(Mark One)

x  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

 

                                                                          Commission File Number: 1-12579

 

 

 

 

 

 

 

 

 

 

 

 

FORWARD-LOOKING STATEMENTS

 

Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

 

 

 

 

 

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 14 of Notes to Consolidated Financial Statements. The Company was incorporated in August 1995 in the state of Oklahoma and its principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.

 

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

 

Enogex LLC and its subsidiaries (“Enogex”) is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing. Historically, Enogex had also engaged in natural gas marketing through its former subsidiary, OGE Energy Resources, Inc. (“OERI”). On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture through Enogex Atoka LLC (“Atoka”), a wholly owned subsidiary of Enogex.

 

Effective April 1, 2008, Enogex Inc. converted from an Oklahoma corporation to a Delaware limited liability company. Also, effective April 1, 2008, Enogex Products Corporation (“Products”), a wholly owned subsidiary of Enogex, converted from an Oklahoma corporation to an Oklahoma limited liability company.

 

In September 2008, OGE Energy and Energy Transfer Partners, L.P. (“ETP”) entered into an agreement to form a joint venture combining Enogex’s midstream business with ETP’s interstate operations as well as its midstream operations in the Rocky Mountains. One of the conditions to completing the joint venture was obtaining financing that met the minimum specified terms the parties had agreed to in the joint venture agreement. Under the terms of the agreement, if OGE Energy and ETP did not complete the financing and close the joint venture by March 31, 2009, either OGE Energy or ETP could terminate the contribution agreement relating to the formation of the joint venture. Due to the significant downturn in the national economy and resulting uncertainty in the capital markets, the parties determined that obtaining the financing and completing the formation of the joint venture was not feasible and not in their best interests. Accordingly, on February 12, 2009, the parties terminated the agreement to form the joint venture.

In light of the September 28, 2008 announcement of the proposed joint venture as well as market conditions, OGE Enogex Partners, L.P., a partnership formed by the Company to further develop Enogex’s natural gas midstream assets and operations, which had previously filed a registration statement with the SEC for a proposed initial public offering of its common units, has determined not to proceed with the offering contemplated by the registration statement and withdrew the registration statement on September 23, 2008.

 

In July 2008, OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture to construct high-capacity transmission line projects in western Oklahoma. The Company will own 50 percent of the joint venture. The joint venture is intended to allow the companies to lead development of renewable wind by sharing capital costs associated with the planned transmission construction. Work on the joint venture projects is scheduled to begin in late 2009 and is targeted for completion by the end of 2013. The joint venture projects are subject to creation by the Southwest Power Pool (“SPP”) of a cost allocation method that would spread the total cost across the SPP region. OGE Energy filed an application with the FERC in October 2008 for cost recovery of these projects subject to SPP and FERC approval for these projects. On December 2, 2008, the FERC granted the joint venture’s request for transmission rate incentives for the initial projects, established a base

 

 

 

return on equity for initial projects, approved certain accounting treatments for the initial projects and set the formula rate and accompanying protocols for hearing and settlement discussions. The joint venture’s initial projects will include 765 kilovolt lines from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from Woodward 50 miles north to the Kansas border. An SPP study estimates cost for the two projects to be approximately $500 million, of which OGE Energy’s portion will be approximately $250 million.

 

Company Strategy

 

The Company’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream natural gas business. The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a weather-normalized basis, an annual total return in the top third of its peer group, dividend growth, maintenance of a dividend payout ratio consistent with its peer group and maintenance of strong credit ratings. The Company believes it can accomplish these financial goals by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

 

OG&E has been focused on increased investment at the utility to improve reliability and meet load growth, leverage unique geographic position to develop renewable energy resources for wind and transmission, replace infrastructure equipment, replace aging transmission and distribution systems, provide new products and services and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, OG&E has taken, or has committed to take, the following actions:

 

 

OG&E continues to pursue additional renewable energy and the construction of associated transmission facilities required to support this renewable expansion. In 2008, OG&E established a “Quick Start” Demand Side Management program to encourage more efficient use of electricity. OG&E also announced a “Positive Energy SmartPower” initiative (commonly referred to in the industry as “Smart Grid” technologies) that will empower customers to proactively manage their energy consumption during periods of peak demand. If these initiatives are successful, OG&E believes it may be able to defer the construction of any incremental fossil fuel generation capacity until 2020.

 

The increase in wind power generation and the building of the transmission lines are subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP. Other projects involve installing new emission-control and monitoring equipment at existing OG&E power plants to help meet OG&E’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see Note 16 of Notes to Consolidated Financial Statements.

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets, capturing growth opportunities through expansion projects and increased utilization of existing assets and strategic acquisitions. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Over the past several years, Enogex has initiated multiple organic growth projects. Currently, Enogex’s organic growth capital expenditures are focused on three primary areas:

 

 

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 269 communities and their contiguous rural and suburban areas. At December 31, 2008, four other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area covers approximately 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 269 communities that OG&E serves, 243 are located in Oklahoma and 26 in Arkansas. OG&E derived approximately 89 percent of its total electric operating revenues for the year ended December 31, 2008 from sales in Oklahoma and the remainder from sales in Arkansas.

 

OG&E’s system control area peak demand as reported by the system dispatcher during 2008 was approximately 6,472 MWs on August 4, 2008. OG&E’s load responsibility peak demand was approximately 6,054 MWs on August 4, 2008. As reflected in the table below and in the operating statistics that follow, there were approximately 26.8 million megawatt-hour (“MWH”) sales to OG&E’s customers (“system sales”) in 2008 and 26.4 million MWH system sales in both 2007 and 2006. Variations in system sales for the three years are reflected in the following table:

 

 

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. See Note 16 of Notes to Consolidated Financial Statements for a discussion of the potential impact on competition from Federal and state legislation.

 

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OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year ended December 31 (In millions)			2008				2007			2006
ELECTRIC ENERGY (Millions of MWH)
Generation (exclusive of station use)			25.7				23.8			24.6
Purchased			4.3				5.2			3.9
Total generated and purchased			30.0				29.0			28.5
Company use, free service and losses			(1.8)				(1.9)			(2.1)
Electric energy sold			28.2				27.1			26.4
ELECTRIC ENERGY SOLD (Millions of MWH)
Residential			9.0				8.7			8.7
Commercial			6.5				6.3			6.2
Industrial			4.0				4.2			4.4
Oilfield			2.9				2.8			2.7
Public authorities and street light			3.0				3.0			2.9
Sales for resale			1.4				1.4			1.5
System sales			26.8				26.4			26.4
Off-system sales			1.4				0.7			---
Total sales			28.2				27.1			26.4
ELECTRIC OPERATING REVENUES (In millions)
Residential	$		751.2		$		706.4	$		698.8
Commercial			479.0				450.1			428.3
Industrial			219.8				221.4			215.7
Oilfield			151.9				140.9			129.3
Public authorities and street light			190.3				181.4			171.0
Sales for resale			64.9				68.8			65.4
Provision for rate refund			(0.4)				0.1			(0.9)
System sales revenues			1,856.7				1,769.1			1,707.6
Off-system sales revenues			68.9				35.1			2.7
Other			33.9				30.9			35.4
Total Electric Operating Revenues	$		1,959.5		$		1,835.1	$		1,745.7
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential			659,829				653,369			647,548
Commercial			85,030				83,901			82,974
Industrial			3,086				3,142			3,181
Oilfield			6,424				6,324			6,324
Public authorities and street light			15,670				15,446			14,769
Sales for resale			49				52			44
Total			770,088				762,234			754,840
AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$		1,145.05		$		1,086.03	$		1,084.31
Average annual use (kilowatt-hour (“KWH”))			13,659				13,325			13,526
Average price per KWH (cents)	$		8.38		$		8.15	$		8.02

 

 

 

 

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, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of OG&E’s facilities and operations. For the year ended December 31, 2008, approximately 88 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and three percent to the FERC.

 

The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of the Company. The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

 

OG&E has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by OG&E due to the significant problems faced by other states in their electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the Federal and state levels are described in more detail in Note 16 of Notes to Consolidated Financial Statements.

 

Recent Regulatory Matters

 

Acquisition of Redbud Power Plant. On January 21, 2008, OG&E entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which were indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, OG&E agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which owned the Redbud Facility, for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.

 

In connection with the Purchase and Sale Agreement, OG&E also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”), pursuant to which OG&E agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to which OG&E, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and OG&E will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility.

 

The transactions described above were subject to an order from the FERC authorizing the contemplated transactions and an order from the OCC approving the prudence of the transactions and an appropriate reasonable recovery mechanism, and other customary conditions.

 

On September 16, 2008, the FERC issued an order approving the Redbud acquisition. In the order, the FERC concluded that the Redbud acquisition could harm horizontal competition by increasing market concentration. However, the FERC concluded that, since OG&E had committed to construct specific upgrades on the system, these would be adequate mitigation measures.  Accordingly, the FERC conditioned its approval of the Redbud acquisition on OG&E’s completion of these upgrades.  OG&E is required to file quarterly updates describing the progress of the transmission upgrades, the first of which was filed December 16, 2008. OG&E also must notify the FERC of any change in circumstances regarding these projects. During the approximately 27-month period required to construct the transmission upgrades, the FERC did not require any interim mitigation beyond the limits of OG&E’s market-based rate authority and the SPP market monitoring

 

 

 

 

programs currently in place. In addition, the FERC found that the proposed transaction would have no adverse effects on vertical market power, on wholesale rates, or on state or Federal regulation. The FERC also determined that the transaction presented no cross-subsidy concerns.  Finally, the FERC rejected various arguments raised by AES Shady Point that sought to expand the scope of the FERC proceeding or to impose additional conditions on the Redbud acquisition. On September 24, 2008, the OCC issued an order approving the Redbud acquisition. OG&E closed on the Redbud acquisition on September 29, 2008. OG&E implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes.

 

Cancelled Red Rock Power Plant and Storm Cost Recovery Rider. On October 11, 2007, the OCC issued an order denying OG&E and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. Specifically, OG&E requested authorization to sell approximately $14.7 million of its sulfur dioxide (“SO2”) allowances and to retain 100 percent of the proceeds to offset the $14.7 million of Red Rock costs. Under a prior order of the OCC, 90 percent of the proceeds from sales of SO2 allowances were to be credited to ratepayers. Any portion of the $14.7 million of deferred costs that the OCC did not approve for recovery by OG&E was to be expensed. In its response to OG&E’s Red Rock cost recovery application, the OCC Staff recommended, among other things, that OG&E sell SO2 allowances and retain 100 percent of the proceeds from the sale to be used to offset OG&E’s December 2007 ice storm costs. These ice storm costs were included as part of the regulatory asset balance of approximately $35.9 million at December 31, 2007 (see Note 1), in accordance with a prior order of the OCC, pending recovery in a future rate case. On June 27, 2008, OG&E filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, OG&E will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with OG&E’s next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date OG&E begins to recover the regulatory asset through the base rates established in OG&E’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in OG&E’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover OG&E’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess SO2 allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 allowances above the amount retained by OG&E and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. In June 2008, OG&E wrote down the Red Rock deferred cost and the storm costs to their net present value, which resulted in a pre-tax charge of approximately $9.0 million, which is currently included in Deferred Charges and Other Assets with an offset in Other Expense on the Company’s Consolidated Financial Statements.

