OGE 2011 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
S ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
OR
£ 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)
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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:
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Title of each class | Name of each exchange on which registered |
Common Stock | 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.
R Yes £ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. £ Yes R No
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. R Yes £ No
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). R Yes £ 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. R
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 the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer R | Accelerated filer £ |
Non-accelerated filer £ (Do not check if a smaller reporting company) | Smaller reporting company £ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). £ Yes R No
At June 30, 2011, 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 $4,904,111,913 based on the number of shares held by non-affiliates (97,458,504) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $50.32.
At January 31, 2012, there were 98,073,157 shares of common stock, par value $0.01 per share, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement for the Company's 2012 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, 2011
TABLE OF CONTENTS
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations that are found throughout this Form 10-K.
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Abbreviation | Definition |
401(k) Plan | Qualified defined contribution retirement plan |
APSC | Arkansas Public Service Commission |
ArcLight group | Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively |
Atoka | Atoka Midstream LLC joint venture |
BART | Best Available Retrofit Technology |
Code | Internal Revenue Code of 1986 |
Company | OGE Energy, collectively with its subsidiaries |
Cordillera | Cordillera Energy Partners III, LLC |
Crossroads | OG&E's Crossroads wind farm in Dewey County, Oklahoma |
Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act |
Dry Scrubbers | Dry flue gas desulfurization units with Spray Dryer Absorber |
Enogex | OGE Holdings, collectively with its subsidiaries |
Enogex LLC | Enogex LLC, collectively with its subsidiaries |
Enogex Holdings | Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings |
EPA | U.S. Environmental Protection Agency |
Federal Clean Water Act | Federal Water Pollution Control Act of 1972, as amended |
FERC | Federal Energy Regulatory Commission |
GAAP | Accounting principles generally accepted in the United States |
MEP | Midcontinent Express Pipeline, LLC |
MMBtu | Million British thermal unit |
MMcf/d | Million cubic feet per day |
MW | Megawatt |
MWH | Megawatt-hour |
NAAQS | National Ambient Air Quality Standards |
NGLs | Natural gas liquids |
NOX | Nitrogen oxide |
NYMEX | New York Mercantile Exchange |
OCC | Oklahoma Corporation Commission |
ODEQ | Oklahoma Department of Environmental Quality |
OER | OGE Energy Resources LLC, wholly-owned subsidiary of Enogex LLC |
Off-system sales | Sales to other utilities and power marketers |
OG&E | Oklahoma Gas and Electric Company |
OGE Holdings | OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings |
OSHA | Federal Occupational Safety and Health Act of 1970 |
Oxbow | Oxbow Midstream, LLC |
Pension Plan | Qualified defined benefit retirement plan |
PHMSA | U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration |
PRM | Price risk management |
Products | Enogex Products LLC, wholly-owned subsidiary of Enogex LLC |
PSO | Public Service Company of Oklahoma |
QF | Qualified cogeneration facilities |
QF contracts | Contracts with QFs and small power production producers |
SIP | State implementation plan |
SO2 | Sulfur dioxide |
SPP | Southwest Power Pool |
System sales | Sales to OG&E's customers |
TBtu/d | Trillion British thermal units per day |
Windspeed | OG&E's transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma |
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 from those expressed in forward-looking statements. 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:
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• | general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
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• | the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms; |
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• | prices and availability of electricity, coal, natural gas and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee; |
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• | business conditions in the energy and natural gas midstream industries; |
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• | competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; |
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• | availability and prices of raw materials for current and future construction projects; |
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• | Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets; |
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• | environmental laws and regulations that may impact the Company's operations; |
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• | changes in accounting standards, rules or guidelines;
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• | the discontinuance of accounting principles for certain types of rate-regulated activities;
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• | whether OG&E can successfully implement its Smart Grid program to install meters for its customers and integrate the Smart Grid meters with its customer billing and other computer information systems;
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• | the cost of protecting assets against, or damage due to, terrorism or cyber attacks;
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• | creditworthiness of suppliers, customers and other contractual parties;
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• | the higher degree of risk associated with the Company's nonregulated business compared with the Company's regulated utility business; and |
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• | other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to this Form 10-K.
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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.
PART I
Item 1. Business.
THE COMPANY
Introduction
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 15 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 OG&E and are subject to regulation by the OCC, the APSC and the 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 natural gas business in 1928 and is no longer engaged in the natural gas distribution business.
Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting, storing and marketing 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 three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. Enogex LLC is a Delaware single-member limited liability company. At December 31, 2011, the Company indirectly owns an 81.3 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC.
Company Strategy
The Company's mission 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's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses. Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders.
OG&E is focused on increased investment to preserve system reliability and meet load growth by adding and maintaining infrastructure equipment and replacing aging transmission and distribution systems. OG&E is focused on maintaining strong regulatory and legislative relationships for the long-term benefit of its customers. In an effort to encourage more efficient use of electricity, OG&E is also providing energy management solutions to its customers through the Smart Grid program that utilizes newer technology to improve operational and environmental performance and promote demand-side management programs. If these initiatives are successful, OG&E believes it may be able to defer the construction or acquisition of any incremental fossil fuel generation capacity until 2020. As the Smart Grid platform matures, OG&E anticipates providing new products and services to its customers. In addition, OG&E is also pursuing additional transmission-related opportunities within the SPP. OG&E is customer focused and strives to provide excellent customer service.
Enogex's business plan entails growing its businesses and providing attractive financial returns through efficient operations and effective commercial management of its assets, capturing growth opportunities through expansion projects, increased utilization of existing assets and through acquisitions in and around its footprint. In addition, Enogex is seeking to geographically diversify its gathering, processing and transportation businesses principally by expanding into other areas that are complementary with the Company's capabilities. Enogex expects to accomplish this diversification by undertaking organic growth projects and through acquisitions.
The Company's financial objectives include a long-term annual earnings growth rate of five to seven percent on a weather-normalized basis, maintaining a strong credit rating as well as increasing the dividend to meet the Company's dividend payout objectives. The Company's target payout ratio is to pay out 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.
ELECTRIC OPERATIONS - OG&E
General
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 268 communities and their contiguous rural and suburban areas. At December 31, 2011, two other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area covers 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 268 communities that OG&E serves, 242 are located in Oklahoma and 26 in Arkansas. OG&E derived 90 percent of its total electric operating revenues in 2011 from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand in 2011 was 7,057 MWs on August 3, 2011. OG&E's load responsibility peak demand was 6,513 MWs on August 3, 2011. As reflected in the table below and in the operating statistics that follow, there were 28.5 million MWH system sales in 2011, 27.6 million MWH system sales in 2010 and 25.9 million MWH system sales in 2009. Variations in system sales for the three years are reflected in the following table:
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Year ended December 31 | 2011 | 2011 vs. 2010 Increase | 2010 | 2010 vs. 2009 Increase | 2009 |
System sales - millions of MWHs | 28.5 | 3.3% | 27.6 | 6.6% | 25.9 |
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.
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OKLAHOMA GAS AND ELECTRIC COMPANY |
CERTAIN OPERATING STATISTICS |
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Year ended December 31 | 2011 | 2010 | 2009 |
ELECTRIC ENERGY (Millions of MWH) | | | |
Generation (exclusive of station use) | 26.7 |
| 25.6 |
| 25.0 |
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Purchased | 4.9 |
| 4.7 |
| 3.9 |
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Total generated and purchased | 31.6 |
| 30.3 |
| 28.9 |
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OG&E use, free service and losses | (2.1 | ) | (2.2 | ) | (2.0 | ) |
Electric energy sold | 29.5 |
| 28.1 |
| 26.9 |
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ELECTRIC ENERGY SOLD (Millions of MWH) | | | |
Residential | 9.9 |
| 9.6 |
| 8.7 |
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Commercial | 6.9 |
| 6.7 |
| 6.4 |
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Industrial | 3.9 |
| 3.8 |
| 3.6 |
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Oilfield | 3.2 |
| 3.1 |
| 2.9 |
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Public authorities and street light | 3.2 |
| 3.0 |
| 3.0 |
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Sales for resale | 1.4 |
| 1.4 |
| 1.3 |
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System sales | 28.5 |
| 27.6 |
| 25.9 |
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Off-system sales | 1.0 |
| 0.5 |
| 1.0 |
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Total sales | 29.5 |
| 28.1 |
| 26.9 |
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ELECTRIC OPERATING REVENUES (In millions) | | | |
Residential | $ | 943.5 |
| $ | 894.8 |
| $ | 717.9 |
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Commercial | 531.3 |
| 521.0 |
| 439.8 |
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Industrial | 216.0 |
| 212.5 |
| 172.1 |
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Oilfield | 165.1 |
| 162.8 |
| 132.6 |
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Public authorities and street light | 207.4 |
| 200.8 |
| 167.7 |
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Sales for resale | 65.3 |
| 65.8 |
| 53.6 |
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Provision for rate refund | — |
| — |
| (0.6 | ) |
System sales revenues | 2,128.6 |
| 2,057.7 |
| 1,683.1 |
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Off-system sales revenues | 36.2 |
| 21.7 |
| 31.8 |
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Other | 46.7 |
| 30.5 |
| 36.3 |
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Total operating revenues | $ | 2,211.5 |
| $ | 2,109.9 |
| $ | 1,751.2 |
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ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) | | | |
Residential | 675,806 |
| 670,309 |
| 665,344 |
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Commercial | 87,480 |
| 86,496 |
| 85,537 |
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Industrial | 2,991 |
| 3,020 |
| 3,056 |
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Oilfield | 6,451 |
| 6,418 |
| 6,437 |
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Public authorities and street light | 16,374 |
| 16,264 |
| 16,124 |
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Sales for resale | 44 |
| 51 |
| 52 |
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Total | 789,146 |
| 782,558 |
| 776,550 |
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AVERAGE RESIDENTIAL CUSTOMER SALES | | | |
Average annual revenue | $ | 1,401.84 |
| $ | 1,339.81 |
| $ | 1,083.50 |
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Average annual use (kilowatt-hour) | 14,738 |
| 14,304 |
| 13,197 |
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Average price per kilowatt-hour (cents) | $ | 9.51 |
| $ | 9.37 |
| $ | 8.21 |
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Regulation and Rates
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 U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2011, 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 OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy 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 OGE Energy 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.
Completed Regulatory Matters
OG&E Wholesale Agreement
On May 28, 2009, OG&E sent a termination notice to the Arkansas Valley Electric Cooperative that OG&E would terminate its wholesale power agreement to all points of delivery where OG&E sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011. In December 2010, OG&E and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby OG&E will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015. On January 3, 2011, OG&E submitted this agreement to the FERC for approval. The FERC approved the new wholesale power agreement on March 2, 2011 and the new contract was effective May 1, 2011.
OG&E Crossroads Wind Farm
On July 29, 2010, OG&E received an order from the OCC authorizing OG&E to recover from Oklahoma customers the cost to construct Crossroads, with the rider being implemented as the individual turbines are placed in service. The Crossroads wind farm was fully in service in January 2012. As part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for Crossroads which allowed Crossroads to interconnect at 227.5 MWs.
OG&E 2010 Arkansas Rate Case Filing
On September 28, 2010, OG&E filed a rate case with the APSC requesting an annual rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines, that have been completed since the last rate filing in August 2008, as well as increased operating costs. OG&E also sought recovery, through a rider, of the Arkansas jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. On June 17, 2011, the APSC approved a settlement agreement among all parties to the case and OG&E implemented new electric rates effective June 20, 2011. Key items of the APSC order include: (i) the recovery of and a return on significant electric system expansions and upgrades, including high-voltage transmission lines, as well as increased operating costs, totaling $8.8 million annually; (ii) authorization for OG&E to recover the actual cost of third-party transmission charges and SPP administrative fees through a rider mechanism which will remain in effect until new rates are implemented after OG&E's next general rate case (the Arkansas jurisdictional portion of the combined costs was $1.0 million in 2011); and (iii) the deferral of certain expenses associated with a customer education program in an amount not to exceed $0.3 million per year for a maximum of two years.
