the Company’s
Consolidated Financial Statements. Except as set forth below and in Notes 13 and
14 of Notes to Consolidated Financial Statements, management, after consultation
with legal counsel, does not currently anticipate that liabilities arising out
of these pending or threatened lawsuits, claims and contingencies will have a
material adverse effect on the Company’s consolidated financial position,
results of operations or cash flows.
1. United States of America ex rel.,
Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and
OG&E. (U.S. District Court for the Western District of
Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel.,
Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the
Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the
Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999,
the Company was served with the plaintiff’s complaint, which was a qui tam
action under the False Claims Act. Plaintiff Jack J. Grynberg,
as individual relator on behalf of the Federal government,
alleged: (a) each of the named defendants had improperly or
intentionally mismeasured gas (both volume and Btu content) purchased from
Federal and Indian lands which resulted in the under reporting and underpayment
of gas royalties owed to the Federal government; (b) certain provisions
generally found in gas purchase contracts were improper; (c) transactions
by affiliated companies were not arms-length; (d) excess processing cost
deduction; and (e) failure to account for production separated out as a
result of gas processing. Grynberg sought the following
damages: (a) additional royalties which he claimed should have
been paid to the Federal government, some percentage of which Grynberg, as
relator, may be entitled to recover; (b) treble damages; (c) civil
penalties; (d) an order requiring defendants to measure the way Grynberg
contends is the better way to do so; and (e) interest, costs and attorneys’
fees. Various appeals and hearings were held in this matter from 2006
to late 2009. In October 2009, this matter concluded with the
dismissal of all complaints against all Company parties. The Company
now considers this case closed and, as a result, during the third quarter of
2009, the Company reversed a reserve of approximately $1.5 million that was
originally established with the 1999 acquisition of Transok.
2. Will Price, et al. v. El Paso
Natural Gas Co., et al. (Price I). On September 24, 1999,
various subsidiaries of the Company were served with a class action petition
filed in the District Court of Stevens County, Kansas by Quinque Operating
Company and other named plaintiffs alleging the mismeasurement of natural gas on
non-Federal lands. On April 10, 2003, the court entered an order
denying class certification. On May 12, 2003, the plaintiffs (now
Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark
Foundation, on behalf of themselves and other royalty interest owners) filed a
motion seeking to file an amended class action petition, and the court granted
the motion on July 28, 2003. In its amended petition (the “Fourth
Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two
of the Company’s other subsidiary entities remained as
defendants. The plaintiffs’ Fourth Amended Petition seeks class
certification and alleges that approximately 60 defendants, including two of the
Company’s subsidiary entities, have improperly measured the volume of natural
gas. The Fourth Amended Petition asserts theories of civil
conspiracy, aiding and abetting, accounting and unjust enrichment. In
their briefing on class certification, the plaintiffs seek to also allege a
claim for conversion. The plaintiffs seek unspecified actual damages,
attorneys’ fees, costs and pre-judgment and post-judgment
interest. The plaintiffs also reserved the right to seek punitive
damages.
Discovery
was conducted on the class certification issues, and the parties fully briefed
these same issues. A hearing on class certification issues was held
April 1, 2005. In May 2006, the court heard oral argument on a motion
to intervene
filed by
Colorado Consumers Legal Foundation, which is claiming entitlement to
participate in the putative class action. The court has not yet ruled
on the motion to intervene.
The class
certification issues were briefed and argued by the parties in 2005 and
proposed findings of facts and conclusions of law on class certification were
filed in 2007. On September 18, 2009, the court entered its order
denying class certification. On October 2, 2009, the plaintiffs filed
for a rehearing of the court’s denial of class certification. On February 10,
2010 the court heard arguments on the rehearing. No ruling on this
motion has been made.
The
Company intends to vigorously defend this action. At this time, the
Company is unable to provide an evaluation of the likelihood of an unfavorable
outcome and an estimate of the amount or range of potential loss to the
Company.