 

Renewable Energy Filing. OG&E announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, OG&E issued an RFP to wind developers for construction of up to 300 MWs of new capability. OG&E intends to add the new capacity to its power-generation portfolio no later than the end of 2010. See discussion of OG&E proposed wind power project below.

 

OG&E filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma at a cost of approximately $211 million. This transmission line is a critical first step to increased wind development in western Oklahoma. In the application, OG&E also requested authorization to implement a recovery rider to be effective when the transmission line is completed and in service, which is expected during 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to OG&E’s Oklahoma customers. On July 11, 2008, the OCC Staff filed responsive testimony recommending approval of OG&E’s renewable plan and the Oklahoma Industrial Energy Consumers opposed OG&E’s request. A settlement agreement was signed by all parties in the matter on July 31, 2008. Under the terms of the settlement agreement, the parties agreed that OG&E will: (i) receive pre-approval for construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma and a conclusion that the construction costs of the transmission line are

 

 

 

prudent, (ii) receive a recovery rider for the revenue requirement of the $218 million in construction costs and allowance for funds used during construction (“AFUDC”) when the transmission line is completed and in service until new rates are implemented in a subsequent rate case and (iii) to the extent the construction costs and AFUDC for the transmission line exceed $218 million OG&E be permitted to show that such additional costs are prudent and allowed to be recovered. On September 11, 2008, the OCC issued an order approving the settlement agreement. Separately, on July 29, 2008, the SPP Board of Directors approved the proposed transmission line discussed above. On February 2, 2009, OG&E received SPP approval to begin construction of the transmission line and the associated Woodward Extra High Voltage substation.

 

OG&E Arkansas Rate Case Filing. On August 29, 2008, OG&E filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that OG&E can reliably meet growing customer demand for electricity, and a return on equity of 12.25 percent. In January 2009, the APSC Staff recommended a $12.0 million rate increase based on a 10.5 percent return on equity. The Attorney General’s consultant recommended a return on equity at the current authorized level of 10.0 percent and stated that his analysis identified at least $10.9 million in reductions to OG&E’s rate increase request. A hearing is scheduled for April 7, 2009. An order from the APSC is expected in June 2009, with new rates targeted for implementation in July 2009.

 

OG&E 2009 Oklahoma Rate Case Filing. Beginning in October 2008, OG&E began developing a rate case filing for the Oklahoma jurisdiction. On January 20, 2009, OG&E notified the OCC that it will make its planned Oklahoma rate case filing on or about February 26, 2009. OG&E is finalizing the preparation of the rate case and expects to request an increase of between $100 million and $110 million. The case is expected to proceed through the first half of 2009. If an increase is approved by the OCC, electric rates would likely be implemented in September 2009 at the earliest.

 

OG&E Proposed Wind Power Project. OG&E signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the future OU Spirit wind project in western Oklahoma. OG&E will seek regulatory recovery from the OCC and plans to have this project in-service by the end of 2009. Capital expenditures associated with this project are expected to be approximately $260 million.

 

OGE Energy and Electric Transmission America Joint Venture. As discussed above, the joint venture is intended to allow the companies to lead development of renewable wind by sharing capital costs associated with the planned transmission construction. Work on the joint venture projects is scheduled to begin in late 2009 and is targeted for completion by the end of 2013. The joint venture projects are subject to creation by the SPP of a cost allocation method that would spread the total cost across the SPP region. OGE Energy filed an application with the FERC in October 2008 for cost recovery of these projects subject to SPP and FERC approval for these projects. On December 2, 2008, the FERC granted the joint venture’s request for transmission rate incentives for the initial projects, established a base return on equity for initial projects, approved certain accounting treatments for the initial projects and set the formula rate and accompanying protocols for hearing and settlement discussions. The joint venture’s initial projects will include 765 kilovolt lines from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from Woodward 50 miles north to the Kansas border. An SPP study estimates cost for the two projects to be approximately $500 million, of which OGE Energy’s portion will be approximately $250 million.

 

See Note 16 of Notes to Consolidated Financial Statements for further discussion of these matters, as well as a discussion of additional regulatory matters, including, among other things, review of OG&E’s fuel adjustment clause, OG&E FERC formula rate filing, OG&E 2008 storm cost filing, national energy legislation and state legislative initiatives.

 

Regulatory Assets and Liabilities

 

OG&E, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71. SFAS No. 71 provides 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, 2008 and 2007, OG&E had regulatory assets of approximately $464.3 million and $330.7 million, respectively, and regulatory liabilities of approximately $164.0 million and $148.2 million, respectively. See Note 1 of Notes to Consolidated Financial Statements for a further discussion.

 

As discussed in Note 16 of Notes to Consolidated Financial Statements, legislation was enacted in the 1990’s for Oklahoma that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet, if and when implemented, this legislation could deregulate OG&E’s electric generation assets and cause OG&E to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect OG&E’s electric transmission and distribution assets and OG&E believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

 

Rate Structures

 

Oklahoma

 

OG&E’s standard tariff rates include a cost-of-service component (including an authorized return on capital) plus an fuel adjustment clause mechanism that allows OG&E to pass through to customers variances (either positive or negative) in the actual cost of fuel as compared to the fuel component in OG&E’s most recently approved rate case.

 

OG&E offers several alternate customer programs and rate options. The Guaranteed Flat Bill (“GFB”) option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set price for an entire year. Budget-minded customers that desire a fixed monthly bill may benefit from the GFB option. The GFB option received OCC approval for permanent rate status in OG&E’s rate case completed in December 2005. A second tariff rate option provides a “renewable energy” resource to OG&E’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and is available as a voluntary option to all of OG&E’s Oklahoma retail customers. OG&E’s ownership and access to wind resources makes the renewable wind power option a possible choice in meeting the renewable energy needs of our conservation-minded customers and provides the customers with a means to reduce their exposure to increased prices for natural gas used by OG&E as boiler fuel. A third rate offering available to commercial and industrial customers is levelized demand billing. This program is beneficial for medium to large size customers with seasonally consistent demand levels who wish to reduce the variability of their monthly electric bills. Another program being offered to OG&E’s commercial and industrial customers is a voluntary load curtailment program. 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.

 

The previously discussed rate options, coupled with OG&E’s other rate choices, provide many tariff options for OG&E’s Oklahoma retail customers. 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 our customers for many years to come. 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.  There was a gain from the GFB option of approximately $3.0 million, $4.2 million and $0.6 million, respectively, in 2008, 2007 and 2006. Revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose alternative rate options.

 

OG&E also has two additional rate classes, Public Schools-Demand and Public Schools Non-Demand. These two classes of service will provide OG&E 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 also implemented a military base rider that demonstrates Oklahoma’s continued commitment to our military partners.

 

Fuel Supply and Generation

 

During 2008, approximately 68 percent of the OG&E-generated energy was produced by coal-fired units, 30 percent by natural gas-fired units and two percent by wind-powered units. Of OG&E’s 6,781 total MW capability reflected in the table under Item 2. Properties, approximately 4,119 MWs, or 61 percent, are from natural gas generation, approximately 2,542 MWs, or 37 percent, are from coal generation and approximately 120 MWs, or two percent, are from wind generation.

 

 

Though OG&E has a higher installed capability of generation from natural gas units, it has been more economical to generate electricity for our customers using lower priced coal. Over the last five years, the weighted average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:

 

 

The increase in the weighted average cost of fuel in 2008 as compared to 2007 was primarily due to increased natural gas prices partially offset by decreased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2007 as compared to 2006 was primarily due to increased natural gas volumes. The decrease in the weighted average cost of fuel in 2006 as compared to 2005 was primarily due to decreased natural gas prices partially offset by increased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2005 and in 2004 was primarily due to increased natural gas prices and increased amounts of natural gas being burned. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of these fuel costs that is not included in the base rates is recoverable through OG&E’s fuel adjustment clauses that are approved by the OCC and the APSC. See Note 15 of Notes to Consolidated Financial Statements for a discussion of new and pending coal transportation contracts that will increase OG&E’s delivered coal prices.

 

Coal

 

All of OG&E’s coal-fired units, with an aggregate capability of approximately 2,542 MWs, are designed to burn low sulfur western coal. OG&E purchases coal primarily under contracts expiring in years 2010 and 2011. During 2008, OG&E purchased approximately 10.5 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.3 percent and can be burned in these units under existing Federal, state and local environmental standards (maximum of 1.2 lbs. of SO2 per MMBtu) without the addition of SO2 removal systems. Based upon the average sulfur content, OG&E’s coal units have an approximate emission rate of 0.52 lbs. of SO2 per MMBtu, well within the limitations of the current provisions of the Federal Clean Air Act discussed in Note 15 of Notes to Consolidated Financial Statements.

 

OG&E has continued its efforts to maximize the utilization of its coal-fired units at its Sooner and Muskogee generating plants. See “Environmental Laws and Regulations” in Note 15 of Notes to Consolidated Financial Statements for a discussion of environmental matters which may affect OG&E in the future.

 

Natural Gas

 

          In August 2008, OG&E issued an RFP for gas supply purchases for periods from November 2008 through March 2009, which accounted for approximately 15 percent of its projected 2009 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2009. Additional gas supplies to fulfill OG&E’s remaining 2009 natural gas requirements will be acquired through additional RFPs in early to mid-2009, along with monthly and daily purchases, all of which are expected to be made at competitive market prices.

 

In 1993, OG&E began utilizing a natural gas storage facility for storage services that allowed OG&E to maximize the value of its generation assets. Storage services are now provided by Enogex as part of Enogex’s gas transportation and storage contract with OG&E. At December 31, 2008, OG&E had approximately 1.9 million MMBtu’s in natural gas storage that it acquired for approximately $11.5 million.

 

Wind

 

OG&E’s current wind power portfolio includes the 120 MW Centennial wind farm placed in service in January 2007 as well as 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 in 2003.

 

OG&E announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, OG&E issued an RFP to wind developers for construction of up to 300 MWs of new capability. OG&E intends to add the new capacity to its power-generation portfolio no later than the end of 2010.

 

 

 

OG&E signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the future OU Spirit wind project in western Oklahoma. OG&E will seek regulatory recovery from the OCC and plans to have this project in-service by the end of 2009. Capital expenditures associated with this project are expected to be approximately $260 million.