OG&E SPP Cost Tracker
On October 7, 2010, OG&E filed an application with the OCC seeking recovery of the Oklahoma jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. OG&E requested authorization to implement a cost tracker in order to recover from its retail customers the third-party project costs discussed above and to collect its administrative SPP cost assessment levied under Schedule 1A of the SPP open access transmission tariff, which is currently recovered in base rates. OG&E also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give OG&E the opportunity to
recover such costs that will be paid but not recovered until the cost tracker is made effective. On February 8, 2011, all parties signed a settlement agreement in this matter which would allow OG&E to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. OG&E recovered $5.1 million of incremental revenues in 2011 through the rider. Rather than including the costs of the SPP administrative fee assessment in the recovery rider, the stipulating parties agreed to allow OG&E to include the projected 2012 level of the SPP administrative fee assessment in its next Oklahoma rate case which was filed in August 2011. Pursuant to the settlement agreement in OG&E's 2011 Oklahoma general rate case filing, OG&E proposed that recovery in base rates for the costs of transmission projects it constructs and owns and that are authorized by the SPP in its regional planning processes should be limited to the Oklahoma retail jurisdictional share of the costs for such projects allocated to OG&E by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.
OG&E Fuel Adjustment Clause Review for Calendar Year 2009
On October 29, 2010, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2009 fuel adjustment clause. On December 28, 2010, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. An intervenor representing a group of OG&E's industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by OG&E to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing gas transportation and storage contract between OG&E and Enogex. OG&E filed rebuttal testimony on April 4, 2011 in opposition to the claims of the intervenor. On August 11, 2011, all parties to this case signed a settlement agreement in this matter, stating that (i) OG&E was prudent in its operations during 2009; (ii) a third party expert should be hired to evaluate OG&E's future gas transportation and storage needs and that OG&E should file a plan for meeting its future gas transportation and storage needs by mid-2012; and (iii) with respect to the existing gas transportation and storage contract with Enogex, OG&E will return $8.4 million to its customers in settlement for all periods under the contract through April 30, 2013. In August 2011, OG&E credited $4.9 million to its customers and will credit the remaining amount on a monthly basis through April 30, 2013. The OCC issued an order approving the settlement agreement on August 29, 2011.
OG&E Smart Grid Project
On December 17, 2010, OG&E filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant awarded by the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. On June 22, 2011, OG&E reached a settlement agreement with all the parties in this matter. OG&E and the other parties in this matter agreed to ask the APSC to approve the settlement agreement including the following: (i) pre-approval of system-wide deployment of smart grid technology in Arkansas and authorization for OG&E to begin recovering the prudently incurred costs of the Arkansas system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement; (ii) cost recovery through the rider would commence when all of the smart meters to be deployed in Arkansas are in service; (iii) OG&E guarantees that customers will receive certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider; and (iv) the stranded costs associated with OG&E's existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning after an order is issued in OG&E's next general rate case. OG&E currently expects to spend $14 million, net of funds from the U.S. Department of Energy grant, in capital expenditures to implement smart grid in Arkansas pursuant to the settlement agreement. On August 3, 2011, the APSC issued an order in this matter approving the settlement agreement.
OG&E FERC Transmission Rate Incentive Filing
On February 18, 2011, OG&E submitted to the FERC a request seeking limited transmission rate incentives for five transmission projects. OG&E requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five 345 kilovolt Extra High Voltage transmission projects to be constructed and owned by OG&E within the SPP's region. OG&E also requested to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond OG&E's control. On April 19, 2011, the FERC granted these incentives for the Sooner-Rose Hill, Sunnyside-Hugo and Balanced Portfolio 3E transmission projects discussed below.
OG&E Pension Tracker Modification Filing
On February 22, 2011, OG&E filed an application with the OCC requesting that OG&E's pension tracker be modified to include the difference between the level of retiree medical costs authorized in OG&E's last rate case and the current level of these expenses as a regulatory liability, effective January 1, 2011. On June 23, 2011, a settlement agreement was filed by parties in the case stating that the pension tracker should be modified as proposed by OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. On September 27, 2011, the OCC issued an
order in this matter approving the settlement agreement.
OG&E Demand and Energy Efficiency Program Filing
To build on the success of its earlier programs and further promote energy efficiency and conservation for each class of OG&E customers, on March 15, 2011, OG&E filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting. In seeking approval of these programs, OG&E also sought recovery of the program and related costs through a rider that would be added to customers' electric bills. On June 30, 2011, the APSC issued an order approving OG&E's energy efficiency plan for 2011 and approving OG&E's energy efficiency cost recovery rider for 2011. In Arkansas, OG&E's program is expected to cost $7.0 million over a three-year period and is expected to increase the average residential electric bill by $1.47 per month.
FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 applies only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which are expected to be filed during the third quarter of 2012. Order No. 1000 leaves to individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP currently has a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build various transmission projects in Oklahoma.
OGE Energy is continuing to evaluate Order No. 1000 and cannot at this time determine its precise impact on OG&E. Nevertheless, at the present time, OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.
Pending Regulatory Matters
OG&E 2011 Oklahoma Rate Case Filing
As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E is requesting a return on equity of 11.00 percent based on a common equity percentage of 53 percent. Each 0.10 percent change in the requested return on equity affects the requested rate increase by $3.0 million. In its application, OG&E seeks to recover increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous two and one-half years. On November 9, 2011, the OCC Staff recommended a $6.2 million annual rate decrease based on a return on equity of 9.81 percent and a common equity percentage of 53 percent. The staff of the Oklahoma Attorney General recommended a return on equity of 9.818 percent and a common equity percentage of 49.5 percent. The staff of the Oklahoma Attorney General
did not recommend a specific revenue requirement, but OG&E believes that adoption of the staff of the Oklahoma Attorney General's recommendations would result in a rate decrease. The Oklahoma Industrial Electric Consumers recommended a $56 million annual rate decrease based on a return on equity of 9.5 percent and a common equity percentage of 48 percent. OG&E filed rebuttal testimony on November 29, 2011 on the revenue requirement testimony filed by the parties on November 9, 2011. On November 16, 2011, the parties filed cost-of-service and rate design testimony and OG&E filed rebuttal testimony in those areas on December 2, 2011. The hearing in this matter began on December 13, 2011. OG&E expects to receive an order from the OCC in the first quarter of 2012.
OG&E Fuel Adjustment Clause Review for Calendar Year 2010
On August 19, 2011, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2010 fuel adjustment clause. On October 18, 2011, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. A procedural schedule has not yet been established in this matter.
OG&E Contract and Wind Energy Purchase Agreement Filing
On December 1, 2011, OG&E filed an application with the OCC requesting approval of a 20-year agreement that is intended to provide wind power to help meet the current and future power generation needs of Oklahoma State University. The project calls for OG&E to contract with NextEra Energy to build a 60 MW wind farm near Blackwell, Oklahoma, to support the Oklahoma State University project in which NextEra will build, own and operate the wind farm and OG&E will purchase the electric output. A procedural schedule has not yet been established in this matter. OG&E expects to receive a decision from the OCC in the first quarter of 2012.
SPP Transmission/Substation Projects
The SPP is a regional transmission organization under the jurisdiction of the FERC that 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 currently has the first obligation to build; however, the process for deciding which entity constructs and owns a project may change as a result of FERC Order. No. 1000 discussed above.
There are several studies currently under review at the SPP including a 20-year plan to address issues of regional and interregional importance. The 20-year plan suggests overlaying the SPP footprint with a 345 kilovolt 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 44 miles of a new 345 kilovolt transmission line which will originate at OG&E's existing Sooner 345 kilovolt 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. Construction of the line began in early 2011 and the line is estimated to be in service by mid-2012 at an estimated cost of $45 million for OG&E.
In January 2009, OG&E received notification from the SPP to begin construction on 50 miles of a new 345 kilovolt transmission line and substation upgrades at OG&E's Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative. The new line will extend from OG&E's Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative near Hugo, Oklahoma. The project cost is estimated at $155 million for OG&E. OG&E began preliminary line routing and acquisition of rights-of-way in June 2009. Construction began in January 2011. When construction is completed, which is expected in mid-2012, the SPP will allocate a portion of the annual revenue requirement to OG&E customers according to the regional cost allocation mechanism as provided in the SPP tariff for application to such improvements.
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 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of $160 million for OG&E, which is expected to be
in service by late 2013, (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage 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 an estimated cost of $145 million for OG&E, which is expected to be in service by mid-2014, (iii) construction of 39 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 $60 million for OG&E, which is expected to be in service by late 2012 and (iv) construction of a new substation near Anadarko which consisted of a 345/138 kilovolt transformer and substation breakers and was built in OG&E's portion of the Cimarron-Lawton East Side 345 kilovolt line at an estimated cost of $15 million for OG&E, which was placed in service in December 2011. 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 2011.
On April 27, 2010, the SPP approved, contingent upon approval by the FERC of a regional cost allocation methodology filed with the FERC by the SPP, a set of transmission projects titled "Priority Projects." The Priority Projects consist of several transmission projects, two of which have been assigned to OG&E. The 345 kilovolt projects include: (i) construction of 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at an estimated cost of $185 million for OG&E, which is expected to be in service by mid-2014 and (ii) construction of 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at an estimated cost of $150 million to OG&E, which is expected to be in service by late 2014. On June 17, 2010, the FERC approved the cost allocation filed by the SPP and notices to construct these Priority Projects were issued by the SPP on June 30, 2010. On September 27, 2010, OG&E responded to the SPP that OG&E will construct the Priority Projects discussed above beginning in June 2012. The scope of the Woodward District Extra High Voltage substation/Kansas border Priority Project was subsequently revised and the SPP Board of Directors approved this revision in October 2010. The SPP issued a revised notice to construct for this Priority Project on November 22, 2010. On February 4, 2011, OG&E responded to the SPP that OG&E will construct the revised Priority Project.
The capital expenditures related to the Sooner-Rose Hill, Sunnyside-Hugo, Balanced Portfolio 3E and Priority 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 - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities."
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, 2011 and 2010, OG&E had regulatory assets of $523.9 million and $495.3 million, respectively, and regulatory liabilities of $276.4 million and $243.9 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, which could have significant financial effects.
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 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 guaranteed flat bill option. A second tariff rate option provides a "renewable energy" resource to OG&E's Oklahoma retail customers. This renewable energy resource is a Renewable Energy Credit 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 option a possible choice in meeting the renewable energy needs of our conservation-minded customers. 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 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.
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 the actual cost of fuel. OG&E offers several alternate customer programs and rate options. The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. A second tariff rate option provides a "renewable energy" resource to OG&E's Arkansas retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. OG&E offers its commercial and industrial customers a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action. OG&E 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
In 2011, 57.9 percent of the OG&E-generated energy was produced by coal-fired units, 39.2 percent by natural gas-fired units and 2.9 percent by wind-powered units. Of OG&E's 6,790 total MW capability reflected in the table under Item 2. Properties, 3,825 MWs, or 56.3 percent, are from natural gas generation, 2,548 MWs, or 37.5 percent, are from coal generation and 417 MWs, or 6.2 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, was as follows:
|
| | | | | |
Year ended December 31 (In Kilowatt-Hour - cents) | 2011 | 2010 | 2009 | 2008 | 2007 |
Coal | 2.064 | 1.911 | 1.747 | 1.153 | 1.143 |
Natural gas | 4.328 | 4.638 | 3.696 | 8.455 | 6.872 |
Weighted average | 2.897 | 3.012 | 2.474 | 3.337 | 3.173 |
The decrease in the weighted average cost of fuel in 2011 as compared to 2010 was primarily due to lower natural gas prices and lower natural gas generation. The increase in the weighted average cost of fuel in 2010 as compared to 2009 was primarily due to higher natural gas prices and increased natural gas generation. 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. 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. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of recoverable fuel costs that is not included in the base rates is recovered 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 2,548 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E purchases coal primarily under contracts expiring in years 2012 and 2015. In 2011, OG&E purchased 7.5 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.26 percent. Based upon the average sulfur content and EPA certified emission data, OG&E's coal units have an approximate emission rate of 0.5 lbs. of SO2 per MMBtu. As discussed, in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," emission limits are expected to become more stringent.