3. Will Price, et al. v. El Paso
Natural Gas Co., et al. (Price II). On May 12, 2003, the
plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed
a new class action petition in the District Court of Stevens County, Kansas
naming the same defendants and asserting substantially identical legal and/or
equitable theories as in the Fourth Amended Petition of the Price I
case. OG&E and Enogex Inc. were not named in this case, but two
subsidiary entities of the Company were named in this case. The
plaintiffs allege that the defendants mismeasured the Btu content of natural gas
obtained from or measured for the plaintiffs. In their briefing on
class certification, the plaintiffs seek to also allege a claim for
conversion. The plaintiffs seek unspecified actual damages,
attorneys’ fees, costs and pre-judgment and post-judgment
interest. The plaintiffs also reserved the right to seek punitive
damages.
Discovery
was conducted on the class certification issues, and the parties fully briefed
these same issues. A hearing on class certification issues was held
April 1, 2005. In May 2006, the court heard oral argument on a motion
to intervene filed by Colorado Consumers Legal Foundation, which is claiming
entitlement to participate in the putative class action. The court
has not yet ruled on the motion to intervene.
The class
certification issues were briefed and argued by the parties in 2005 and
proposed findings of facts and conclusions of law on class certification were
filed in 2007. On September 18, 2009, the court entered its order
denying class certification. On October 2, 2009, the plaintiffs filed
for a rehearing of the court’s denial of class certification. On February 10,
2010 the court heard arguments on the rehearing. No ruling on this
motion has been made.
The
Company intends to vigorously defend this action. At this time, the
Company is unable to provide an evaluation of the likelihood of an unfavorable
outcome and an estimate of the amount or range of potential loss to the
Company.
4. Oklahoma Royalty
Lawsuit. On July 22, 2005, Enogex along with certain other
unaffiliated co-defendants was served with a purported class action which had
been filed on February 7, 2005 by Farris Buser and other named plaintiffs in the
District Court of Canadian County, Oklahoma. The plaintiffs own
royalty interests in certain oil and gas producing properties and allege they
have been under-compensated by the named defendants, including Enogex and its
subsidiaries, relating to the sale of liquid hydrocarbons recovered during the
transportation of natural gas from the plaintiffs’ wells. The
plaintiffs assert breach of contract, implied covenants, obligation, fiduciary
duty, unjust enrichment, conspiracy and fraud causes of action and claim actual
damages in excess of $10,000, plus attorneys’ fees and costs, and punitive
damages in excess of $10,000. Enogex and its subsidiaries filed a
motion to dismiss which was granted on November 18, 2005, subject to the
plaintiffs’ right to conduct discovery and the possible re-filing of their
allegations in the petition against the Enogex companies. On
September 19, 2005, the co-defendants, BP America, Inc. and BP America
Production Company (collectively, “BP”), filed a cross claim against Products
seeking indemnification and/or contribution from Products based upon the 1997
sale of a third-party interest in one of Products natural gas processing
plants. On May 17, 2006, the plaintiffs filed an amended petition
against Enogex and its subsidiaries. Enogex and its subsidiaries
filed a motion to dismiss the amended petition on August 2, 2006. The
hearing on the dismissal motion was held on November 20, 2006 and the court
denied Enogex’s motion. Enogex companies filed an answer to the
amended petition and BP’s cross claim on January 16, 2007. Based on
Enogex’s investigation to date, the Company believes these claims and cross
claims in this lawsuit are without merit and intends to continue
vigorously defending this case.