 

Safety and Health Regulation

 

OG&E is subject to a number of Federal and state laws and regulations, including the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state statutes, whose purpose is to protect the safety and health of workers. In addition, the OSHA hazard communication standard, the U.S. Environmental Protection Agency (“EPA”) community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in OG&E’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

 

NATURAL GAS PIPELINE OPERATIONS - ENOGEX

 

Overview

 

Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing.

 

Historically, Enogex had also engaged in natural gas marketing through its former subsidiary, OERI. On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy.

 

Transportation and Storage

 

General

 

Enogex’s transportation and storage business owns and operates approximately 2,433 miles of intrastate natural gas transportation pipelines with approximately 1.57 trillion British thermal units per day (“TBtu/d”) of average daily throughput during 2008. Enogex also owns and operates two storage facilities currently being operated at a working gas level of approximately 24 billion cubic feet (“Bcf”). Enogex provides fee-based intrastate transportation services on a firm and interruptible basis and, pursuant to Section 311 of the Natural Gas Policy Act (“NGPA”), provides interstate transportation services on an interruptible 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 cases, 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 only obligated to transport natural gas nominated by the shipper to the extent that it has available capacity. For this service, the shipper pays no demand or reservation charge but pays a transportation or commodity charge for quantities actually shipped. Enogex derives a substantial portion of its transportation revenues from firm transportation services. To the extent pipeline capacity is not needed for such firm intrastate transportation service, Enogex offers interruptible interstate transportation services pursuant to Section 311 of the NGPA as well as interruptible intrastate transportation services.

 

Enogex delivers natural gas to most interstate and intrastate pipelines and end-users connected to its systems from the Arkoma and Anadarko basins (including recent growth activity in the Granite Wash play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma). At December 31, 2008, Enogex was connected to 11 third-party natural gas pipelines and had 63 interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative, CenterPoint Energy Gas Transmission Co., El Paso Natural Gas Pipeline, Quest Pipelines (KPC) and Ozark Gas Transmission, L.L.C. Further, Enogex is connected to 24 end-user customers, including 15 natural gas-fired electric generation facilities in Oklahoma.

 

 

 

Enogex owns and operates two natural gas storage facilities in Oklahoma, the Wetumka Storage Facility and the Stuart Storage Facility. These storage facilities are currently being operated at a working gas level of approximately 24 Bcf and have approximately 650 million cubic feet per day (“MMcf/d”) of maximum withdrawal capability and approximately 650 MMcf/d of injection capability. Enogex offers both fee-based firm and interruptible storage services to third parties. Services offered under Section 311 of the NGPA are pursuant to terms and conditions specified in Enogex’s Statement of Operating Conditions (“SOC”) for gas storage and at market-based rates negotiated with each customer. Enogex’s storage facilities are also used to support its no-notice load following transportation and storage contract with OG&E.

 

Enogex uses its storage assets to meet its contractual obligations under certain load following transportation contracts. Enogex also periodically conducts an open season to solicit commitments for contracted capacity and deliverability to third parties for contracts that generally do not exceed three years.

 

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, unless extended. The stated term of the OG&E contract expires April 30, 2009, but the contract will remain in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2009, the contract will remain in effect at least through April 30, 2010. As part of the no-notice load following contract with OG&E, Enogex provides natural gas storage services for OG&E. Enogex has been providing natural gas storage services to OG&E since August 2002 when it acquired the Stuart Storage Facility. Demand for natural gas on Enogex’s system is usually greater during the summer, primarily due to demand by gas-fired electric generation facilities to serve residential and commercial electricity requirements. Natural gas produced in excess of that which is used during the winter months is typically stored to meet the increased demand for natural gas during the summer months. During 2006, 2007 and 2008, revenues from Enogex’s firm intrastate transportation and storage contracts were approximately $98.1 million, $103.9 million and $104.4 million, respectively, of which approximately $47.6 million, $47.4 million and $47.5 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million and $15.3 million, respectively, was attributed to PSO. Revenues from Enogex’s firm intrastate transportation and storage contracts represented approximately 31 percent of Enogex’s consolidated gross margin on revenues (“gross margin”) in 2006, 29 percent in 2007 and 27 percent in 2008.

 

Competition

 

Enogex’s transportation and storage assets compete with numerous interstate and intrastate pipelines, including several of the interconnected pipelines discussed above, and storage facilities in providing transportation and storage services for natural gas. The principal elements of competition are rates, terms of services, flexibility and reliability of service. Natural gas-fired electric generation facilities contribute their highest value when they have the capability to provide load following service to the customer (i.e., the ability of the generation facility to regulate generation to respond to and meet the instantaneous changes in customer demand for electricity). While the physical characteristics of natural gas-fired electric generation facilities are known to provide quick start-up, on-line functionality and the ability to efficiently provide varying levels of electric generation relative to other forms of generation, a key part of their effectiveness is contingent upon having access to an integrated pipeline and storage system that can respond quickly to meet their corresponding fluctuating fuel needs. We believe that Enogex is well positioned to compete for the needs of these generators due to the ability of its transportation and storage assets to provide no-notice load following service.

 

Natural gas competes with other forms of energy available to Enogex’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas or other forms of energy as well as weather and other factors affect the demand for natural gas on Enogex’s system.

 

Regulation

 

The transportation rates charged by Enogex for transporting natural gas in interstate commerce are subject to the jurisdiction of the FERC under Section 311 of the NGPA. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every three years. The rate review may, but will not necessarily, involve an administrative-type hearing before the FERC Staff panel and an administrative appellate review. In the past, Enogex has successfully settled, rather than litigated, its Section 311 rate cases. Offering interruptible Section 311 transportation gives Enogex the opportunity to utilize any unused capacity on an interruptible basis in interstate commerce and thus increase its transportation revenues without increasing its regulatory burden appreciably. Enogex currently has two

 

 

 

zones under its Section 311 rate structure - an East Zone and a West Zone with a maximum transportation rate and a fuel retention rate for each zone. Enogex may charge up to its maximum established zonal East and West transportation rates for transportation in one zone or cumulative maximum rates for transportation in both zones and the applicable fixed zonal fuel percentage(s) for the fuel used in shipping natural gas under Section 311 on the Enogex system.

 

The fixed zonal fuel percentages are adjusted annually and remain in effect for a calendar year. The mechanism used to establish the percentages is a fuel tracker filed annually at the FERC to establish prospectively the zonal fixed fuel factors (expressed as a percentage of natural gas shipped in the zone) for the upcoming calendar year. Fuel usage is later trued-up to actual usage over a two-year period based on the value of the gas at the time of usage.

 

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for 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 additionally filed protests.

 

The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action. By order of February 28, 2008, the FERC extended the time period in this docket by 120 days and encouraged the parties to settle. No action has yet been taken by the FERC and the parties are currently in settlement negotiations.

 

On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex rate case with a separate Enogex application pending before the FERC allowing Enogex to lease firm capacity to MEP and with separate applications filed by MEP with the FERC for a certificate to construct and operate the new MEP pipeline and to lease firm capacity from Enogex. Additional pleadings were also filed by this intervenor after the initial protest and Enogex and MEP separately opposed this intervenor’s assertions. By order dated July 25, 2008, the FERC approved the MEP project and denied the intervenors’ request for consolidation of the MEP proceedings with the Enogex rate case. The intervenor has filed a request for rehearing in the MEP project and lease proceedings. The FERC has not yet acted on the request. Enogex has not, as of yet, placed the increased rates into effect while settlement negotiations continue. Enogex has a regulatory obligation to file its next rate case no later than October 1, 2010 to comply with the FERC’s requirement for triennial filings, but plans to file a new rate case during the first half of 2009. While Enogex has yet to finalize various components of the new filing, Enogex is finalizing agreements with East Zone shippers interested in firm Section 311 service on the East Zone of its system and anticipates offering in the near-term a  limited firm Section 311 service on the East Zone for the first time.

 

On November 21, 2008, Enogex made its annual filing to establish fixed fuel percentages for its East Zone and West Zone, respectively, for calendar year 2009 (“2009 Fuel Year”). The FERC accepted the proposed zonal fuel percentages for the 2009 Fuel Year by an order dated January 8, 2009.

 

The FERC regulates Enogex’s Section 311 transportation services but does not regulate its gathering services. In addition, the FERC does not regulate Enogex’s intrastate transportation services because these services are not Section 311 services. These services include those intrastate transportation services provided to the gas-fired electric generation facilities and other end users within Oklahoma. Therefore, the rates charged by Enogex for transporting natural gas for the Oklahoma utility companies, independent electric generation facilities and other shippers within Oklahoma are not subject to FERC regulation. Nor are the rates charged by Enogex for any intrastate transportation service subject to direct state regulation by the OCC. However, the OCC, the APSC and the FERC (all of which approve various electric rates of OG&E) have the authority to examine the appropriateness of any transportation charges or other fees paid by OG&E to Enogex which OG&E seeks to recover from its ratepayers in its cost-of-service for electric service.

 

Enogex’s pipeline operations are subject to various state and Federal safety and environmental and pipeline transportation laws. For example, the U.S. Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for its transportation pipelines. During 2008, Enogex incurred approximately $7.9 million of capital expenditures and operating costs to implement its pipeline integrity management program along certain segments of its natural gas pipelines. Enogex currently estimates that it will incur capital expenditures and operating costs of approximately $35.7 million between 2009 and 2013 in connection with its pipeline integrity management program. 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 as a result of the integrity management program. At this time, Enogex cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity assessment that is required by the rule. Enogex will continue its pipeline integrity program to assess, remediate and maintain the integrity of its pipelines. The results of these activities could cause Enogex to incur significant and unanticipated capital

 

 

and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

 

Recent System Expansions

 

Over the past several years, Enogex has initiated multiple organic growth projects. Currently, in Enogex’s transportation and storage business, organic growth capital expenditures are focused on upgrades to Enogex’s existing transportation system due to increased volumes as a result of the broader shift of gas flow from the Rocky Mountains and the mid-continent to markets in the northeast and southeast United States.

 

In December 2006, Enogex entered into a firm capacity lease agreement with MEP for a primary term of ten years (subject to possible extension) that would give 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 includes construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. Enogex currently estimates that its capital expenditures related to this project will be approximately $94 million.

 

On July 25, 2008, the FERC issued its order approving the MEP project including the approval of a limited jurisdiction certificate authorizing the Enogex lease agreement to MEP. Further, the FERC order rejected all claims raised by protestors regarding the lease agreement. Accordingly, Enogex is proceeding with the construction of facilities necessary to implement this service. On August 25, 2008, one protestor filed a request for rehearing. The FERC has not yet ruled on the request for rehearing. The MEP project is currently expected to be in service during the second quarter of 2009.

 

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. Furthermore, the processing plants produce NGLs.