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
OG&E has natural gas contracts for purchases from January 2012 through March 2012 that account for 26 percent of OG&E's projected 2012 natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2012 natural gas requirements will be acquired through additional requests for proposal in early to mid-2012, 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, 2011, OG&E had 2.9 million MMBtu's in natural gas storage valued at $10.7 million.
Wind
OG&E's current wind power portfolio includes: (i) the Centennial wind farm, (ii) the OU Spirit wind farm, (iii) the Crossroads wind farm, (iv) 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, (v) access to up to 150 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030 and (vi) access to up to 130 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2030.
Safety and Health Regulation
OG&E 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. 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 OG&E's operations and that this information be provided to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
NATURAL GAS MIDSTREAM OPERATIONS - ENOGEX
Overview
Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting, storing and marketing 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 three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing.
On October 5, 2010, OGE Energy entered into an investment agreement with the ArcLight group, pursuant to which the ArcLight group agreed to make an initial equity investment in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, in an amount equal to $183,150,000 in exchange for a 9.9 percent membership interest in Enogex Holdings. As a result of this transaction, the ArcLight group acquired an indirect 9.9 percent interest in Enogex LLC and OGE Energy retained an indirect 90.1 percent interest in Enogex LLC. The investment agreement provides the ArcLight group the opportunity to increase its ownership interest by providing equity funding for capital expenditures associated with Enogex's business plan. The transaction closed on November 1, 2010. As a result of the investment agreement described above and subsequent contributions by the ArcLight group, at December 31, 2011, the Company indirectly owns an 81.3 percent membership interest in Enogex Holdings.
As part of the investment agreement, OGE Energy and the ArcLight group have agreed to indemnify each other for breaches of representations, warranties and covenants contained in the investment agreement, and, in the case of OGE Energy, for certain tax matters related to the Company, in each case subject to customary thresholds and survival periods.
Pursuant to the Enogex Holdings LLC Agreement, OGE Holdings' and the ArcLight group's rights to designate directors to the Board of Directors of Enogex Holdings will be determined by percentage ownership. OGE Holdings was initially entitled to designate three directors, and the ArcLight group was initially entitled to designate one director. As its ownership position increases, the ArcLight group will be entitled to increasing board representation. The ArcLight group will also be entitled, at various ownership thresholds, to certain special board approval rights with respect to certain significant actions taken by Enogex Holdings, as well as to appoint additional directors for Enogex Holdings.
Until the ArcLight group owns 50 percent of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest. If necessary, the ArcLight group will fund between 50 percent and 90 percent of required capital contributions during that period. The remainder of the required capital contributions (i.e., between 10 percent and 50 percent) will be funded by OGE Holdings. Prior to January 1, 2012, the per unit equity price paid equaled the initial price that had been paid by the ArcLight group under the investment agreement. Beginning January 1, 2012, the equity price per unit will be based on the equity value of Enogex Holdings. Subject to certain adjustments, including for material acquisitions, equity value will be calculated as 9.0 or 9.5 times trailing 12-month Earnings before Interest, Taxes, Depreciation and Amortization, depending on the ArcLight group's ownership interest and whether the project has already been identified by Enogex Holdings.
Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings will make minimum quarterly distributions equal to the amount of cash required to cover OGE Energy's anticipated tax liabilities plus $12.5 million, to be distributed in proportion to each member's percentage ownership interest.
Under the terms of the Enogex Holdings LLC Agreement, each member and its affiliates are prohibited from independently pursuing a transaction in which a portion of the relevant assets are located in a designated core operating area, subject to certain exceptions. In addition, each member and its affiliates are prohibited from independently pursuing a transaction in which a portion of the relevant assets are located in a designated area of mutual interest unless (i) in the case of the ArcLight group, the collective ownership interest of the ArcLight group is less than five percent, (ii) the transaction falls within a defined category of passive financial investments, (iii) the proposed transaction has been disapproved by Enogex Holdings or (iv) the fair market value of the assets located in the area of mutual interest constitutes less than 50 percent of the total fair market value of the assets involved in the transaction. A member permitted to pursue a transaction independently pursuant to the foregoing is not required to offer the assets associated with such transaction to Enogex Holdings.
Transportation and Storage
General
Enogex owns and operates approximately 2,250 miles of intrastate natural gas transportation pipelines in Oklahoma with 1.94 TBtu/d of average daily throughput in 2011. Enogex also owns and operates two underground natural gas storage facilities in Oklahoma operating at a combined working gas level of 24 billion cubic feet. 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 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 f
rom 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 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, Cana/Woodford Shale play and the Colony Wash play in western Oklahoma and the Granite Wash play in the Wheeler County, Texas area, which is located in the Texas Panhandle). At December 31, 2011, Enogex was connected to 13 third-party natural gas pipelines and had 62 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, Postrock KPC Pipeline, LLC, Ozark Gas Transmission, L.L.C., Gulf Crossings Pipeline Company LLC and MEP. Further, Enogex is connected to 33 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 operating at a combined working gas level of 24 billion cubic feet with 650 MMcf/d of maximum withdrawal capacity and 650 MMcf/d of injection capacity. Enogex offers both fee-based firm and interruptible storage services. Storage services offered under Section 311 of the Natural Gas Policy Act are pursuant to terms and conditions specified in Enogex's Statement of Operating Conditions 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 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. 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, 2012, the contract will remain in effect at least through April 30, 2013. 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 natural gas-fired electric generation facilities to serve residential and commercial electricity requirements. In 2011, 2010 and 2009, revenues from Enogex's firm intrastate transportation and storage contracts were $130.7 million, $116.6 million and $116.8 million, respectively, of which $47.5 million in each year was attributed to OG&E and $15.3 million in each year was attributed to PSO. Revenues from Enogex's firm intrastate transportation and storage contracts represented 30 percent of Enogex's consolidated gross margin in 2011, 28 percent in 2010 and 33 percent in 2009.
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 Natural Gas Policy Act. Rates to provide such service must be "fair and equitable" under the Natural Gas Policy Act and are subject to review and approval by the FERC at least once every five years (previously a triennial requirement). 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. Enogex began to offer firm Section 311 service in the East Zone on April 1, 2009 and in the West Zone on March 1, 2011.
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 and West Zones. Finally, Enogex may charge the applicable fixed zonal fuel percentage(s) for the fuel used in transporting natural gas under Section 311 on Enogex's 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. 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. A final settlement was filed with the FERC on August 5, 2010. With the filing of Enogex's Section 311 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 October 13, 2011, the FERC issued an order in this matter approving the settlement agreement, providing that Enogex's rates from its previous rate case remain in effect and that the MEP lease agreement discussed below would be addressed in Enogex's Section 311 2009 rate case. This matter is now closed.
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 its 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 had filed with the FERC, as required by the FERC's regulations, a revised Statement of Operating Conditions Applicable to Transportation Services to describe the terms, conditions and operating arrangements for the new service. Enogex made the Statement of Operating Conditions 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 were collected, subject to refund, pending the FERC approval of the proposed rates. A number of parties intervened in both the rate case and the Statement of Operating Conditions filing and some additionally filed protests. On January 4, 2010, the FERC Staff submitted an offer proposing various adjustments to Enogex's filed cost of service. On April 27, 2010, Enogex submitted comments to the FERC Staff stating that it would agree to the offer, contingent upon all parties agreeing to support or not oppose. On October 4, 2011, Enogex filed a settlement agreement with the FERC which included a proposed refund to shippers of $2.1 million related to the increase in the rates for East and West Zone and interruptible Section 311 service which were collected, subject to refund, pending the FERC approval of the proposed rates. This refund was made to shippers in January 2012. On December 16, 2011, the FERC issued an order approving the settlement agreement. Also, as discussed below, the MEP lease agreement was addressed in this rate case.
On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex 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 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 (i) approving the MEP project including the approval of a limited jurisdiction certificate and (ii) authorizing the Enogex lease agreement with MEP. Accordingly, Enogex proceeded with the construction of facilities necessary to implement this service. On August 25, 2008, a 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. On December 28, 2010, the Court of Appeals issued an opinion generally upholding the FERC's orders, but remanding the case for further explanation of one aspect of the FERC's reasoning. The Court of Appeals emphasized that it was not vacating the FERC's orders and that its approval of the Enogex lease agreement with MEP remains in effect and legally binding. On remand, the FERC was to clarify that its decision was based on a finding that the lease does not adversely affect existing customers on Enogex's system. On January 21, 2011, Apache Corporation filed a motion asking the FERC to establish procedures on remand and to either condition the lease on Enogex's willingness to provide firm Section 311 transportation service to existing customers on all portions of its system or to establish an expedited briefing schedule. On February 7, 2011, Enogex, MEP and Chesapeake Energy Corporation filed a joint answer asking the FERC to find, among other things, that the reduction in the amount of interruptible transportation capacity available due to the MEP lease did not have an adverse affect on Apache Corporation and to acknowledge that Apache Corporation's request to condition the lease on the provision of West Zone 311 firm transportation service has been addressed as Enogex filed a rate case on January 28, 2011 proposing to implement such service effective March 1, 2011. On March 1, 2011, Apache Corporation filed an answer seeking to refute some of the arguments presented in the joint answer filed by Enogex, MEP and Chesapeake Energy Corporation. On March 3, 2011, the FERC issued an order on remand affirming the authorizations previously granted to Enogex and MEP and clarifying the applicable legal standard in response to the court's directive. On April 4, 2011, Apache Corporation filed a request for rehearing of the FERC's order on remand. On September 29, 2011, the FERC issued an order denying Apache Corporation's motion for rehearing. Apache Corporation did not appeal the FERC's March 3, 2011 order on remand and/or the September 29, 2011 order denying rehearing. This matter is now closed.
Enogex Storage Statement of Operating Conditions Filing
On August 31, 2010, Enogex filed via eTariff with the FERC a new Statement of Operating Conditions applicable to storage services that replaced Enogex's existing storage Statement of Operating Conditions effective July 30, 2010. Among other things, the new storage Statement of Operating Conditions updates the general terms and conditions for providing storage services. A FERC order is pending.
Enogex FERC Section 311 2011 Rate Case
On January 28, 2011, Enogex submitted a new rate filing to the FERC to set the maximum rate for a new firm Section 311 transportation service in the West Zone of its system and to revise the currently effective maximum rates for Section 311 interruptible transportation service in the East Zone and West Zone. Along with establishing the rate for a new firm service in the West Zone, Enogex's filing requested a decrease in the maximum interruptible zonal rates in the West Zone and to retain the currently effective rates for firm and interruptible services in the East Zone. Enogex reserved the right to implement the higher rates for firm and interruptible services in the East Zone supported by the cost of service to the extent an expeditious settlement agreement cannot be reached in the proceeding. Enogex proposed that the rates be placed into effect on March 1, 2011. The deadline for interventions and protests on Enogex's filing was November 28, 2011 and no protests were filed. On January 10, 2012, Enogex filed a settlement agreement with the FERC. The deadline for comments to the filing was January 17, 2012, and no comments opposing the settlement were filed. A FERC order is pending.