5. Hull v. Enogex LLC. On
November 14, 2008, a natural gas gathering pipeline owned by Enogex
ruptured in Grady County, near Alex, Oklahoma, resulting in a fire that caused
injuries to one resident and destroyed three residential
structures. The cause of the rupture is not known and an
investigation of the incident is ongoing. The damaged pipeline
hasbeen repaired and the pipeline is back in service. After the
incident, Enogex coordinated and assisted the affected
residents. Enogex resolved matters with two of the residents and
Enogex continues to seek resolution with a remaining resident. This
resident filed a legal action in May 2009 in the District Court of Cleveland
County, Oklahoma, against OGE Energy and Enogex seeking to recover actual and
punitive damages in excess of $10,000. The parties participated in a
mediation of the
pending
action in August but were unable to resolve the action. Enogex has
requested information regarding property and non-economic damage from the
plaintiffs but has not yet received a response. Enogex intends to
make full payment for actual medical expenses and property damages in this
case. While the Company cannot predict the outcome of this lawsuit at this
time, the Company intends to vigorously defend any
demand for punitive damages or excessive compensatory damages in this
case and believes that its ultimate resolution will not be material to the
Company’s consolidated financial position or results of operations.
6. Franchise Fee Lawsuit.
On June 19, 2006, two OG&E customers brought a putative class action,
on behalf of all similarly situated customers, in the District Court of Creek
County, Oklahoma, challenging certain charges on OG&E’s electric
bills. The plaintiffs claim that OG&E improperly charged sales tax
based on franchise fee charges paid by its customers. The plaintiffs also
challenge certain franchise fee charges, contending that such fees are more than
is allowed under Oklahoma law. OG&E’s motion for summary judgment was
denied by the trial judge. OG&E filed a writ of prohibition at the
Oklahoma Supreme Court asking the court to direct the trial court to dismiss the
class action suit. In January 2007, the Oklahoma Supreme Court “arrested”
the District Court action until, and if, the propriety of the complaint of
billing practices is determined by the OCC. In September 2008,
the plaintiffs filed an application with the OCC asking the OCC to modify its
order which authorizes OG&E to collect the challenged franchise fee
charges. On March 10, 2009, the Oklahoma Attorney General, OG&E,
OG&E Shareholders Association and the Staff of the Public Utility Division
of the OCC all filed briefs arguing that the application should be
dismissed. On December 9, 2009 the OCC issued an order dismissing the
plaintiffs’ request for a modification of the OCC order which authorizes
OG&E to collect and remit sales tax on franchise fee charges. In its
December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not
address the question of whether OG&E’s collection and remittance of such
sales tax should be discontinued prospectively. On December 21, 2009, the
plaintiffs filed a motion at the Oklahoma Supreme Court asking the court to deny
OG&E’s writ of prohibition and to remand the cause to the District Court. On
December 29, 2009, the Oklahoma Supreme Court declared the plaintiffs’ motion
moot. On January 27, 2010, the OCC Staff filed a motion asking the OCC to
dismiss the cause and close the cause at the OCC. If the OCC Staff’s
motion is granted, the plaintiffs would be required to file a new cause in order
to ask for prospective relief. In its motion, the OCC Staff stated
that the plaintiff’s counsel advised the OCC Staff counsel that the plaintiffs
have no desire to seek a determination regarding prospective relief from the
OCC. It is unknown whether the plaintiffs will attempt to continue
the District Court action. OG&E believes that the lawsuit is
without merit.
7. Oxley
Litigation. OG&E has been sued by John C. Oxley D/B/A
Oxley Petroleum et al. in the District Court of Haskell County,
Oklahoma. This case has been pending for more than 11 years.
The plaintiffs alleged that OG&E breached the terms of contracts
covering several wells by failing to purchase gas from the plaintiffs in
amounts set forth in the contracts. The plaintiffs’ most recent Statement
of Claim describes approximately $2.7 million in take-or-pay
damages (including interest) and approximately $36 million
in contract repudiation damages (including interest), subject to the
limitation described below. In 2001, OG&E agreed to provide the plaintiffs
with approximately $5.8 million of consideration and the parties agreed to
arbitrate the dispute. Consequently, OG&E will only be liable for the
amount, if any, of an arbitration award in excess of $5.8 million. The
arbitration hearing was completed recently and the next step is briefing by the
parties. While the Company cannot predict the precise outcome of
the arbitration, based on the information known at this
time, OG&E believes that this lawsuit will not have a
material adverse effect on the Company’s consolidated financial position or
results of operations.