 

Enogex’s gathering system includes approximately 5,763 miles of natural gas gathering pipelines with approximately 1.16 TBtu/d of average daily throughput during 2008 extending from southwestern Oklahoma to the eastern Texas Panhandle. During 2008, Enogex connected 357 new producing wells (including 154 wells behind central receipt points), located in the Arkoma and Anadarko basins (including recent growth activity in the Granite Wash play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma) to its gathering systems. At December 31, 2008, Enogex’s gathering system was connected to approximately 3,278 wells and approximately 266 central receipt points, all of which are equipped with state-of-the-art electronic flow measurement technology. Approximately 74 percent of Enogex’s gathered volumes are received at wellheads while 26 percent is gathered from central receipt or other interconnection points.

 

Enogex owns and operates six natural gas processing plants with a total inlet capacity of approximately 723 MMcf/d, has a 50 percent interest in and operates an additional natural gas processing plant with an inlet capacity of approximately 20 MMcf/d and has access to capacity up to 50 MMcf/d in two third-party plants, all in Oklahoma. Where the quality of natural gas received dictates the removal of NGLs, such gas is aggregated through the gathering system to the inlet of one or more of the seven processing plants operated by Enogex or the two leased plants. The resulting processed stream of natural gas is then delivered from the tailgate of each plant into Enogex’s intrastate natural gas transportation system. For the year ended December 31, 2008, Enogex extracted and sold approximately 426 million gallons of NGLs.

 

In 2007, 2008 and 2009, Enogex has pursued and expects to pursue several projects to address tightening processing capacity as a result of increasing supply:

 

 

 

 

Enogex’s gathering and processing business has approximately 276,000 horsepower of owned compression. Enogex also has its own compression overhaul center and specialized compression workforce.

 

Enogex gathers and processes natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” and “percent-of-liquids” arrangements and “keep-whole” arrangements. Percent-of-proceeds, percent-of-liquids and keep-whole arrangements involve commodity price risk to Enogex because Enogex’s margin is based in part on natural gas and NGL prices. Enogex seeks to minimize 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.

 

 

 

 

Enogex is active in the extraction and marketing of NGLs from natural gas. The liquids extracted include condensate liquids, marketable ethane, propane, butanes and natural gasoline mix. The residue gas remaining after the liquid products have been extracted consists primarily of ethane and methane.

 

Approximately 17 percent of the commercial grade propane produced at Enogex’s plants is sold on the local market. The balance of propane and the other NGLs produced by Enogex is delivered into pipeline facilities of a third party and transported to Conway, Kansas and 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 Calumet plant, is also sold under contract or on the spot market.

 

Enogex’s large diameter, rich gas gathering pipelines in western Oklahoma are configured such that natural gas from the Wheeler County area in the Texas Panhandle can flow to the Cox City, Thomas or Calumet gas processing plants. These large-diameter “super-header” gathering systems of Enogex provide gas routing flexibility for Enogex to optimize the economics of its gas processing and to improve system utilization and reliability.

 

Several of Enogex’s processing plants are currently operating at or near full capacity, such as the Cox City processing plant. As Enogex experiences increased growth in regions such as the Woodford Shale play, Enogex will evaluate the need to expand its processing plants in order to meet the growing needs of its producer customers.

 

Natural Gas Supply

 

As of December 31, 2008, approximately 3,278 wells and approximately 266 central receipt points were connected to Enogex’s system in Oklahoma and the Texas Panhandle area, areas that have experienced an increase in drilling activity and production. Enogex has secured significant areas of dedication from numerous customers active throughout Enogex’s areas of operations.

 

Customers and Contracts

 

Residue gas remaining after processing is primarily taken in kind by the producer customers into Enogex’s transportation pipelines for redelivery either (a) to on-system customers such as the electric generation facilities of OG&E, PSO and other independent power producers or (b) into downstream interstate pipelines. Enogex’s NGLs are typically sold to NGL marketers and end users, its condensate liquid production is typically sold to marketers and refineries and its propane is typically sold in the local market to wholesale distributors. Enogex’s key natural gas producer customers include Chesapeake Energy Marketing Inc., Apache Corporation, Devon Gas Services, L.P., Samson Resources Company and Cimarex Energy Co. During 2008, these five customers accounted for approximately 20 percent, 15 percent, nine percent, four percent and three percent, respectively, of Enogex’s gathering and processing volumes. During 2008, Enogex’s top ten natural gas producer customers accounted for approximately 65 percent of Enogex’s gathering and processing volumes.

 

Competition

 

Competition for natural gas supply is primarily based on efficiency and reliability of operations, customer service, proximity to existing assets, access to markets and pricing. Competition to gather and process non-dedicated gas is based on providing the producer with the highest total value, which is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Enogex believes it will be able to continue to compete effectively. Enogex competes with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. Enogex’s primary competitors are master limited partnerships who are active in its region, including Atlas Pipeline Partners, L.P., Crosstex Energy LP, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P., Hiland Partners, LP, 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. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (the “Competition Bill”) and H.B. 1920 (the “Lost and Unaccounted for Gas (“LUG”) Bill”). The Texas Competition Bill and LUG Bill contain provisions applicable to various natural gas industry participants, including gatherers. The Competition Bill allows the Railroad Commission of Texas (“TRRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings, if a complaint is filed and a determination is made that such a rate is necessary to remedy unreasonable discrimination. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to impose administrative penalties against purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It expands the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders for purposes of preventing waste in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. To date, neither the Competition Bill nor the LUG Bill has had a significant impact on Enogex’s operations. However, Enogex cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on its gathering operations 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 also may be subject to additional safety and operational regulations relating to the integrity, design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. Enogex cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

Recent System Expansions

 

Over the past several years, Enogex has initiated multiple organic growth projects. Currently, in Enogex’s gathering and processing business, organic growth capital expenditures are focused on expansions on the east side of Enogex’s gathering system, primarily in the Woodford Shale play in southeastern Oklahoma through the construction of new facilities and expansion of existing facilities and the interest in the joint venture, Atoka, and expansions on the west side of Enogex’s gathering system, primarily in the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is located in the Texas Panhandle.

 

Enogex is expanding in the Woodford Shale play and has several projects either completed or scheduled for completion in 2008, 2009 and 2010. For example, in December 2006, Enogex entered into a joint venture arrangement with Pablo Gathering, LLC, a subsidiary of Pablo Energy II, LLC, a Texas-based exploration and production company, which resulted in the formation of the Atoka joint venture. Atoka constructed, owns and/or operates a gathering system and processing plant and related facilities relating to production in certain areas in southeastern Oklahoma. The gathering system and processing plant were placed in service during the third quarter of 2007. Enogex owns a 50 percent membership interest in Atoka and acts as the managing member and operator of the facilities owned by the joint venture. The joint venture plans to expand its infrastructure in order to accommodate an anticipated increase in production in the area which is expected to require additional compression and processing capacity, as well as additional suction, discharge and well connect pipe. The current expansion project, including timing, is still under development. The capital expenditures associated with the expansion of Atoka are expected to be approximately $20 million. In addition, in order to accommodate the increased drilling activity in Canadian County, Oklahoma, Enogex plans to add approximately six miles of 12-inch steel pipe and another 10 MMcf/d of compression capacity to Enogex’s Grandview gathering project in 2009.  The capital expenditures associated with the additional pipe and compression capacity are expected to be approximately $9 million.

 

In February 2008, Enogex completed construction of a new 20-mile pipeline project that connects Enogex’s Hughes, Coal and Pittsburgh county gathering system with the 30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex mainline pipeline to Wilburton, Oklahoma.  The gathering project created additional gathering capacity of 75 MMcf/d for customers desiring low-pressure services. The pipeline is complemented by approximately 16,000 horsepower of new gathering compression which was completed in the third quarter of 2008. Also, Enogex is planning to add approximately 16 miles of 20-inch steel pipe and 60 MMcf/d of additional treating facilities.  Under the assumed operating conditions, the gathering pipe is expected to have throughput capacity of approximately 300 MMcf/d and is expected to be in

 

17

 

 

service by June 2009. The capital expenditures associated with the additional pipe and treating facilities are expected to be approximately $20 million.

 

In August 2006, Enogex completed a project to expand its gathering pipeline capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas area of the Texas Panhandle that has allowed Enogex to benefit from growth opportunities in that marketplace. Since the pipeline was put in service, Enogex has completed the construction of five new gas gathering compressor stations totaling approximately 26,500 horsepower of compression, and several miles of gathering pipe, including a new 16-inch line that extends the original pipeline project an additional 20 miles to the west.  Enogex is continuing to expand in the Wheeler and Hemphill counties in Texas and expects to add another 16,000 horsepower of low pressure compression to the Wheeler area by October 2009.

 

Technology Improvements

 

Enogex continues to upgrade its data and information systems in order to improve operational efficiencies and increase profitability of its business and that of its customers.

 

 

Safety and Health Regulation

 

Enogex is subject to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas within ten years. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

 

A four-mile portion of Enogex’s pipeline is also subject to regulation by the DOT under the Accountable Pipeline and Safety Partnership Act of 1996 (the “Hazardous Liquid Pipeline Safety Act”) and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of liquid pipeline facilities. The Hazardous Liquid Pipeline Safety Act covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the U.S. Secretary of Transportation. These regulations include potential fines and penalties for violations. Enogex believes that it is in material compliance with these Hazardous Liquid Pipeline Safety Act regulations.

 

States may be preempted by Federal law from solely regulating pipeline safety but may assume responsibility for enforcing Federal intrastate pipeline regulations and inspection of intrastate pipelines. In the State of Oklahoma, the OCC’s Transportation Division, acting through the Pipeline Safety Department, administers the OCC’s intrastate regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipeline. The OCC develops regulations and other approaches to assure safety in design, construction, testing, operation, maintenance and emergency response to pipeline facilities. The OCC derives its authority over intrastate pipeline operations through state statutes and certification agreements with the DOT. A similar regime for safety regulation is in place in Texas and administered by the Texas Railroad Commission. Enogex anticipates that it should be able to comply with currently existing state laws and regulations applicable to pipeline safety without incurring material costs. Enogex’s natural gas pipelines have inspection and compliance programs designed to maintain compliance with pipeline safety and pollution control requirements.

 

  

In addition, Enogex is subject to a number of Federal and state laws and regulations, including OSHA and comparable state statutes, whose purpose is to protect the safety and health of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in Enogex’s operations and that this information be provided to employees, state and local government authorities and citizens. Enogex is also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Enogex has an internal program of inspection designed to monitor and enforce compliance with worker safety and health requirements. Enogex believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

 

MARKETING - OERI

 

General

 

On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Enogex has historically utilized, and is expected to continue to utilize, OERI for natural gas marketing, hedging, risk management and other related activities. For the years ended December 31, 2006, 2007 and 2008, OERI recorded revenues from Enogex of approximately $107.1 million, $95.2 million and $41.7 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2006, 2007 and 2008, Enogex recorded revenues from OERI of approximately $291.9 million, $304.3 million and $307.2 million, respectively, for the sale, at market rates, of natural gas. Enogex has paid, and is expected to continue to pay, certain fees to OERI for providing natural gas marketing, hedging, risk management and other related services. OERI pays Enogex a fee for certain back office functions and administrative services.