Enogex 2011 Fuel Filing
On February 28, 2011, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2011 through March 31, 2012). Along with the revised fuel percentages, Enogex also requested authority to revise its Statement of Operating Conditions to permanently change the annual filing date to February 28. The deadline for interventions and protests on Enogex's filing was March 15, 2011, and no protests were filed. A FERC order is pending.
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 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 $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 added an incremental 17,200 horsepower of gas turbine compression at its Bennington compressor station, as well as other system upgrades. These projects were placed in service in December 2010 and January 2011. The capital expenditures associated with these projects were $27 million.
In August 2010, Enogex completed construction of transportation and compression facilities necessary to provide gas delivery service to a new natural gas-fired electric generation facility near Pryor, Oklahoma. Aid in Construction payments of $36.4 million received in excess of construction costs were recognized as Deferred Revenues on the Company's Consolidated Balance Sheet and are being amortized on a straight-line basis of $1.2 million per year over the life of the related firm transportation service agreement under which service commenced in June 2011.
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 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 methane and ethane.
Enogex's gathering system includes approximately 6,019 miles of intrastate natural gas gathering pipelines in Oklahoma and Texas with 1.36 TBtu/d of average daily gathered volumes in 2011. Enogex owns and operates eight natural gas processing plants, with a current total inlet capacity of 1,105 MMcf/d and has contracted to have access to up to 230 MMcf/d of capacity in six third-party plants. 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. In 2011, Enogex extracted and sold 685 million gallons of NGLs.
Enogex also has a 50 percent interest in Atoka, which operated a 20 MMcf/d refrigeration processing plant which processed gas gathered in the Atoka area. The processing plant was leased on a month-to-month basis. In August 2011, management made a decision to use third-party processing exclusively for gathered volumes dedicated to Atoka and, therefore, to take the processing plant out of service and return it to the lessor in accordance with the rental agreement. See Note 5 of Notes to Consolidated Financial Statements for a further discussion.
Enogex gathers and processes natural gas pursuant to a variety of arrangements generally categorized as fee-based, percent-of-proceeds, percent-of-liquids and keep-whole arrangements. Percent-of-proceeds, percent-of-liquids and keep-whole arrangements involve varying levels of 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.
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• | Fee-based arrangements. Under these arrangements, Enogex generally is paid a fixed fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through Enogex's system and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in Enogex's fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. At December 31, 2011, these arrangements accounted for 31 percent of Enogex's natural gas processed volumes. |
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• | 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, 2011, these arrangements accounted for 44 percent of Enogex's natural gas processed volumes.
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• | Keep-whole arrangements. Enogex processes raw natural gas to extract NGLs and returns to the producer the full gas equivalent British thermal unit value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. Enogex is entitled to retain the processed NGLs and to sell them for its own account. Accordingly, Enogex's margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent of those NGLs. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of Enogex's keep-whole contracts include provisions that reduce its commodity price exposure, including conditioning floors (such as the default processing fee described below) that allow the keep-whole contract to be charged a fee if the NGLs have a lower value than their gas equivalent British thermal unit value in natural gas. At December 31, 2011, these arrangements accounted for 25 percent of Enogex's natural gas processed volumes. |
In August 2011, Enogex and one of its five largest customers entered into new agreements, effective July 1, 2011, relating to the customer's gathering and processing volumes on the Oklahoma portion of Enogex's system. The effect of this new arrangement is that (i) the acreage dedicated by the customer to Enogex for gathering and processing in Oklahoma has been increased for an extended term and (ii) the processing arrangement has been converted from keep-whole to fixed fee. This customer's converted volumes represented 8.4 percent of total inlet volumes from July 1, 2011 to December 31, 2011. Also, as a result of this transaction and as part of the new agreements, Enogex recorded $6.4 million in Deferred Revenues on the Company's Consolidated Balance Sheet at December 31, 2011. Processing revenues under the agreements are recognized based on the estimated average fee per MMBtu processed over the life of the agreements. Enogex expects to record additional deferred revenues during 2012.
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 British thermal unit 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 British thermal unit 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 British thermal unit per cubic foot when the price of the NGLs to be extracted and sold is less than the British thermal unit value of the natural gas that Enogex otherwise would be required to replace.
Of the commercial grade propane produced at Enogex's processing plants, 14 percent 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 western Oklahoma and the Wheeler County area in the Texas Panhandle can flow to the Cox City, Thomas, Calumet or South Canadian gas processing plants. These large-diameter "super-header" gathering system of Enogex provides gas routing flexibility for Enogex to optimize the economics of its gas processing and to improve system utilization and reliability.
In order to meet the growing requirements of its customers, Enogex continues to evaluate the need to expand its processing capabilities on the "super-header" gathering system, such as the 200 MMcf/d processing plant in Canadian County which was placed in service in December 2011 and the 200 MMcf/d processing plant currently under construction in Wheeler County, Texas and the 200 MMcf/d processing plant which will be installed in Custer County, Oklahoma.
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 in 2011 included Chesapeake Energy Marketing Inc., Apache Corporation, Devon Energy Production Company, L.P., BP America Production Company and Kaiser Francis Oil Co. In 2011, these five customers accounted for 19.9 percent, 15.0 percent, 12.5 percent, 4.1 percent and 3.9 percent, respectively, of Enogex's gathering and processing volumes. In 2011, Enogex's top 10 natural gas producer
customers accounted for 69.4 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 Chesapeake Midstream Partners, L.P., Crosstex Energy LP, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P., 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, known as the lost and unaccounted for gas bill, which 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 regulations nor the lost and unaccounted for gas bill 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 west side of Enogex's gathering system, primarily in the Cana/Woodford Shale play and the Colony Wash play in western Oklahoma and the Granite Wash play in western Oklahoma and in the Wheeler County, Texas area, which is located in the Texas Panhandle.
Enogex constructed a new 200 MMcf/d cryogenic processing plant in Canadian County, Oklahoma. The new plant, which has inlet and residue compression and is supported by the installation of 31 miles of 20-inch gathering pipeline, as well as 11 miles of 24-inch transmission pipeline providing takeaway capacity from the plant tailgate, was placed in service in December 2011. The total capital expenditures associated with this project were $140 million.
Enogex expects to expand its cryogenic processing plant currently under construction in Wheeler County, Texas from a processing capacity of 120 MMcf/d to 200 MMcf/d with the installation of additional residue compression facilities. The initial processing capacity of 120 MMcf/d is expected to be in service at the beginning of the third quarter of 2012, and the additional processing capacity is expected to be in service by the end of the third quarter of 2012. The new plant will be supported by the installation of 9,400 horsepower of field compression. The total capital expenditures associated with this project are expected to be $140 million.
In support of significant long-term acreage dedications from its customers in the area, Enogex continues to expand its gathering infrastructure in four counties of western Oklahoma. These expansions are planned to occur in phases, with the initial phase calling for the installation of 47,980 horsepower of low pressure compression and over 300 miles of gathering pipe across the area. This infrastructure is expected to be constructed throughout 2012 and 2013. The total capital expenditures associated with these expansions projects are expected to be $240 million.
Enogex expects to install a 200 MMcf/d cryogenic processing plant in Custer County, Oklahoma. The new plant will be supported by 6,000 horsepower of inlet compression and 25 miles of transmission pipeline. This plant is expected to be in service by the end of the third quarter of 2013. The total capital expenditures associated with this project are expected to be $135 million.
Disposition
On April 1, 2011, Enogex completed the sale of its Harrah processing plant (38 MMcf/d of capacity) and the associated Wellston and Davenport gathering assets. The proceeds from the sale were $15.9 million and Enogex recorded a pre-tax gain in the second quarter of 2011 of $3.7 million.
Gas Gathering Acquisitions
On September 23, 2011, Enogex entered into the following agreements: an agreement with Cordillera, Oxbow and West Canadian Midstream LLC pursuant to which Enogex agreed to acquire 100 percent of the membership interest in Roger Mills Gas Gathering, LLC, an Oklahoma limited liability company that owns an approximately 60-mile natural gas gathering system located in Roger Mills County and Ellis County, Oklahoma; an agreement with Cordillera and Oxbow pursuant to which Enogex agreed to acquire an approximately 30-mile natural gas gathering system located in Roger Mills County, Oklahoma; and agreements with Cordillera and other producers pursuant to which such producers agreed to provide Enogex with long-term acreage dedication in the area served by the gathering systems encompassing approximately 100,000 net acres. The gathering systems are located in the Granite Wash area. The aggregate purchase price for these transactions was $200.4 million which was paid in cash primarily from contributions from OGE Energy and the ArcLight group (as discussed in Note 4 of Notes to Consolidated Financial Statements) as well as cash generated from operations and bank borrowings. The transactions closed on November 1, 2011. Enogex believes that the transactions will provide Enogex with key new opportunities in the Granite Wash area. See Note 3 of Notes to Consolidated Financial Statements for a further discussion.
In support of the acquisitions described above, Enogex plans to construct 20 miles of 16-inch gathering pipe and over 11,000 horsepower of low pressure compression in 2012. The total capital expenditures for these projects are expected to be $55 million.
Enogex Cox City Plant Fire
On December 8, 2010, a fire occurred at Enogex's Cox City natural gas processing plant destroying major components of one of the four processing trains, representing 120 MMcf/d of the total 180 MMcf/d of capacity, at that facility. Gas volumes normally processed at the Cox City plant were diverted to other facilities or bypassed around Enogex's system to accommodate production and all of the impacted gathered volumes were back online in December 2010. The damaged train was replaced and the facility was returned to full service in September 2011. The total cost necessary to return the facility back to full service was $29.6 million. While Enogex believes that the costs in excess of the $10 million deductible should be reimbursed by insurance, the matter is currently being negotiated with the insurance company and Enogex cannot predict the precise outcome of these negotiations or the timing associated with the recovery. In the fourth quarter of 2011, Enogex received a partial insurance reimbursement of $7.4 million and recognized a gain of $3.0 million on insurance proceeds. Enogex expects to receive additional reimbursement of portions of the costs in 2012. Enogex will recognize insurance recoveries in earnings as the insurance claims are resolved.
Safety and Health Regulation
Certain of Enogex's facilities are subject to pipeline transportation regulations, including the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The Pipeline and Hazardous Materials Safety Administration regulates safety requirements in the design, construction, operation and maintenance of applicable natural gas and hazardous liquid pipeline facilities. The Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 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 U.S. Department of Transportation has developed regulations implementing the Pipeline Safety Improvement Act of 2002 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. For example, the U.S. Department of Transportation has adopted regulations requiring pipeline operators to develop integrity management programs for their applicable pipelines. In 2011, Enogex incurred $23.0 million of capital expenditures and operating costs for pipeline integrity management. Enogex currently estimates that it will incur capital expenditures and operating costs of between $100 million and $160 million from 2012 to 2016 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.
On December 13, 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which the President signed into law on January 3, 2012. Among other things, the law requires additional verification of pipeline infrastructure records by Enogex and other intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. Where records are inadequate to confirm the maximum allowable operating pressure, the PHMSA will require the operator to re-confirm the maximum allowable operating pressure, a process that could cause temporary or permanent limitations on throughput for affected pipelines. This law requires PHMSA to direct pipeline operators to verify the maximum allowable operating pressure of their pipelines by July 3, 2012, and to submit documentation to PHMSA by July 3, 2013. This law also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2.0 million for a related series of violations. For further information regarding this Act and potential regulations, see Note 16 of Notes to Consolidated Financial Statements. At this time, the Company is not able to estimate the capital, operating or other costs that may be required to comply with this law and any related PHMSA regulations that may be promulgated, but such costs could be significant.