Item 4. Submission of Matters to a
Vote of Security Holders.
Executive Officers
of the Registrant.
The
following persons were Executive Officers of the Registrant as of February 18,
2010:
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.
|
No family
relationship exists between any of the Executive Officers of the
Registrant. Messrs. Delaney, Harris, Trauschke, Huneryager, Johnston,
Merrill, Nuttall, Renfrow, Myers, Forbes and Peace and Ms. Horn and Ms.
McQuistion are also officers of OG&E. Each officer is to hold
office until the Board of Directors meeting following the next Annual Meeting of
Shareowners, currently scheduled for May 20, 2010.
The
business experience of each of the Executive Officers of the Registrant for the
past five years is as follows:
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)
|
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
|
Item 5. Market for Registrant’s
Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.
The
Company’s Common Stock is listed for trading on the New York Stock Exchange
under the ticker symbol “OGE.” Quotes may be obtained in daily
newspapers where the common stock is listed as “OGE Engy” in the New York Stock
Exchange listing table. The following table gives information with
respect to price ranges, as reported in The Wall
Street Journal as New York Stock Exchange Composite Transactions, and
dividends paid for the periods shown.
|
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
|
|
The
number of record holders of the Company’s Common Stock at December 31, 2009, was
21,971. The book value of the Company’s Common Stock at December 31,
2009, was $21.06.
Dividend
Restrictions
Before
the Company can pay any dividends on its common stock, the holders of any of its
preferred stock that may be outstanding are entitled to receive their dividends
at the respective rates as may be provided for the shares of their
series. Currently, there are no shares of preferred stock of the
Company outstanding. Because the Company is a holding company and
conducts all of its operations through its subsidiaries, the Company’s cash flow
and ability to pay dividends will be dependent on the earnings and cash flows of
its subsidiaries and the distribution or other payment of those earnings to the
Company in the form of dividends or distributions, or in the form of repayments
of loans or advances to it. The Company expects to derive principally
all of the funds required by it to enable it to pay dividends on its common
stock from dividends paid by OG&E, on OG&E’s common stock, and from
distributions paid by Enogex, on Enogex’s limited liability company
interests. The Company’s ability to receive dividends on OG&E’s
common stock is subject to the prior rights of the holders of any OG&E
preferred stock that may be outstanding and the covenants of OG&E’s
certificate of incorporation and its debt instruments limiting the ability of
OG&E to pay dividends. The Company’s ability to receive
distributions on Enogex’s limited liability company interests is subject to the
prior rights of existing and future holders of such limited liability company
interests that may be outstanding and the covenants of Enogex’s debt instruments
(including its revolving credit agreement) limiting the ability of Enogex to pay
distributions.
Under
OG&E’s certificate of incorporation, if any shares of its preferred stock
are outstanding, dividends (other than dividends payable in common stock),
distributions or acquisitions of OG&E common stock:
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.
|
OG&E’s
certificate of incorporation further provides that no dividend may be declared
or paid on the OG&E common stock until all amounts required to be paid or
set aside for any sinking fund for the redemption or purchase of OG&E
cumulative preferred stock, par value $25 per share, have been paid or set
aside. Currently, no shares of OG&E preferred stock are outstanding and no
portion of the retained earnings of OG&E is presently restricted by these
provisions.
Under
Enogex’s current revolving credit agreement, Enogex generally may not make
distributions if an event of default exists and otherwise may make monthly and
quarterly distributions in amounts not to exceed the amount by which Enogex’s
cash on hand exceeds its current and anticipated needs, including, without
limitation, for operating expenses, debt service, acquisitions and a reasonable
contingency reserve.
Issuer
Purchases of Equity Securities
The
shares indicated below represent shares of Company common stock purchased on the
open market by the trustee for the Company’s 401(k) Plan and reflect shares
purchased with employee contributions as well as the portion attributable to the
Company’s matching contributions.
|
|
|
|
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
|
|
$
|
|