 

OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas from suppliers and reselling to pipelines, local distribution companies and end-users, including the electric generation sector. The geographic scope of marketing efforts has been focused largely in the mid-continent area of the United States. These markets are natural extensions of OERI’s business on the Enogex system. OERI contracts for pipeline capacity with Enogex and other pipelines to access multiple interconnections with the interstate pipeline system network that moves natural gas from the production basins primarily in the south central United States to the major consumption areas in Chicago, New York and other north central and mid-Atlantic regions of the United States.

 

OERI primarily participates in both intermediate-term markets (less than three years) and short-term “spot” markets for natural gas. Although OERI continues to increase its focus on intermediate-term sales, short-term sales of natural gas are expected to continue to play a critical role in the overall strategy because they provide an important source of market intelligence as well as an important portfolio balancing function. OERI’s average daily sales volumes decreased from approximately 0.7 Bcf in 2007 to approximately 0.6 Bcf in 2008.  This reflects selective deal execution to assure adequate margin in light of credit and other risks in the current commodity price and credit environment. OERI’s risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. The Company follows a policy of hedging price risk on gas purchases or sales contracts entered into by OERI by buying and selling natural gas futures contracts on the New York Mercantile Exchange futures exchange and other derivatives in the over-the-counter market, subject to daily and monthly trading stop loss limits of $2.5 million and daily value-at-risk limits of $1.5 million in accordance with corporate policies.            

 

Competition

 

OERI competes in marketing natural gas with major integrated oil companies, marketing affiliates of major interstate and intrastate pipelines and commercial banks, national and local natural gas brokers, marketers and distributors for natural gas supplies. Competition for natural gas supplies is based primarily on reputation, credit support, the availability of gathering and transportation to high-demand markets and the ability to obtain a satisfactory price for the producer’s natural gas. Competition for sales to customers is based primarily upon reliability, services offered and the price of delivered natural gas.

 

For the year ended December 31, 2008, approximately 65.0 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers, of which approximately 26.0 percent was with affiliates of OERI. The remaining 35.0 percent of service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2008, approximately 64.0 percent of the payment exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services (“Standard & Poor’s”) and approximately 1.7 percent having less than investment

 

grade ratings. The remaining 34.3 percent of OERI’s exposure is with privately held companies, municipals or cooperatives that were not rated by Standard & Poor’s. OERI applies internal credit analyses and policies to these non-rated companies.

 

Regulation

 

The price at which OERI buys and sells natural gas and NGLs is currently not subject to Federal regulation and, for the most part, is not subject to state regulation. However, with regard to OERI’s physical purchases and sales of these energy commodities, and any related hedging activities that it undertakes, OERI is required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (“CFTC”). The FERC and CFTC hold substantial enforcement authority under the anti-market manipulation laws and regulations, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should OERI violate the anti-market manipulation laws and regulations, it could also be subject to related third party damage claims by, among other, marketers, royalty owners and taxing authorities.

 

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 as well as the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E’s and Enogex’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment. OG&E and Enogex handle some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”) and comparable state statutes, prepare and file reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtain permits pursuant to the Federal Clean Air Act and comparable state air statutes.

 

OG&E and Enogex believe that their operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing Federal, state and local environmental laws and regulations will not have a material adverse effect on their business, consolidated financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, OG&E and Enogex cannot assure that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause it to incur significant costs. Approximately $1.6 million of the Company’s capital expenditures budgeted for 2009 are to comply with environmental laws and regulations, of which approximately $1.0 million and $0.6 million are related to OG&E and Enogex, respectively. Approximately $32.1 million of the Company’s capital expenditures budgeted for 2010 are to comply with environmental laws and regulations, of which approximately $31.5 million and $0.6 million are related to OG&E and Enogex, respectively. It is estimated that OG&E’s and Enogex’s total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $35.7 million and $4.3 million, respectively, during 2009 as compared to approximately $37.1 million and $3.6 million, respectively, during 2008. Management continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position it in a competitive market. See Note 15 of Notes to Consolidated Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.

 

Hazardous Waste

 

OG&E’s and Enogex’s operations generate hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 (“RCRA”) as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste.

 

 

 

For OG&E, these laws impose strict “cradle to grave” requirements on generators regarding their treatment, storage and disposal of hazardous waste. OG&E routinely generates small quantities of hazardous waste throughout its system that include, but are not limited to, waste paint, spent solvents, rechargeable batteries and mercury-containing lamps. These wastes are treated, stored and disposed off-site at facilities that are permitted to manage them. Occasionally, larger quantities of hazardous wastes are generated as a result of power generation-related activities and these larger quantities are managed either on-site or off-site. Nevertheless, through its waste minimization efforts, the majority of OG&E’s facilities remain conditionally exempt small quantity generators of hazardous waste.

 

For Enogex, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other waste associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial waste such as paint waste, waste solvents and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

 

Site Remediation

 

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”) (also known as “Superfund”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Because OG&E and Enogex utilize various products and generate wastes that either are or otherwise contain CERCLA hazardous substances, OG&E and Enogex could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause any significant impact to OG&E or Enogex.

 

Enogex currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, compression and processing of natural gas. Although Enogex used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by Enogex. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbon or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Enogex could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators) or remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills).

 

Air Emissions

 

OG&E’s and Enogex’s operations are subject to the Federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E and Enogex obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, install emission control equipment or subject OG&E and Enogex to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. OG&E and Enogex likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions. See Note 15 of Notes to Consolidated Financial Statements for a discussion of potentially significant environmental capital expenditures related to air emissions.

 

Water Discharges

 

OG&E’s and Enogex’s operations are subject to the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state

 

 

 

and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from OG&E’s and Enogex’s power plants, pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations. See Note 15 of Notes to Consolidated Financial Statements for a discussion of water intake matters.

 

Other Laws and Regulations

 

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. For instance, at least nine states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York and Vermont) and five states in the West (Arizona, California, New Mexico, Oregon and Washington) have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (such as cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. The enactment of climate control laws or regulations that restrict emissions of greenhouse gases in areas in which OG&E and Enogex conduct business could have an adverse effect on their operations and demand for their services or products. OG&E reports quarterly its carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions.  Enogex is a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions.

 

FINANCE AND CONSTRUCTION

 

Future Capital Requirements

 

Capital Requirements

 

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and Enogex. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. However, OGE Energy’s and OG&E’s ability to access the commercial paper market was adversely impacted by the market turmoil that began in September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and OG&E utilized borrowings under their revolving credit agreements which bear a higher interest rate and a minimum 30-day maturity compared to commercial paper which had historically been available at lower interest rates and on a daily basis. OGE Energy and OG&E expect to repay the borrowings under their revolving credit agreements and begin utilizing commercial paper in the commercial paper market when available. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital requirements.

 

Capital Expenditures

 

The Company’s current 2009 to 2014 construction program includes continued investment in OG&E’s distribution, generation and transmission system and Enogex’s transportation, storage, gathering and processing assets. The Company’s current estimates of capital expenditures, are approximately: 2009 - $872.0 million, 2010 - $593.4 million, 2011 - $681.0 million, 2012 - $652.8 million, 2013 - $692.3 million and 2014 - $607.3 million. These capital expenditures include expenditures related to: (i) the proposed transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma, (ii) OGE Energy’s portion of the proposed transmission projects as part of a newly formed transmission joint venture, (iii) OG&E’s proposed 101 MW OU Spirit wind power project in western Oklahoma, (iv) OG&E’s proposed system hardening plan and (v) OG&E’s transmission/substation SPP project (see Note 16 of Notes to Consolidated Financial Statements for a further discussion). These capital expenditures exclude any environmental expenditures associated with Best Available

 

 

 

Retrofit Technology (“BART”) requirements. As discussed in Note 15 of Notes to Consolidated Financial Statements, due to comments from the EPA that OG&E’s proposed initial BART compliance plan would not satisfy the applicable requirements, OG&E completed additional analysis. On May 30, 2008, OG&E filed the results with the Oklahoma Department of Environmental Quality (“ODEQ”) for the affected generating units. In the May 30, 2008 filing, OG&E indicated its intention to install low nitrogen oxide (“NOX”) combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. OG&E believes that these control measures will achieve visibility improvements in a cost-effective manner. OG&E did not propose the installation of scrubbers at its four coal-fired generating units because OG&E concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective.  OG&E previously reported an expectation that a compliance plan would be approved by the EPA by December 31, 2008; however, submission of the overall compliance plan by the ODEQ (which will include OG&E’s compliance plan previously submitted to the ODEQ) has been delayed and the current timing of the EPA approval cannot be reasonably predicted. In a letter dated November 4, 2008, the EPA notified the ODEQ that they had completed their review of BART applications for all affected sources in Oklahoma, which included OG&E.   The EPA did not approve or disapprove the applications, however, additional information was requested from the ODEQ by the EPA regarding OG&E’s plan.  The Company cannot predict what action the EPA or the ODEQ will take in response to OG&E’s May 30, 2008 filing or the November 4, 2008 letter from the EPA. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by OG&E with a reasonable degree of certainty. Due to this uncertainty regarding BART costs, the Company has excluded any BART costs from the foregoing capital expenditure estimates. OG&E also has approximately 440 MWs of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.

 

Pension and Postretirement Benefit Plans

 

During both 2008 and 2007, the Company made contributions to its pension plan of approximately $50.0 million to help ensure that the pension plan maintains an adequate funded status. During 2009, the Company may contribute up to $50.0 million to its pension plan. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s pension and postretirement benefit plans.

 

Future Sources of Financing

 

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and proceeds from the sales of common stock to the public through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings will be adequate over the next three years to meet anticipated cash needs. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

 

Short-Term Debt

 

Short-term borrowings generally are used to meet working capital requirements. At December 31, 2008, the Company had approximately $298.0 million in outstanding borrowings under its revolving credit agreements and no outstanding commercial paper borrowings. At December 31, 2007, the Company had approximately $295.0 million in outstanding commercial paper borrowings and no outstanding borrowings under its revolving credit agreements. OGE Energy’s and OG&E’s ability to access the commercial paper market was adversely impacted by the market turmoil that began in September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and OG&E utilized borrowings under their revolving credit agreements, which generally bear a higher interest rate and a minimum 30-day maturity compared to commercial paper, which has historically been available at lower interest rates and on a daily basis. However, in late 2008, OGE Energy’s and OG&E’s revolving credit borrowings had a lower interest rate than commercial paper due to disruptions in the credit markets. In December 2008, OG&E repaid the outstanding borrowings under its revolving credit agreement with a portion of the proceeds received from the issuance of long-term debt in December. OG&E intends to utilize commercial paper in the commercial paper market when available. OGE Energy expects to repay the borrowings under its revolving credit agreement and begin utilizing the commercial paper market when available. Also, OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2009 and ending December 31, 2010. See Note 12 of Notes to the Consolidated Financial Statements for a discussion of the Company’s short-term debt activity.