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 U.S. Department of Transportation. 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
General
OER 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 OER's business on Enogex's system. OER 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.
OER primarily participates in both intermediate-term markets (less than three years) and short-term "spot" markets for natural gas. Although OER 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. OER's average daily sales volumes were 0.5 billion cubic feet in both 2011 and 2010. OER'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 OER by buying and selling natural gas futures contracts on the NYMEX 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.
Competition
OER 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.
In 2011, 60 percent of OER's service volumes were with electric utilities, local gas distribution companies, pipelines and producers, of which 31 percent was with affiliates of OER. The remaining 40 percent of OER's service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2011, 69 percent of the payment exposure was to companies having investment grade ratings with Standard & Poor's Ratings Services and two percent was to companies having less than investment grade ratings with Standard & Poor's Rating Services. The remaining 29 percent of OER's exposure is with privately held companies, municipals or cooperatives that were not rated by Standard & Poor's Ratings Services. OER applies internal credit analyses and policies to these non-rated companies. At December 31, 2011, all but $1.2 million of OER's exposure was to counterparties who were investment grade or deemed investment grade equivalents based upon OER's internal credit analyses.
Regulation
The price at which OER 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, OER is required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission. The FERC and Commodity Futures Trading Commission 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 OER 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.
On July 21, 2010, President Obama signed into law the Dodd-Frank Act. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps, exchange trading, margin requirements and other transparency requirements. The impact of the provisions of the Dodd-Frank Act on the OER cannot be determined pending issuance of the final implementing regulations. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Potential Collateral Requirements" for further discussion of the Dodd-Frank Act.
ENVIRONMENTAL MATTERS
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 their wastes, requiring remedial action to mitigate pollution conditions that may be caused by their operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. 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. OG&E and Enogex believe that their operations are in substantial compliance with current Federal, state and local environmental standards.
The trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment. OG&E and Enogex cannot assure that future events, such as changes in existing laws, the promulgation of new
laws or regulations, or the development or discovery of new facts or conditions will not cause them to incur significant costs. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
Of the Company's capital expenditures budgeted for 2012, $34.4 million are to comply with environmental laws and regulations, of which $33.7 million and $0.7 million are related to OG&E and Enogex, respectively. Of the Company's capital expenditures budgeted for 2013, $36.0 million are to comply with environmental laws and regulations, of which $35.3 million and $0.7 million are related to OG&E and Enogex, respectively. The Company's management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards. 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 $51.6 million and $6.2 million, respectively, in 2012 as compared to $24.0 million and $6.5 million, respectively, in 2011. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
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."
FINANCE AND CONSTRUCTION
Future Capital Requirements and Financing Activities
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, 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 Resources" for a discussion of the Company's capital requirements.
Capital Expenditures
The Company's consolidated estimates of capital expenditures for the years 2012 through 2016 are shown in the following table. 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.
|
| | | | | | | | | | | | | | | |
(In millions) | 2012 | 2013 | 2014 | 2015 | 2016 |
OG&E Base Transmission | $ | 80 |
| $ | 50 |
| $ | 50 |
| $ | 50 |
| $ | 50 |
|
OG&E Base Distribution | 195 |
| 200 |
| 200 |
| 200 |
| 200 |
|
OG&E Base Generation | 110 |
| 80 |
| 80 |
| 80 |
| 80 |
|
OG&E Other | 30 |
| 30 |
| 30 |
| 30 |
| 30 |
|
Total OG&E Base Transmission, Distribution, Generation and Other | 415 |
| 360 |
| 360 |
| 360 |
| 360 |
|
OG&E Known and Committed Projects: | | | | | |
Transmission Projects: | | | | | |
Sunnyside-Hugo (345 kilovolt) | 25 |
| — |
| — |
| — |
| — |
|
Sooner-Rose Hill (345 kilovolt) | 5 |
| — |
| — |
| — |
| — |
|
Balanced Portfolio 3E Projects | 110 |
| 180 |
| 50 |
| — |
| — |
|
SPP Priority Projects | 20 |
| 200 |
| 115 |
| — |
| — |
|
Total Transmission Projects | 160 |
| 380 |
| 165 |
| — |
| — |
|
Other Projects: | | | | | |
Smart Grid Program (A) | 90 |
| 35 |
| 40 |
| 20 |
| 20 |
|
Crossroads | 40 |
| — |
| — |
| — |
| — |
|
System Hardening | 15 |
| — |
| — |
| — |
| — |
|
Total Other Projects | 145 |
| 35 |
| 40 |
| 20 |
| 20 |
|
Total OG&E Known and Committed Projects | 305 |
| 415 |
| 205 |
| 20 |
| 20 |
|
Total OG&E (B) | 720 |
| 775 |
| 565 |
| 380 |
| 380 |
|
Enogex LLC Base Maintenance | 60 |
| 50 |
| 55 |
| 60 |
| 65 |
|
Enogex LLC Known and Committed Projects: | | | | | |
Western Oklahoma / Texas Panhandle Gathering Expansion | 215 |
| 115 |
| 15 |
| 5 |
| 5 |
|
Other Gathering Expansion | 25 |
| 25 |
| 20 |
| 20 |
| 20 |
|
Total Enogex LLC Known and Committed Projects | 240 |
| 140 |
| 35 |
| 25 |
| 25 |
|
Total Enogex LLC (C) | 300 |
| 190 |
| 90 |
| 85 |
| 90 |
|
OGE Energy | 20 |
| 20 |
| 20 |
| 20 |
| 20 |
|
Total capital expenditures | $ | 1,040 |
| $ | 985 |
| $ | 675 |
| $ | 485 |
| $ | 490 |
|
| |
(A) | These capital expenditures are net of the $130 million Smart Grid grant approved by the U.S. Department of Energy. |
| |
(B) | The capital expenditures above exclude any environmental expenditures associated with pollution control equipment related to regional haze requirements due to the uncertainty regarding the timing and costs for such pollution control equipment. OG&E has committed to install low NOX burners at the affected generating units at a cost preliminarily estimated between $70 million and $130 million, but the timing of the installation of such burners is uncertain. The SO2 emissions standards in the EPA's Federal implementation plan could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. The Federal implementation plan is being challenged by OG&E and the state of Oklahoma. Neither the outcome of the challenge to the Federal implementation plan nor the timing and amount of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. For further information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" below. |
| |
(C) | These capital expenditures represent 100 percent of Enogex LLC's capital expenditures, of which a portion may be funded by the ArcLight group. Until the ArcLight group owns 50 percent of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest. If necessary, the ArcLight group will fund between 50 percent and 90 percent of required capital contributions during that period. The remainder of the required capital contributions (i.e., between 10 percent and 50 percent) will be funded by OGE Holdings. |
Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets and at Enogex LLC, will be evaluated based upon their impact upon achieving the Company's financial objectives. The capital expenditure projections related to Enogex LLC in the table above reflect base market conditions at February 16, 2012 and do not reflect the potential opportunity for a set of growth projects that could materialize. Also, if drilling activity declines in the future, this could reduce Enogex's capital expenditures in the table above.
Pension and Postretirement Benefit Plans
During each of 2011 and 2010, OGE Energy made contributions to its Pension Plan of $50 million to help ensure that the Pension Plan maintains an adequate funded status. During 2012, OGE Energy may contribute up to $35 million to its Pension
Plan. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a discussion of OGE Energy's pension and postretirement benefit plans.
Common Stock Dividends
At the Company's December 2011 Board meeting, management, after considering estimates of future earnings and numerous other factors, recommended to the Board of Directors an increase in the current quarterly dividend rate to $0.3925 per share from $0.3750 per share effective with the Company's first quarter 2012 dividend. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a further discussion.
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 or other offerings will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. Additionally, the Company will have an additional source of funding for growth opportunities at Enogex through the ArcLight group and from quarterly distributions from Enogex Holdings. 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 and Credit Facilities
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. In December 2011, the Company, OG&E and Enogex LLC each entered into new unsecured five-year revolving credit facilities totaling in the aggregate $1,550 million ($750 million for the Company, $400 million for OG&E and $400 million for Enogex LLC). The short-term debt balance was $277.1 million and $145.0 million at December 31, 2011 and 2010, respectively. The weighted-average interest rate on short-term debt at December 31, 2011 was 0.48 percent. The average balance of short-term debt in 2011 was $210.7 million at a weighted-average interest rate of 0.36 percent. The maximum month-end balance of short-term debt in 2011 was $323.0 million. Enogex had $150.0 million and $25.0 million in outstanding borrowings under its revolving credit agreement at December 31, 2011 and 2010, respectively. As Enogex LLC's credit agreement matures on December 13, 2016, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Consolidated Balance Sheets. At December 31, 2011, the Company had $1,120.7 million of net available liquidity under its revolving credit agreements. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2011 and ending December 31, 2012. At December 31, 2011, the Company had $4.6 million in cash and cash equivalents. See Note 13 of Notes to Consolidated Financial Statements for a discussion of the Company's short-term debt activity.
Expected Issuance of Long-Term Debt
OG&E expects to issue approximately $250 million of long-term debt in late 2012, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.
Common Stock
The Company expects to issue between $13 million and $15 million of common stock in its Automatic Dividend Reinvestment and Stock Purchase Plan in 2012. See Note 11 of Notes to Consolidated Financial Statements for a discussion of the Company's common stock activity.
Minimum Quarterly Distributions by Enogex Holdings
Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings will make minimum quarterly distributions equal to the amount of cash required to cover OGE Energy's anticipated tax liabilities plus $12.5 million, to be distributed in proportion to each member's percentage ownership interest.
EMPLOYEES
The Company and its subsidiaries had 3,489 employees at December 31, 2011.
EXECUTIVE OFFICERS
The following persons were Executive Officers of the Registrant as of February 16, 2012:
|
| | |
Name | Age | Title |
Peter B. Delaney | 58 | Chairman of the Board, President and Chief Executive Officer - OGE Energy Corp. |
Sean Trauschke | 44 | Vice President and Chief Financial Officer - OGE Energy Corp. |
E. Keith Mitchell | 49 | President and Chief Operating Officer - Enogex Holdings |
Stephen E. Merrill | 47 | Chief Operating Officer of Enogex LLC |
William J. Bullard | 63 | Assistant General Counsel - OGE Energy Corp. |
Scott Forbes | 54 | Controller and Chief Accounting Officer - OGE Energy Corp. |
Patricia D. Horn | 53 | Vice President - Governance, Environmental, Health & Safety; Corporate Secretary - OGE Energy Corp. |
Gary D. Huneryager | 61 | Vice President - Internal Audits - OGE Energy Corp. |
Jesse B. Langston | 49 | Vice President - Retail Energy - OG&E |
Jean C. Leger, Jr. | 53 | Vice President - Utility Operations - OG&E |
Cristina F. McQuistion | 47 | Vice President - Strategy and Performance Improvement - OGE Energy Corp. |
Max J. Myers | 37 | Treasurer - OGE Energy Corp. |
Reid V. Nuttall | 54 | Vice President - Chief Information Officer - OGE Energy Corp. |
Jerry A. Peace | 49 | Chief Risk Officer - OGE Energy Corp. |
Paul L. Renfrow | 55 | Vice President - Public Affairs and Human Resources - OGE Energy Corp. |
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Trauschke, Bullard, Forbes, Huneryager, Myers, Nuttall, Peace, Renfrow and Ms. Horn and Ms. McQuistion are also officers of OG&E. Messrs. Delaney, Trauschke, Mitchell, Myers and Ms. Horn are also officers of Enogex Holdings and/or its subsidiaries. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners, currently scheduled for May 17, 2012.