 

 

 

Long-Term Debt

 

On April 1, 2008, Enogex entered into a $250 million unsecured five-year revolving credit facility. Subject to certain limitations, the facility provides Enogex with the option, exercisable annually, to extend the maturity of the facility for an additional year and, upon the expiration of the revolving term, an option to convert the outstanding balance under the facility to a one-year term loan. The facility provides the option for Enogex to increase the borrowing limit by up to an additional $250 million (to a maximum of $500 million) upon the agreement of the lenders (or any additional lender) and the satisfaction of other specified conditions. This bank facility is available to provide revolving credit borrowings. At December 31, 2008, Enogex had approximately $120.0 million outstanding under this facility. These borrowings are not expected to be repaid within the next 12 months, therefore, they are classified as long-term debt for financial reporting purposes.

 

EMPLOYEES

 

The Company and its subsidiaries had 3,441 employees at December 31, 2008.

 

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

 

The Company’s web site address is www.oge.com. Through the Company’s web site under the heading “Investors”, “SEC Filings,” the Company makes available, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.

 

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 Enogex LLC and its subsidiaries. In addition to the other information in this Annual Report on Form 10-K and other documents filed by us and/or our subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

 

REGULATORY RISKS

 

Our profitability depends to a large extent on the ability of OG&E to fully recover its costs from its customers and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.

 

We are subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences our operating environment and OG&E’s ability to fully recover its costs from utility customers. With rising fuel costs, recoverability of under recovered amounts from our customers is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to fully recover costs related to providing energy and utility services to our customers.

 

In recent years, the regulatory environments in which we operate have received an increased amount of public attention. It is possible that there could be changes in the regulatory environment that would impair our ability to fully recover costs historically absorbed by our customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. Although OG&E has several rate proceedings currently pending, and expects to file a general rate case in Oklahoma shortly, 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 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 regulation by the OCC and the APSC, in addition to the FERC. Exposure to inconsistent state and Federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate may harm our financial position and results of operations.

 

Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, consolidated financial position, or liquidity.

 

We are subject to extensive Federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife mortality, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.

 

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 able to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.

 

There also is growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide.  This concern has led to increased interest in legislation at the Federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Federal Clean Air Act.  Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.

 

Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases.  However, government officials in these states have declared support for state and Federal action on climate change issues.  OG&E reports quarterly its carbon dioxide emissions from its generating stations under the EPA’s acid rain program and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions.  Enogex is a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. See Note 15 of Notes to Consolidated Financial Statements for a further discussion.

 

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.

 

Our business plan for OG&E calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E’s facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment. This could adversely affect our results of operations and financial position. While we may seek to limit the impact of any denied recovery by

 

 

 

attempting to reduce the scope of our capital investment, there can no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

 

Our planned capital investment program coincides with a material increase in the historic prices of the fuels used to generate electricity. Many of our jurisdictions have fuel clauses that permit us to recover these increased fuel costs through rates without a general rate case. While prudent capital investment and variable fuel costs each generally warrant recovery, in practical terms our regulators could limit the amount or timing of increased costs that we would recover through higher rates. Any such limitation could adversely affect our results of operations and financial position.

 

The construction by Enogex of additions or modifications to its existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond Enogex’s control and may require the expenditure of significant amounts of capital. These projects, once undertaken, may not be completed on schedule or at the budgeted cost, or at all. Moreover, Enogex’s revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if Enogex expands 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 constructing new pipelines. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and Enogex may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, Enogex’s consolidated financial position, results of operations and cash flows could be adversely affected.

 

The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.

 

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization (“RTO”) and has transferred operational authority (but not ownership) of OG&E’s transmission facilities to the SPP RTO. The SPP RTO implemented a regional energy imbalance service market on February 1, 2007. OG&E has participated, and continues to participate, in the SPP energy imbalance service market to aid in the optimization of its physical assets to serve OG&E’s customers.  OG&E has not participated in the SPP energy imbalance service market for any speculative trading activities.  The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Consolidated Financial Statements. OG&E’s revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP RTO.

 

Increased competition resulting from restructuring efforts could have a significant financial impact on us and OG&E and consequently decrease our revenue.

 

We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our consolidated financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our consolidated financial position, results of operations or cash flows.

 

A change in the jurisdictional characterization of some of Enogex’s assets by Federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

 

 

Enogex’s natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938, but the FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking and capacity release and its promotion of market centers, may indirectly affect intrastate markets. In recent years, the FERC has aggressively pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue these same objectives as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business.

 

Enogex’s natural gas transportation and storage operations are subject to regulation by the FERC pursuant to Section 311 of the NGPA, which could have an adverse impact on its ability to establish transportation and storage rates that would allow it to recover the full cost of operating its transportation and storage facilities, including a reasonable return, and an adverse impact on its consolidated financial position, results of operations or cash flows.

 

The FERC has jurisdiction over transportation rates charged by Enogex for transporting natural gas in interstate commerce under Section 311 of the NGPA. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every three years. Enogex is currently charging rates for its Section 311 transportation services that were deemed fair and equitable under a rate settlement approved by the FERC for the period from January 1, 2005 until December 31, 2007. On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for 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 additionally filed protests. The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action. By order of February 28, 2008, the FERC extended the time period in this docket by 120 days and encouraged the parties to settle. No action has yet been taken by the FERC and the parties are currently in settlement negotiations. Enogex cannot predict what the settlement terms will be or, if not settled, what determinations the FERC will make with respect to this proceeding or what impact, if any, those determinations might have on Enogex’s ability to establish transportation rates that would allow Enogex to recover the full cost, including a reasonable return, of operating its transportation facilities and that portion of its storage capacity used in support of transportation services. Accordingly, Enogex cannot predict what impact, if any, such determinations could have on its consolidated financial position, results of operations or cash flows.

 

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 also may be or become subject to safety and operational regulations relating to the integrity, design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on Enogex’s operations, but Enogex could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect Enogex’s business. Any such state regulation could have an adverse impact on Enogex’s business and its consolidated financial position, results of operations or cash flows.

 

Enogex may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

 

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines. The regulations require operators to:

 

 

 

	•	maintain a quality assurance process and management-of-change process; and
	•	establish a communication plan that addresses safety concerns raised by the DOT and state agencies, including the periodic submission of performance documents to the DOT.

 

During 2008, Enogex incurred approximately $7.9 million of capital expenditures and operating costs to implement its pipeline integrity management program along certain segments of its natural gas pipelines. Enogex currently estimates that it will incur capital expenditures and operating costs of approximately $35.7 million between 2009 and 2013 in connection with its pipeline integrity management program. The estimated capital expenditures and operating costs include Enogex’s estimates for the assessment, remediation, prevention or other mitigation that may be determined to be necessary as a result of the integrity management program. At this time, we cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity assessment that is required by the rule. Enogex will continue its pipeline integrity program to assess, remediate and maintain the integrity of its pipelines. The results of these activities could cause Enogex to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

 

Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, consolidated financial position, cash flows and access to capital.

 

As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under an increased amount of public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, consolidated financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.

 

We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.  

 

We are subject to substantial regulation from Federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain numerous permits, approvals and certificates from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.

 

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with significant monetary penalties. The FERC has approved the North American Electric Reliability Corporation (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. It is the Company’s intent to comply with all applicable reliability rules and expediently correct a violation should it occur. The Company is subject to a NERC readiness evaluation and compliance audit every three years 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

  

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these agreements will fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Coal delivery may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers. In addition, as agreements with our suppliers expire, we may not be able to enter into new agreements for coal delivery on equivalent terms.

 

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the August 14, 2003 black-out in portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our consolidated financial position and results of operations.

 

Economic conditions could negatively impact our business.

 

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.

 

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.

 

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our consolidated financial position, results of operations and cash flows.  

 

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the electric utility and natural gas midstream industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.

 

Enogex does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

 

Enogex does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Enogex obtains the rights to construct and operate its pipelines on land owned by third parties and governmental agencies sometimes for a specific period of time. A loss of these rights, through Enogex’s inability to renew right-of-way contracts or otherwise, could cause Enogex to cease operations temporarily or permanently on the affected land, increase costs related to 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

  

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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 NGL prices are volatile, and changes in these prices could adversely affect Enogex’s results of operations and cash flows.

 

Enogex is subject to risks due to frequent and often substantial fluctuations in commodity prices. Enogex’s results of operations and cash flows could be adversely affected by volatility in natural gas and NGL prices. Enogex’s gathering and processing margins generally improve when NGL prices are high relative to the price of natural gas. In the past, the prices of natural gas and NGLs have been extremely volatile, and Enogex expects this volatility to continue. With respect to natural gas, the mid-continent prices for natural gas, as represented by the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract in 2006 ranged from a high of $8.76 per MMBtu to a low of $3.54 per MMBtu. In 2007, the same index ranged from a high of $6.82 per MMBtu to a low of $4.73 per MMBtu. In 2008, the same index ranged from a high of $11.07 per MMBtu to a low of $2.81 per MMBtu. Natural gas prices reached relatively high levels in mid-2008 due to the impact of rising demand for natural gas but have returned to the near $4.50 per MMBtu level due to a rapid decline in demand for natural gas. With respect to NGLs, the mid-continent prices for propane, for example, as represented by the average of the Oil Price Information Service daily average posting at the Conway, Kansas market, in 2007 ranged from a high of $1.52 per gallon to a low of $0.87 per gallon. In 2008, the same index ranged from a high of $1.76 per gallon to a low of $0.70 per gallon. Enogex’s future revenue and cash flows may be materially adversely affected if the midstream industry experiences significant, prolonged deterioration below general price levels experienced in recent years.

 

Some factors that affect prices of natural gas and NGLs are beyond our control and changes in these prices could adversely affect Enogex’s and OERI’s revenue and cash flows.

 

The markets and prices for natural gas and NGLs depend upon factors beyond Enogex’s and OERI’s control and changes in these prices could adversely affect Enogex’s and OERI’s revenue and cash flows. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquified natural gas and NGLs, actions taken by foreign oil and gas producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

 

Enogex’s “keep-whole” natural gas processing arrangements and “percent-of-proceeds” and “percent-of-liquids” natural gas processing agreements expose it to risks associated with fluctuations associated with the price of natural gas and NGLs, which could adversely affect Enogex’s revenue and cash flows.

 

Enogex’s keep-whole natural gas processing arrangements, which constituted approximately 23 percent of its gross margin and accounted for approximately 54 percent of its natural gas processed volumes during 2008, expose it to fluctuations in the pricing spreads between NGL prices and natural gas prices. Keep-whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis by replacing the Btu’s of the NGLs extracted from the production stream with Btu’s of natural gas. Therefore, if natural gas prices increase and NGL prices do not increase by a corresponding amount, the processor has to replace the Btu’s of natural gas at higher prices and processing margins are negatively affected.

 

Enogex’s percent-of-proceeds and percent-of-liquids natural gas processing agreements constituted approximately nine percent of its gross margin and accounted for approximately 36 percent of its natural gas processed volumes during 2008. 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 our and Enogex’s business and results of operations and cash flows.

 

Enogex’s gathering and transportation systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, Enogex’s cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, Enogex must continually obtain new natural gas supplies. The primary factors affecting Enogex’s ability to obtain new supplies of natural gas and attract new customers to its assets depends in part on the level of successful drilling activity near these systems, Enogex’s ability to compete for volumes from successful new wells and Enogex’s ability to expand capacity as needed. If Enogex is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on its gathering, processing and transportation facilities would decline, which could have a material adverse effect on its business, results of operations and cash flows.

 

Enogex’s businesses are dependent, in part, on the drilling decisions of others.

 

All of Enogex’s businesses are dependent on the continued availability of natural gas production. Enogex does not have control over the level of drilling activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. The primary factor that impacts drilling decisions is natural gas prices. Natural gas prices reached relatively high levels in mid-2008 due to the impact of rising demand for natural gas but have returned to the near $4.50 per MMBtu level due to a rapid decline in demand for natural gas. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by Enogex’s gathering, processing and transportation facilities, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, access to credit, the ability of producers to obtain necessary drilling and other governmental permits, costs of steel and other commodities, geological considerations, demand for hydrocarbons, the level of reserves, other production and development costs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by Enogex’s assets, producers may choose not to develop those reserves.

 

Enogex and OERI engage in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on their earnings and cash flows.

 

Enogex and OERI are exposed to changes in commodity prices in their operations. To minimize the risk of commodity prices, Enogex and OERI may enter into physical forward sales or financial derivative contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas. However, financial derivative contracts do not eliminate the risk of market supply shortages, which could result in Enogex’s and OERI’s inability to fulfill contractual obligations and incurrence of significantly higher energy or fuel costs relative to corresponding sales contracts. Enogex and OERI marks their derivative contracts to estimated fair market value. When available, market prices are utilized in determining the value of natural gas and related derivative commodity instruments. For longer-term positions, which are limited to a maximum of 60 months, and certain short-term positions for which market prices are not available, models based on forward price curves are utilized. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

 

Enogex and OERI engage in cash flow hedge transactions to manage commodity risk. Hedges of anticipated transactions are documented as cash flow hedges pursuant to Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and are executed based upon management-established price targets. Enogex and OERI utilize hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and storage natural gas, percent-of-liquids and keep-whole natural gas and NGL hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue

 

 

to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

 

As a result of the factors discussed above, Enogex’s and OERI’s hedging activities may not be as effective as intended in reducing the volatility of its cash flows. In addition, 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 properly followed or do not work as planned. The steps taken to monitor Enogex’s and OERI’s hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

 

Enogex’s results of operations and cash flows may be adversely affected by risks associated with its hedging activities.

 

Enogex has instituted a hedging program that is intended to reduce the commodity price risk associated with Enogex’s keep-whole and percent-of-liquids arrangements. Enogex intends to hedge approximately 70 percent of its NGL volumes when market conditions dictate. As of December 31, 2008, Enogex had hedged approximately 65 percent of its expected non-ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2009 through 2011, including approximately 86 percent for 2009, 77 percent for 2010 and 37 percent for 2011. As of December 31, 2008, Enogex had not hedged any of its expected ethane volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2009. Enogex has the option to reject ethane if processing it is not economical. Management will continue to evaluate whether to enter into any new hedging arrangements, and there can be no assurance that Enogex will enter into any new hedging arrangements. Also, Enogex may seek in the future to further limit its exposure to changes in natural gas and NGL commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms. To the extent Enogex hedges its commodity price and interest rate exposures, Enogex will 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 NGL supply. During 2008, Chesapeake Energy Marketing Inc., Apache Corporation, Devon Gas Services, L.P., Samson Resources Company and Cimarex Energy Co. accounted for approximately 52 percent of Enogex’s natural gas and NGL supply. The loss of the natural gas and NGL volumes supplied by these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on Enogex’s consolidated financial position, results of operations and cash flows.

 

Enogex depends on two customers for a significant portion of its firm intrastate transportation and storage services. The loss of, or reduction in volumes from, either of these customers could result in a decline in Enogex’s transportation and storage services and its consolidated financial position, results of operations or cash flows.

 

     Enogex provides firm intrastate transportation and storage services to several customers on its system. Enogex’s major customers are OG&E and PSO, which is the second largest electric utility in Oklahoma and serves the Tulsa market. As part of the no-notice load following contract with OG&E, Enogex provides natural gas storage services for OG&E. Enogex provides gas transmission delivery services to all of PSO’s natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. During 2006, 2007 and 2008, revenues from Enogex’s firm intrastate transportation and storage contracts were approximately $98.1 million, $103.9 million and $104.4 million, respectively, of which $47.6 million, $47.4 million and $47.5 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million and $15.3 million, respectively, was attributed to PSO. Enogex’s current contract with PSO expires January 1, 2013, unless extended. The stated term of Enogex’s current contract with OG&E expires April 30, 2009, but the contract will remain in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2009, the contract will remain in effect at least through April 30, 2010. 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.

 

Enogex may not be successful in balancing its purchases and sales of natural gas and NGLs, which would increase its exposure to commodity price risk.

 

In the normal course of business, Enogex purchases or retains from producers and other customers some of the natural gas and NGLs that flow through its natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. Enogex may not be successful in balancing its purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause Enogex’s purchases and sales to be unbalanced. If Enogex’s purchases and sales are unbalanced, it will face increased exposure to commodity price risk and Enogex could have increased volatility in its operating income 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:

 

 

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 defined benefit retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2008, we expect to continue to make future contributions to maintain required funding levels; however, as our plans have experienced adverse market returns on investments in 2008 due to the recent turmoil in the financial markets, this could cause our future contributions to rise substantially over historical levels. It is our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.

 

On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it alters the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions, introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants.

 

Many of the changes enacted as part of the Pension Protection Act were required to be implemented as of the first plan year beginning in 2008. While the Company generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. See Note 13 of Notes to Consolidated Financial Statements for a further discussion of changes made to the Company’s plans in order to comply with the Pension Protection Act.

 

All employees hired prior to February 1, 2000 participate in defined benefit and 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 assumptions are outside of our control.

 

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, consolidated financial position, or liquidity.

 

We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.

 

Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility and natural gas pipeline industry. The median age of utility and natural gas pipeline workers is significantly higher than the national average. Over the next three years, approximately 27 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, 2008, the Company and its subsidiaries had outstanding indebtedness and other liabilities of approximately $4.6 billion. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due on our indebtedness or to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of our subsidiaries on the assets of these subsidiaries will have priority over our claims generally (except to the extent that we may be a creditor of the subsidiaries and our claims are recognized) and claims by our shareowners.

 

In addition, as discussed above, OG&E is regulated by state utility commissions in Oklahoma and Arkansas which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions attempt to impose restrictions on the ability of OG&E to pay dividends to us, it could adversely affect our ability to continue to pay dividends.

 

Certain provisions in our charter documents and rights plan have anti-takeover effects.

 

Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporations statute, may have the effect of delaying, deferring or preventing a change in control of the Company. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders’ meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of the Company without stockholder approval, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder’s best interest. Additionally, our rights plan may also delay, defer or prevent a change of control of the Company. Under the rights plan, each outstanding share of common stock has one half of a right attached that trades with the common stock. Absent prior action by our board of directors to redeem the rights or amend the rights plan, upon the consummation of certain acquisition transactions, the rights would entitle the holder thereof (other than the acquiror) to purchase shares of common stock at a discounted price in a manner designed to result in substantial dilution to the acquiror. These provisions could limit the price that investors might be willing to pay in the future for shares of our common stock, discourage third party bidders from bidding for us and could significantly impede the ability of the holders of our common stock to change our management.

 

We and our subsidiaries may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.

 

The terms of the indentures governing our debt securities do not fully prohibit us or our subsidiaries from incurring additional indebtedness. If we or our subsidiaries are in compliance with the financial covenants set forth in our revolving credit agreements and the indentures governing our debt securities, we and our subsidiaries may be able to incur substantial additional indebtedness. If we or any of our subsidiaries incur additional indebtedness, the related risks that we and they now face may intensify.

 

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.

 

We cannot assure that any of our current ratings or the ratings of our subsidiaries’ will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruption as experienced with the recent market turmoil. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, would require us to post cash collateral or letters of credit. Also, any downgrade below investment grade at OERI could require us to issue additional guarantees to support some of OERI’s marketing operations.  

 

Any negative change in OERI’s creditworthiness could adversely affect Enogex’s ability to engage in hedging transactions or adversely affect the prices and terms upon which hedging transactions occur.

 

 

 

Enogex historically has conducted its hedging activities with OERI as its counterparty. OERI, in turn, has engaged in back-to-back hedging transactions with third parties. The willingness of those third parties to serve as counterparties on OERI’s hedging transactions depends on OERI’s creditworthiness. Any negative change in OERI’s creditworthiness could adversely affect OERI’s and Enogex’s ability to enter into hedging transactions, or the prices and terms upon which such transactions may be effected.

 

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:

 

 

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 ten generating stations with an aggregate capability of approximately 6,781 MWs at December 31, 2008. The following table sets forth information with respect to OG&E’s electric generating facilities, all of which are located in Oklahoma.

 

(A)  2008 Capacity Factor = 2008 Net Actual Generation / (2008 Net Maximum Capacity (Nameplate Rating in         MWs) x Period Hours (8,760 Hours)).

(B)  Peaking units, which are used when additional capacity is required, are also necessary to meet the SPP        reserve margins.

(C) The original units at the Redbud Facility were installed in 2003. In September 2008, OG&E purchased a 51        percent ownership interest in the Redbud Facility. The capacity factor for the Redbud Facility shown above        represents the capacity factor since OG&E’s ownership.

(D) Represents OG&E’s 77 percent ownership interest in the McClain Plant.