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
|
| | |
Name | Business Experience |
Peter B. Delaney | 2012 - Present: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. and OG&E |
| 2010 - 2011: | Chairman of the Board and Chief Executive Officer of OGE Energy Corp. and OG&E |
| 2010 - Present: | Chief Executive Officer of Enogex Holdings LLC |
| 2008 - Present: | Chief Executive Officer of Enogex LLC |
| 2007 - 2010: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. and OG&E |
| 2007 - 2008: | Chief Executive Officer of Enogex Inc. |
| 2007: | President and Chief Operating Officer of OGE Energy Corp. and OG&E |
| 2007: | Executive Vice President and Chief Operating Officer of OGE Energy Corp. and OG&E |
Sean Trauschke | 2009 - Present: | Vice President and Chief Financial Officer of OGE Energy Corp. and OG&E |
| 2010 - Present: | Chief Financial Officer of Enogex Holdings LLC |
| 2009 - Present: | Chief Financial Officer of Enogex LLC |
| 2007 - 2009: | Senior Vice President - Investor Relations and Financial Planning of Duke Energy |
| 2007: | Vice President - Investor Relations of Duke Energy (electric utility) |
E. Keith Mitchell | 2011 - Present: | President and Chief Operating Officer of Enogex Holdings LLC; President of Enogex LLC |
| 2008 - 2011: | Senior Vice President and Chief Operating Officer of Enogex LLC |
| 2007 - 2008: | Senior Vice President and Chief Operating Officer of Enogex Inc. |
| 2007: | Senior Vice President of Enogex Inc. |
| 2007: | Vice President - Transportation Services of Enogex Inc. |
Stephen E. Merrill | 2011 - Present: | Chief Operating Officer of Enogex LLC |
| 2009 - 2011: | Vice President - Human Resources of OGE Energy Corp. and OG&E |
| 2008 - 2009: | Vice President and Chief Financial Officer of Enogex LLC |
| 2007 - 2008: | Vice President and Chief Financial Officer of Enogex Inc. |
| 2007: | Vice President and Chief Financial Officer of Cayenne Drilling, LLC and Sunstone Energy Group LLC (oil and gas company) |
William J. Bullard | 2010 - Present: | Assistant General Counsel of OGE Energy Corp.; General Counsel of OG&E |
| 2007 - 2010: | Assistant General Counsel of OGE Energy Corp. and OG&E |
Scott Forbes | 2007 - 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 |
Patricia D. Horn | 2010 - Present: | Vice President - Governance, Environmental, Health & Safety; Corporate Secretary of OGE Energy Corp. and OG&E; Secretary of Enogex Holdings LLC; Corporate Secretary of Enogex LLC |
| 2008 - 2010: | Vice President - Legal, Regulatory, Environmental Health & Safety, General Counsel and Secretary of Enogex LLC |
| 2007 - 2010: | Assistant General Counsel of OGE Energy Corp. |
| 2007 - 2008: | Vice President - Legal, Regulatory, Environmental Health & Safety, General Counsel and Secretary of Enogex Inc. |
Gary D. Huneryager | 2007 - Present: | Vice President - Internal Audits of OGE Energy Corp. and OG&E |
Jesse B. Langston | 2011 - Present: | Vice President - Retail Energy of OG&E |
| 2007 - 2011: | Vice President - Utility Commercial Operations of OG&E |
Jean C. Leger, Jr. | 2008 - Present: | Vice President - Utility Operations of OG&E |
| 2007 - 2008: | Vice President of Operations of Enogex Inc. |
| | |
| | |
| | |
| | |
|
| | |
| | |
Name | Business Experience |
Cristina F. McQuistion | 2011 - Present: | Vice President - Strategy and Performance Improvement of OGE Energy Corp. and OG&E |
| 2008 - 2011: | 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 |
| 2007: | Executive Vice President - Member Services of Teleflora (floral industry and software services to floral industry company) |
Max J. Myers | 2009 - Present: | Treasurer of OGE Energy Corp. and OG&E |
| 2010 - Present: | Treasurer of Enogex Holdings LLC |
| 2008 - 2009: | Managing Director of Corporate Development and Finance of OGE Energy Corp. and OG&E |
| 2007 - 2008: | Manager of Corporate Development of OGE Energy Corp. and OG&E |
Reid V. Nuttall | 2009 - Present: | Vice President - Chief Information Officer of OGE Energy Corp. and OG&E |
| 2007 - 2009: | Vice President - Enterprise Information and Performance of OGE Energy Corp. and OG&E |
Jerry A. Peace | 2008 - Present: | Chief Risk Officer of OGE Energy Corp. and OG&E |
| 2007 - 2008: | Chief Risk Officer and Compliance Officer of OGE Energy Corp. and OG&E |
Paul L. Renfrow | 2011 - Present: | Vice President - Public Affairs and Human Resources of OGE Energy Corp. and OG&E |
| 2007 - 2011: | Vice President - Public Affairs of OGE Energy Corp. and OG&E |
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
The Company's web site address is www.oge.com. Through the Company's website 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 Securities and Exchange Commission. 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.
Item 1A. Risk Factors.
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 OGE Enogex Holdings and its subsidiaries. In addition to the other information in this Form 10-K and other documents filed by us and/or our subsidiaries with the Securities and Exchange Commission 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 conservation, 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 rules could require significant capital and operating expenditures to achieve reductions in emissions of SO2 and NOX over the next five years.
In response to public concern about global climate change, emissions of greenhouse gases including, most significantly, carbon dioxide could be restricted in the future as a result of Federal or state legal requirements or litigation relating to greenhouse gas emissions. If mandatory reductions of carbon dioxide and other greenhouse gases are required in the future, 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.
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.
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".
We are subject to physical and financial risks associated with 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 OG&E's 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 jurisdictions have fuel clauses that permit us to recover 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.
OG&E may not realize the expected benefits of its Smart Grid metering system, the Smart Grid metering system may not perform as intended or OG&E may incur costs to deploy the Smart Grid metering system that are not recoverable in rates which could adversely affect our results of operations, consolidated financial position and cash flows.
In 2010, OG&E began implementing its Smart Grid metering infrastructure project for residential and commercial customers. This project, which is expected to be completed by the end of 2012, involves the installation of approximately 792,000 Smart Grid meters throughout OG&E's service territory. Smart Grid meters will allow customer usage data to be transmitted through a communication network to a central collection point, where the data will be stored and used for customer billing and
other commercial purposes.
The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program are capped at $366.4 million, (inclusive of the U.S. Department of Energy grant award amount) subject to an offset for any recovery of those costs from Arkansas customers and are currently being recovered through a rider which will remain in effect until the Smart Grid project costs are included in base rates beginning in 2014. To the extent that OG&E's total expenditure for system-wide deployment of smart grid technology during the eligible period exceeds the Smart Grid project cost, OG&E shall be entitled to offer evidence and seek to establish that the excess above the Smart Grid project cost was prudently incurred and any such contention may be addressed in OG&E's next rate case.
If OG&E does not recognize the expected benefits of its Smart Grid metering system, if OG&E incurs additional Smart Grid metering costs that the OCC does not find reasonable or are unrecoverable or if OG&E cannot integrate the Smart Grid metering system with its customer billing and other computer information systems, this may adversely affect our results of operations, consolidated financial position and cash flows.
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 regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. The SPP implemented a regional energy imbalance service market on February 1, 2007. OG&E participates 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.
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.
Our investment agreement with the ArcLight group involves risks and uncertainties.
As part of our investment agreement with the ArcLight group, we are entitled to designate three directors and the ArcLight group is able to designate one director of Enogex Holdings. The investment agreement provides the ArcLight group the opportunity to increase its ownership interest by providing equity funding for capital expenditures associated with Enogex's business plan. As its ownership position increases, the ArcLight group will be entitled to increasing board representation. As of December 31, 2011, the ArcLight group has an 18.7 percent membership interest in Enogex Holdings. The ArcLight group will also be entitled, at various ownership thresholds, to certain special board approval rights with respect to certain significant actions taken by Enogex Holdings, as well as to appoint additional directors for Enogex Holdings.
Joint venture arrangements like this involve risks and uncertainties, including the risk of the joint venture partner failing to satisfy its obligations, which may result in certain liabilities to us for commitments; the challenges in achieving strategic objectives and expected benefits of the business arrangement and the risk of conflicts arising between us and our partner and the difficulty of managing and resolving such conflicts.
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 Natural Gas Policy Act, 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 Natural Gas Policy Act. Rates to provide such service must be "fair and equitable" under the Natural Gas Policy Act and are subject to review and approval by the FERC at least once every three years. See Note 17 of Notes to Consolidated Financial Statements for a 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 and other similar programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002 , the U.S. Department of Transportation has adopted regulations requiring pipeline operators to develop integrity management programs for their 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; |
•develop a baseline plan to prioritize the assessment of a covered pipeline segment;
•gather data and identify and characterize applicable threats that could impact a covered pipeline segment;
•discover, evaluate and remediate problems in accordance with the program requirements;
•continuously improve all elements of the integrity program;
•continuously perform preventative and mitigation actions;
•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 U.S. Department of Transportation and state agencies, including the periodic submission of performance documents to the U.S. Department of Transportation. |
In 2011, Enogex incurred $23.0 million of capital expenditures and operating costs for pipeline integrity management. Enogex currently estimates that it will incur capital expenditures and operating costs of between $100 million and $160 million from 2012 to 2016 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.
On December 13, 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which the President signed into law on January 3, 2012. Among other things, the law requires additional verification of pipeline infrastructure records by Enogex and other intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. Where records are inadequate to confirm the maximum allowable operating pressure, the PHMSA will require the operator to re-confirm the maximum allowable operating pressure, a process that could cause temporary or permanent limitations on throughput for affected pipelines. This law requires PHMSA to direct pipeline operators to verify the maximum allowable operating pressure of their pipelines by July 3, 2012, and to submit documentation to PHMSA by July 3, 2013. This law also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2.0 million for a related series of violations. For further information regarding this Act and potential regulations, see Note 16 of Notes to Consolidated Financial Statements. At this time, the Company is not able to estimate the capital, operating or other costs that may be required to comply with this law and any related PHMSA regulations that may be promulgated, but such costs could be significant.
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.
In compliance with the Energy Policy Act of 2005, the FERC approved the North American Electric Reliability Corporation as the national energy reliability organization. The North American Electric Reliability Corporation is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. The Company's plan is to comply with all applicable standards and to expediently correct a violation should it occur. The North American Electric Reliability Corporation has authority to assess penalties up to $1 million per day per violation for noncompliance. OG&E is subject to a North American Electric Reliability Corporation 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.
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.
OG&E's electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
OG&E owns and operates coal-fired, natural gas-fired and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels. Included among these risks are:
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• | Increased prices for fuel and fuel transportation as existing contracts expire;
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• | Facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
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• | Operator error or safety related stoppages;
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• | Disruptions in the delivery of electricity; and
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• | Catastrophic events such as fires, explosions, floods or other similar occurrences.
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Economic conditions could negatively impact our business and our results of operations.
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. Economic conditions may also impact the valuation of certain long-lived or intangible assets, including goodwill, that are subject to impairment testing, potentially resulting in impairment charges, which could have a material adverse impact on our results of operations.
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.
In addition, economic conditions, particularly budget shortfalls, could lead to increased pressure on Federal, state and local governments to raise additional funds, including through increased corporate taxes and/or through delaying, reducing or eliminating tax credits, grants or other incentives, which could have a material adverse impact on our results of operations.
We are subject to cyber security risks.
In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on the operations and financial condition of the Company.
OG&E and Enogex operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems and Enogex's transportation systems and also subject OG&E and Enogex to financial harm. The implementation of OG&E's Smart Grid program further increases potential risks associated with cyber security attacks. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on the operations and financial condition of the Company.
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 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 results of operations and cash flows.
Enogex'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, liquefied 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 15 percent of its gross margin and accounted for 25 percent of its natural gas processed volumes in 2011, 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 British thermal unit basis by replacing the British thermal units of the NGLs extracted from the production stream with British thermal units 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 British thermal units 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 nine percent of its gross margin and accounted for 44 percent of its natural gas processed volumes in 2011. 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 $2.50 per MMBtu level due to an oversupply of natural gas from shale play drilling activity. 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. In particular, certain states have adopted or are considering, and Congress is considering, adopting regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In the event Federal, state, local or municipal legal restrictions are adopted in the areas where Enogex operates, there may be a delay or curtailment in drilling activities. 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. The Company primarily uses forward physical contracts, commodity price swap contracts and commodity price option features to manage the Company's commodity price risk exposures.
From time to time, Enogex has instituted a hedging program that was intended to reduce the commodity price risk associated with Enogex's keep-whole and percent-of-liquids arrangements. 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. 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. In 2011, Chesapeake Energy Marketing Inc., Apache Corporation, Devon Energy Production Company, L.P., BP America Production Company and Kaiser Francis Oil Co. accounted for 55.4 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 transportation customers are OG&E and PSO, the second largest electric utility in Oklahoma. 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 2011, 2010 and 2009, revenues from Enogex's firm intrastate transportation and storage contracts were $130.7 million, $116.6 million and $116.8 million, respectively, of which $47.5 million in each year was attributed to OG&E and $15.3 million in each year was attributed to PSO. 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. 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, 2012, the contract will remain in effect at least through April 30, 2013. 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; and |
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.
FINANCIAL RISKS
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 Pension Plan that covers substantially all of our employees hired before December 1, 2009. We also have defined benefit postretirement plans that cover substantially all of our employees hired prior to February 1, 2000. 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, 2011, 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.
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, 29 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, 2011, the Company and its subsidiaries had outstanding indebtedness and other liabilities of $6.1 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 as well as a Federal regulatory agency which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions or Federal regulatory agency 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 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.
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 you that any of our current credit 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 disruptions. Pricing grids associated with our credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade would include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, could require us to post 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:
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• | 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;
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• | 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
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• | our debt levels may limit our flexibility in responding to changing business and economic conditions.
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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.
Item 2. Properties.
OG&E
OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 12 generating stations with an aggregate capability of 6,790 MWs at December 31, 2011. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
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| | | | | | | | | | | | |
| | | | | | 2011 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) |
| | Year Installed | | Fuel Capability | Unit Run Type | |
Station & Unit | | Unit Design Type | |
Seminole | 1 | 1971 | Steam-Turbine | Gas | Base Load | 25.6 | % | | 490 |
| |
| 1GT | 1971 | Combustion-Turbine | Gas | Peaking | 0.2 | % | (B) | 16 |
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| 2 | 1973 | Steam-Turbine | Gas | Base Load | 29.1 | % | | 499 |
| |
| 3 | 1975 | Steam-Turbine | Gas/Oil | Base Load | 21.7 | % | | 496 |
| 1,501 |
|
Muskogee | 4 | 1977 | Steam-Turbine | Coal | Base Load | 63.3 | % | | 504 |
| |
| 5 | 1978 | Steam-Turbine | Coal | Base Load | 59.6 | % | | 500 |
| |
| 6 | 1984 | Steam-Turbine | Coal | Base Load | 67.9 | % | | 506 |
| 1,510 |
|
Sooner | 1 | 1979 | Steam-Turbine | Coal | Base Load | 69.0 | % | | 515 |
| |
| 2 | 1980 | Steam-Turbine | Coal | Base Load | 74.0 | % | | 523 |
| 1,038 |
|
Horseshoe Lake | 6 | 1958 | Steam-Turbine | Gas/Oil | Base Load | 14.0 | % | | 162 |
| |
| 7 | 1963 | Combined Cycle | Gas/Oil | Base Load | 20.0 | % | | 225 |
| |
| 8 | 1969 | Steam-Turbine | Gas | Base Load | 9.2 | % | | 380 |
| |
| 9 | 2000 | Combustion-Turbine | Gas | Peaking | 5.4 | % | (B) | 46 |
| |
| 10 | 2000 | Combustion-Turbine | Gas | Peaking | 6.1 | % | (B) | 46 |
| 859 |
|
Redbud (C) | 1 | 2003 | Combined Cycle | Gas | Base Load | 41.6 | % | | 147 |
| |
| 2 | 2003 | Combined Cycle | Gas | Base Load | 45.5 | % | | 149 |
| |
| 3 | 2003 | Combined Cycle | Gas | Base Load | 47.8 | % | | 147 |
| |
| 4 | 2003 | Combined Cycle | Gas | Base Load | 44.5 | % | | 146 |
| 589 |
|
Mustang | 1 | 1950 | Steam-Turbine | Gas | Peaking | 6.5 | % | (B) | 50 |
| |
| 2 | 1951 | Steam-Turbine | Gas | Peaking | 7.2 | % | (B) | 50 |
| |
| 3 | 1955 | Steam-Turbine | Gas | Base Load | 23.3 | % | | 109 |
| |
| 4 | 1959 | Steam-Turbine | Gas | Base Load | 22.7 | % | | 250 |
| |
| 5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 2.4 | % | (B) | 32 |
| |
| 5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 2.7 | % | (B) | 32 |
| 523 |
|
McClain (D) | 1 | 2001 | Combined Cycle | Gas | Base Load | 70.1 | % | | 353 |
| 353 |
|
Woodward | 1 | 1963 | Combustion-Turbine | Gas | Peaking | — | % | (B)(E) | — |
| — |
|
Enid | 1 | 1965 | Combustion-Turbine | Gas | Peaking | — | % | (B)(E) | — |
| |
| 2 | 1965 | Combustion-Turbine | Gas | Peaking | — | % | (B)(E) | — |
| |
| 3 | 1965 | Combustion-Turbine | Gas | Peaking | — | % | (B)(E) | — |
| |
| 4 | 1965 | Combustion-Turbine | Gas | Peaking | — | % | (B)(E) | — |
| — |
|
Total Generating Capability (all stations, excluding wind stations) | 6,373 |
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| | | | | | | | | |
| | | | | | 2011 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) |
| | Year Installed | | Number of Units | Fuel Capability | |
Station | | Location | |
Crossroads (F) | | 2011 | Woodward, OK | 85 | Wind | 45.9 | % | | 2.3 |
| 196 |
|
Centennial | | 2007 | Woodward, OK | 80 | Wind | 31.0 | % | | 1.5 |
| 120 |
|
OU Spirit | | 2009 | Woodward, OK | 44 | Wind | 37.8 | % | | 2.3 |
| 101 |
|
Total Generating Capability (wind stations) | 417 |
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(A) 2011 Capacity Factor = 2011 Net Actual Generation / (2011 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).
(B) Peaking units are used when additional short-term capacity is required.
(C) Represents OG&E's 51 percent ownership interest in the Redbud Plant.
(D) Represents OG&E's 77 percent ownership interest in the McClain Plant.
(E) This unit did not demonstrate summer capability in 2011 as prescribed by the SPP criteria.
(F) The Crossroads wind farm was fully in service in January 2012, which increased station capability to 227.5 MWs.
At December 31, 2011, OG&E's transmission system included: (i) 51 substations with a total capacity of 11.5 million kilovolt-amps and 4,258 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.4 million kilovolt-amps and 279 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 353 substations with a total capacity of 9.1 million kilovolt-amps, 27,854 structure miles of overhead lines, 1,895 miles of underground conduit and 10,120 miles of underground conductors in Oklahoma and (ii) 37 substations with a total capacity of 1.0 million kilovolt-amps, 2,250 structure miles of overhead lines, 212 miles of underground conduit and 572 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 73102. 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, 2011, Enogex and its subsidiaries owned: (i) approximately 6,019 miles of intrastate natural gas gathering pipelines in Oklahoma and Texas; (ii) approximately 2,250 miles of intrastate natural gas transportation pipelines in Oklahoma; (iii) two underground natural gas storage facilities in Oklahoma operating at a combined working gas level of 24 billion cubic feet with 650 MMcf/d of maximum withdrawal capacity and 650 MMcf/d of injection capacity; (iv) 638,350 horsepower of owned compression and (v) eight operating natural gas processing plants, with a current total inlet capacity of 1,105 MMcf/d, all located in Oklahoma. The following table sets forth information with respect to Enogex's active natural gas processing plants:
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| | | | | |
Processing Plant | Year Installed | Type of Plant | Fuel Capability | 2011 Average Daily Inlet Volumes (MMcf/d) | Inlet Capacity (MMcf/d) |
Calumet (A) | 1969 | Lean Oil | Gas/Electric | 178 | 250 |
South Canadian (A) (B) | 2011 | Cryogenic | Electric | 74 | 200 |
Cox City (C) (D) | 1994 | Cryogenic | Gas/Electric | 155 | 180 |
Thomas (A) | 1981 | Cryogenic | Gas | 132 | 135 |
Clinton (A) | 2009 | Cryogenic | Electric | 122 | 120 |
Roger Mills (C) | 2008 | Refrigeration | Electric | 29 | 100 |
Canute (C) | 1996 | Cryogenic | Electric | 51 | 60 |
Wetumka (A) | 1983 | Cryogenic | Gas/Electric | 37 | 60 |
Total | 778 | 1,105 |
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(A) | These processing plants are located on property that Enogex owns in fee. |
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(B) | This plant was placed into service in December 2011. |
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(C) | These processing plants are located on easements or leased property as described above. |
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(D) | On December 8, 2010, a fire occurred at Enogex's Cox City natural gas processing plant destroying major components of one of the four processing trains, representing 120 MMcf/d of the total 180 MMcf/d of capacity, at that facility. Gas volumes normally processed at the Cox City plant were diverted to other facilities or bypassed around Enogex's system to accommodate |
production and all of the impacted gathered volumes were back online in December 2010. The damaged train was replaced and the facility was returned to full service in September 2011. Average daily inlet volumes were calculated using October through December 2011 inlet volumes.
On April 1, 2011, Enogex completed the sale of its Harrah processing plant (38MMcf/d of capacity) and the associated Wellston and Davenport gathering assets. The proceeds from the sale were $15.9 million and Enogex recorded a pre-tax gain in the second quarter of 2011 of $3.7 million.
Enogex also has a 50 percent interest in Atoka, which operated a 20 MMcf/d refrigeration processing plant which processed gas gathered in the Atoka area. The processing plant was leased on a month-to-month basis. In August 2011, management made a decision to use third-party processing exclusively for gathered volumes dedicated to Atoka and, therefore, to take the processing plant out of service and return it to the lessor in accordance with the rental agreement. See Note 5 of Notes to Consolidated Financial Statements for a further discussion.
Enogex currently 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. On June 30, 2011, Enogex executed a five-year lease agreement that expires March 31, 2017 for 134,219 square feet of office space at its new executive offices. Although Enogex may require additional office space as its business expands, Enogex believes that its new 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, 2011, the Company's gross property, plant and equipment (excluding construction work in progress) additions were $2.9 billion and gross retirements were $316.8 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 28.2 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2011.
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. When appropriate, 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 GAAP, 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 16 and 17 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. Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy 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, OG&E and Enogex Inc. were omitted from the case but two of OGE Energy's other subsidiary entities remained as defendants. The plaintiffs' amended petition seeks class certification and alleges that 60 defendants, including two of OGE Energy's subsidiary entities, have improperly measured the volume of natural gas. The 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.
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 March 31, 2010, the court denied the plaintiffs' request for rehearing. On July 20, 2011, Enogex LLC and OER filed motions for summary judgment. On January 25, 2012, the court denied portions of the motions for summary judgment related to the legal issue of the plaintiffs' claims regarding civil conspiracy. In an order dated January 23, 2012, the court granted the plaintiffs additional time to perform discovery prior to the consideration of the motions for summary judgment as they relate to the plaintiffs' other claims.
OGE Energy intends to vigorously defend this action. At this time, OGE Energy does not believe the outcome will have a material impact on its financial position.
2. 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 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 amended petition of the Price I case. OG&E and Enogex Inc. were not named in this case, but two of OGE Energy's other subsidiary entities were named in this case. The plaintiffs allege that the defendants mismeasured the British thermal unit 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.
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 March 31, 2010, the court denied the plaintiffs' request for rehearing. On July 20, 2011, Enogex LLC and OER filed motions for summary judgment. On January 25, 2012, the court denied portions of the motions for summary judgment related to the legal issue of the plaintiffs' claims regarding civil conspiracy. In an order dated January 23, 2012, the court granted the plaintiffs additional time to perform discovery prior to the consideration of the motions for summary judgment as they relate to the plaintiffs' other claims.
OGE Energy intends to vigorously defend this action. At this time, OGE Energy does not believe the outcome will have a material impact on its financial position.
3. Farris Buser Litigation. 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 alleged 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 asserted breach of contract, implied covenants, obligation, fiduciary duty, unjust enrichment, conspiracy and fraud causes of action and claim actual damages, plus attorneys' fees and costs, and punitive damages. 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 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 filed an answer to the amended petition and BP America, Inc. and BP America Production Company's cross claim on January 16, 2007. On October 14, 2011, this case was dismissed without prejudice. While this lawsuit could be re-filed, Enogex considers the claims and cross claim associated with this lawsuit to be without merit, based upon Enogex's investigation to date. Enogex now considers this case closed.
4. Opacity Notice. On May 17, 2011, OG&E entered into a Consent Order with the ODEQ related to alleged violations of Federal and state opacity standards from 2005 to May 2011 at OG&E's Muskogee and Sooner generating stations. The Consent Order requires OG&E to reach certain milestones with regard to the overall amount of time when opacity exceeds certain amounts. Beginning January 1, 2015, the Consent Order requires each unit at OG&E's Muskogee and Sooner generating stations to have a rolling annual average of the time that opacity emissions are in excess of 20 percent to a level equal to or below one percent of the total time in a measurement period. OG&E agreed to implement two specific projects and other measures as necessary to achieve the milestones established in the Consent Order. These projects and other measures are not expected to involve significant capital or ongoing operating expenses. OG&E also agreed to pay a stipulated cash penalty of $150,000 and agreed to contribute another $150,000 to an ODEQ environmental fund for assisting small Oklahoma communities with their drinking water and wastewater treatment systems. OG&E entered into the Consent Order without admitting or denying the allegations made by the ODEQ. In order to facilitate the court approval of the Consent Order, the ODEQ initiated the necessary legal action against OG&E in state court on May 17, 2011. On June 2, 2011, the Consent Order was approved and entered by the District Court of Oklahoma County, Oklahoma. Subject to the ongoing compliance obligations described above pursuant to the Consent Order, OG&E considers this matter closed.
As previously reported, on March 18, 2011, the Gulf Coast Environmental Labor Coalition gave notice pursuant to the citizen suit provision of the Federal Clean Air Act that it intended to file a lawsuit against OG&E seeking both injunctive relief to enjoin excess opacity emissions from OG&E's Muskogee and Sooner generating stations and the assessment of civil penalties for alleged past violations of the applicable opacity limits. Because the Consent Order addresses the same alleged violations, the
legal action by the ODEQ will prevent the Gulf Coast Environmental Labor Coalition from filing the lawsuit against OG&E. Neither the ODEQ action against OG&E in state court nor the Consent Order preclude the EPA from seeking additional relief in connection with the allegations of opacity emissions not in accordance with applicable new source performance standards that are contained in the previously disclosed notice of violation issued to OG&E on April 26, 2011.
5. Patent Infringement Case. On September 16, 2011, TransData, Inc., a Texas corporation, sued OG&E in the Western District of Oklahoma, accusing OG&E of infringing three of their U.S. patents by using OG&E's General Electric "smart" meters with Silver Spring Networks wireless modules. The complaint seeks a judgment of infringement, unspecified damages, a permanent injunction, costs and attorneys fees. OG&E was served with the complaint on September 21, 2011 and has notified both General Electric and Silver Springs Network of the lawsuit and its intent to seek indemnity from those companies for any damages that it may incur from this lawsuit. TransData, Inc. sought to consolidate its OG&E lawsuit with similar lawsuits in the Eastern District of Texas, however, on December 13, 2011, the TransData, Inc. cases were consolidated in the Western District of Oklahoma. OG&E has filed a motion for extension of time to answer the complaint. On December 30, 2011 OG&E and General Electric agreed to terms for General Electric to provide OG&E with an unqualified defense in the matter and to indemnify OG&E for costs, expenses and damages awarded against OG&E subject to a reservation of rights. While the Company cannot predict the outcome of this lawsuit at this time, the Company intends to vigorously defend this action and believes that its ultimate resolution will not be material to the Company's consolidated financial position or results of operations.
Item 4. Mine Safety Disclosures.
Not Applicable.
PART II
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.
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| | | | | | | | | |
| Dividend Paid | Price |
2012 | High | Low |
First Quarter (through February 10) | $ | 0.3925 |
| $ | 57.54 |
| $ | 52.34 |
|
2011 | | | |
First Quarter | $ | 0.3750 |
| $ | 50.61 |
| $ | 44.69 |
|
Second Quarter | 0.3750 |
| 53.50 |
| 47.64 |
|
Third Quarter | 0.3750 |
| 52.15 |
| 40.56 |
|
Fourth Quarter | 0.3750 |
| 57.17 |
| 45.70 |
|
2010 | | | |
First Quarter | $ | 0.3625 |
| $ | 39.32 |
| $ | 34.92 |
|
Second Quarter | 0.3625 |
| 42.25 |
| 33.87 |
|
Third Quarter | 0.3625 |
| 41.11 |
| 35.38 |
|
Fourth Quarter | 0.3625 |
| 46.18 |
| 39.93 |
|
At the Company's December 2011 Board meeting, management, after considering estimates of future earnings and numerous other factors, recommended to the Board of Directors an increase in the current quarterly dividend rate to $0.3925 per share from $0.3750 per share effective with the Company's first quarter 2012 dividend.
The number of record holders of the Company's Common Stock at December 31, 2011, was 19,948. The book value of the Company's Common Stock at December 31, 2011, was $28.77.
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 Holdings, 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, the covenants of OG&E's certificate of incorporation and OG&E's debt instruments limiting the ability of OG&E to pay dividends and the ability of public utility commissions that regulate OG&E to effectively restrict the payment of dividends by OG&E. 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 LLC's debt instruments (including Enogex LLC's revolving credit agreement) limiting the ability of Enogex Holdings 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:
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• | may not exceed 50 percent of OG&E's net income for a prior 12-month period, after deducting dividends on any preferred stock during the period, if the sum of the capital represented by common stock, premiums on common stock (restricted to premiums on common stock only by Securities and Exchange Commission orders), and surplus accounts is less than 20 percent of capitalization; |
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• | 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 |
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• | 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 currently restricted by these provisions.
Issuer Purchases of Equity Securities
The following table contains information about the Company's purchases of its common stock during the fourth quarter of 2011.
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| | | | | | |
| | | Total Number of Shares Purchased as Part of Publicly Announced Plan | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan |
| Total Number of Shares Purchased | Average Price Paid Per Share |
Period |
10/1/11 – 10/31/11 | — | $ | — |
| N/A | N/A |
11/1/11 – 11/30/11 | 120,000 | $ | 51.33 |
| 120,000 | N/A |
12/1/11 – 12/31/11 | — | $ | — |
| N/A | N/A |
N/A – not applicable
In November 2011, the Company purchased 120,000 shares of its common stock at an average cost of $51.33 per share on the open market. These shares will be used to satisfy Enogex's portion of the Company's obligation to deliver shares of common stock related to long-term incentive payouts of earned performance units in 2012.
Item 6. Selected Financial Data
HISTORICAL DATA
|
| | | | | | | | | | | | | | | |
Year ended December 31 | 2011 | 2010 | 2009 | 2008 | 2007 |
SELECTED FINANCIAL DATA | | | | | |
(In millions, except per share data) | | | | | |
| | | | | |
Results of Operations Data: | | | | | |
Operating revenues | $ | 3,915.9 |
| $ | 3,716.9 |
| $ | 2,869.7 |
| $ | 4,070.7 |
| $ | 3,797.6 |
|
Cost of goods sold | 2,277.9 |
| 2,187.4 |
| 1,557.7 |
| 2,818.0 |
| 2,634.7 |
|
Gross margin on revenues | 1,638.0 |
| 1,529.5 |
| 1,312.0 |
| 1,252.7 |
| 1,162.9 |
|
Operating expenses | 991.3 |
| 935.6 |
| 820.1 |
| 790.6 |
| 707.6 |
|
Operating income | 646.7 |
| 593.9 |
| 491.9 |
| 462.1 |
| 455.3 |
|
Interest income | 0.5 |
| — |
| 1.4 |
| 6.7 |
| 2.1 |
|
Allowance for equity funds used during construction | 20.4 |
| 11.4 |
| 15.1 |
| — |
| — |
|
Other income | 19.3 |
| 13.7 |
| 27.5 |
| 15.4 |
| 17.4 |
|
Other expense | 21.7 |
| 17.9 |
| 16.3 |
| 25.6 |
| 22.7 |
|
Interest expense | 140.9 |
| 139.7 |
| 137.4 |
| 120.0 |
| 90.2 |
|
Income tax expense | 160.7 |
| 161.0 |
| 121.1 |
| 101.2 |
| 116.7 |
|
Net income | 363.6 |
| 300.4 |
| 261.1 |
| 237.4 |
| 245.2 |
|
Less: Net income attributable to noncontrolling interest | 20.7 |
| 5.1 |
| 2.8 |
| 6.0 |
| 1.0 |
|
Net income attributable to OGE Energy | $ | 342.9 |
| $ | 295.3 |
| $ | 258.3 |
| $ | 231.4 |
| $ | 244.2 |
|
Basic earnings per average common share attributable to OGE Energy common shareholders | $ | 3.50 |
| $ | 3.03 |
| $ | 2.68 |
| $ | 2.50 |
| $ | 2.66 |
|
Diluted earnings per average common share attributable to OGE Energy common shareholders | $ | 3.45 |
| $ | 2.99 |
| $ | 2.66 |
| $ | 2.49 |
| $ | 2.64 |
|
Dividends declared per common share | $ | 1.5175 |
| $ | 1.4625 |
| $ | 1.4275 |
| $ | 1.3975 |
| $ | 1.3675 |
|
Balance Sheet Data (at period end): | | | | | |
Property, plant and equipment, net | $ | 7,474.0 |
| $ | 6,464.4 |
| $ | 5,911.6 |
| $ | 5,249.8 |
| $ | 4,246.3 |
|
Total assets | $ | 8,906.0 |
| $ | 7,669.1 |
| $ | 7,266.7 |
| $ | 6,518.5 |
| $ | 5,237.8 |
|
Long-term debt | $ | 2,737.1 |
| $ | 2,362.9 |
| $ | 2,088.9 |
| $ | 2,161.8 |
| $ | 1,344.6 |
|
Total stockholders' equity | $ | 2,819.3 |
| $ | 2,400.0 |
| $ | 2,060.8 |
| $ | 1,914.0 |
| $ | 1,691.6 |
|
Capitalization Ratios (A) |