 

 

At December 31, 2008, OG&E’s transmission system included: (i) 48 substations with a total capacity of approximately 9.9 million kilo Volt-Amps (“kVA”) and approximately 4,029 structure miles of lines in Oklahoma; and (ii) seven substations with a total capacity of approximately 2.5 million kVA and approximately 259 structure miles of lines in Arkansas. OG&E’s distribution system included: (i) 348 substations with a total capacity of approximately 8.8 million kVA, 24,472 structure miles of overhead lines, 1,591 miles of underground conduit and 9,933 miles of underground conductors in Oklahoma; and (ii) 37 substations with a total capacity of approximately 1.0 million kVA, 1,901 structure miles of overhead lines, 162 miles of underground conduit and 651 miles of underground conductors in Arkansas.

 

OG&E owns approximately 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73101. In addition to its executive offices, OG&E owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, district offices, fleet and equipment service facilities, operation support and other properties.

 

Enogex

 

Enogex’s real property falls into two categories: (1) parcels that it owns in fee and (2) 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 continue to be held by 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, 2008, Enogex and its subsidiaries owned: (i) approximately 5,763 miles of intrastate natural gas gathering pipelines in Oklahoma and Texas; (ii) approximately 2,433 miles of intrastate natural gas transportation pipelines in Oklahoma and Texas; (iii) two natural gas storage facilities in Oklahoma operating at a working gas level of approximately 24 Bcf with approximately 650 MMcf/d of maximum withdrawal capacity and approximately 650 MMcf/d of injection capacity; and (iv) six operating natural gas processing plants, with a total inlet capacity of approximately 723 MMcf/d, a 50 percent interest in an additional natural gas processing plant with an inlet capacity of approximately 20 MMcf/d and two idle natural gas processing plants, all located in Oklahoma. The following table sets forth information with respect to Enogex’s active natural gas processing plants:

 

 

require additional office space as its business expands, Enogex believes that its existing facilities are adequate to meet its needs for the immediate future. In addition to its executive offices, Enogex owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, district offices, fleet and equipment service facilities, compressor station facilities, operation support and other properties.

 

During the three years ended December 31, 2008, the Company’s gross property, plant and equipment (excluding construction work in progress) additions were approximately $2.0 billion and gross retirements were approximately $271.3 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings and commercial paper), long-term borrowings and permanent financings. The additions during this three-year period amounted to approximately 26.2 percent of total property, plant and equipment at December 31, 2008.

 

Item 3. Legal Proceedings.

 

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with legal counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Consolidated Financial Statements. Except as set forth below and in Notes 15 and 16 of Notes to Consolidated Financial Statements, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

 

1.         United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges:  (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and Btu content) purchased from Federal and Indian lands which have resulted in the underreporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages:  (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

 

In qui tam actions, the Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.

 

The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal courts. The consolidated cases are now before the U.S. District Court for the District of Wyoming.

 

In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that OG&E and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.

 

On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and OG&E, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees on various bases on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on

 

 

 

December 5, 2007, the Company filed a notice of its intent to file a separate response brief, which the Company filed on January 11, 2008. Oral arguments were made to the Tenth Circuit on September 25, 2008.  No ruling was made on the oral arguments and the court took the case under advisement. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

 

2.         Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two of the Company’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of the Company’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

 

On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of the Company filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.

 

The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

 

3.         Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II). On May 12, 2003, the plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the Fourth Amended Petition of the Price I case. OG&E and Enogex Inc. were not named in this case, but two subsidiary entities of the Company were named in this case. The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

 

On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of the Company filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.

 

The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

 

          4.           Oklahoma Royalty Lawsuit. On July 22, 2005, Enogex along with certain other unaffiliated co-defendants was served with a purported class action which had been filed on February 7, 2005 by Farris Buser and other named plaintiffs in the District Court of Canadian County, Oklahoma. The plaintiffs own royalty interests in certain oil and gas producing

 

 

properties and allege they have been under-compensated by the named defendants, including Enogex and its subsidiaries, relating to the sale of liquid hydrocarbons recovered during the transportation of natural gas from the plaintiffs’ wells. The plaintiffs assert breach of contract, implied covenants, obligation, fiduciary duty, unjust enrichment, conspiracy and fraud causes of action and claim actual damages in excess of $10,000, plus attorneys’ fees and costs, and punitive damages in excess of $10,000. Enogex and its subsidiaries filed a motion to dismiss which was granted on November 18, 2005, subject to the plaintiffs’ right to conduct discovery and the possible re-filing of their allegations in the petition against the Enogex companies. On September 19, 2005, the co-defendants, BP America, Inc. and BP America Production Co. (collectively, “BP”), filed a cross claim against Products seeking indemnification and/or contribution from Products based upon the 1997 sale of a third-party interest in one of Products natural gas processing plants. On May 17, 2006, the plaintiffs filed an amended petition against Enogex and its subsidiaries. Enogex and its subsidiaries filed a motion to dismiss the amended petition on August 2, 2006. The hearing on the dismissal motion was held on November 20, 2006 and the court denied Enogex’s motion. Enogex companies filed an answer to the amended petition and BP’s cross claim on January 16, 2007. Based on Enogex’s investigation to date, the Company believes these claims and cross claims in this lawsuit are without merit and intends to continue vigorously defending this case.

 

          5.           Franchise Fee Lawsuit. On June 19, 2006, two OG&E customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on OG&E’s electric bills.  The plaintiffs claim that OG&E improperly charged sales tax based on franchise fee charges paid by its customers.  The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law.  OG&E’s motion for summary judgment was denied by the trial judge.  OG&E filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit.  In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC.   In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes OG&E to collect the challenged franchise fee charges. A procedural schedule and notice requirements for the matter were established by the OCC on December 4, 2008.   The OCC expects to hear arguments for a motion to dismiss on March 26, 2009.   OG&E believes that this case is without merit.

 

6.         Oxley Litigation. OG&E has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma.  This case has been pending for more than 11 years.  The plaintiffs’ alleged that OG&E breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs’ in amounts set forth in the contracts.  The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages  (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. OG&E expects the arbitration to occur in the first half of 2009. While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

 

Item 4. Submission of Matters to a Vote of Security Holders.

 

 

 

 

 

 

Executive Officers of the Registrant.

 

The following persons were Executive Officers of the Registrant as of February 13, 2009:

 

Name	Age	Title

 

 

 

Scott Forbes

51

Controller, Chief Accounting Officer and Interim Chief

 

 

 

 

 

 

Jean C. Leger, Jr.

50

Vice President - Utility Operations - OG&E

 

Cristina F. McQuistion

44

Vice President - Process and Performance Improvement -

 

 

 

 

 

 

 

 

 

 

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Harris, Forbes, Grasty, Huneryager, Johnston, Nutall, Renfrow, Myers, Peace and Rhea and Ms. Brockman and Ms. McQuistion are also officers of OG&E.  Each officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders, currently scheduled for May 21, 2009.

 

 

 

The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:

 

Name	Business Experience

 

 

 

               

 

                                               

 

 

 

 

Name	Business Experience

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

 

The number of record holders of the Company’s Common Stock at December 31, 2008, was 22,705. The book value of the Company’s Common Stock at December 31, 2008, was $20.28.

 

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, from OERI, on OERI’s common stock, and from distributions paid by Enogex, on Enogex’s limited liability company interests. The Company’s ability to receive dividends on OG&E’s common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding and the covenants of OG&E’s certificate of incorporation and its debt instruments limiting the ability of OG&E to pay dividends. The Company’s ability to receive distributions on Enogex’s limited liability company interests is subject to the prior rights of existing and future holders of such limited liability company interests that may be outstanding and the covenants of Enogex’s debt instruments (including its credit facility) limiting the ability of Enogex to pay distributions.

 

 

Under OG&E’s certificate of incorporation, if any shares of its preferred stock are outstanding, dividends (other than dividends payable in common stock), distributions or acquisitions of OG&E common stock:

 

 

 

 

OG&E’s certificate of incorporation further provides that no dividend may be declared or paid on the OG&E common stock until all amounts required to be paid or set aside for any sinking fund for the redemption or purchase of OG&E cumulative preferred stock, par value $25 per share, have been paid or set aside. Currently, no shares of OG&E preferred stock are outstanding and no portion of the retained earnings of OG&E is presently restricted by these provisions.

 

Under Enogex’s current credit facility, Enogex generally may not make distributions if an event of default exists and otherwise may make monthly and quarterly distributions in amounts not to exceed the amount by which Enogex’s cash on hand exceeds its current and anticipated needs, including, without limitation, for operating expenses, debt service, acquisitions and a reasonable contingency reserve (as determined from time to time by Enogex’s management in accordance with Enogex’s operating agreement).

 

Issuer Purchases of Equity Securities

 

The shares indicated below represent shares of Company common stock purchased on the open market by the trustee for the Company’s Stock Ownership and Retirement Savings Plan and reflect shares purchased with employee contributions as well as the portion attributable to the Company’s matching contributions.

 

N/A – not applicable

 

 

 

 

Item 6. Selected Financial Data.

 

 

 

 

 

 

 

 

(A)  The Company adopted SFAS No. 123(R) using the modified prospective transition method, effective January 1, 2006, which required the Company to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award.

(B)  Amounts for 2005 and 2004 were restated for discontinued operations related to the sale of Enogex assets in May 2006, as discussed in Note 7 of Notes to Consolidated Financial Statements.

(C)  Includes net property, plant and equipment related to discontinued operations of approximately $169.3 million and $34.9 million during the years ended December 31, 2004 and 2005, respectively.

(D)  Amounts for years 2004 through 2006 have been restated to net price risk management assets and liabilities under master netting agreements in accordance with Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 39 (As Amended), “Offsetting of Amounts Related to Certain Contracts – an interpretation of Accounting Principles Board Opinion No. 10 and FASB Statement No. 105.”

(E)  Capitalization ratios = [Stockholders’ equity / (Stockholders’ equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Stockholders’ equity + Long-term debt + Long-term debt due within one year)].

(F)  For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of pre-tax income from continuing operations plus fixed charges, less allowance for borrowed funds used during construction and other capitalized interest; and (2) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Introduction

 

OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.

 

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

 

Enogex LLC and its subsidiaries (“Enogex”) is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1)

 

 

natural gas transportation and storage and (2) natural gas gathering and processing. Historically, Enogex had also engaged in natural gas marketing through its former subsidiary, OGE Energy Resources, Inc. (“OERI”). On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Enogex’s historical consolidated financial statements were prepared from Enogex’s books and records related to Enogex’s operating assets. Accordingly, the discussion that follows includes the results of OERI, but as of January 1, 2008, Enogex no longer has any interest in the results of OERI. Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture through Enogex Atoka LLC (“Atoka”), a wholly owned subsidiary of Enogex.

 

Effective April 1, 2008, Enogex Inc. converted from an Oklahoma corporation to a Delaware limited liability company. Also, effective April 1, 2008, Enogex Products Corporation (“Products”), a wholly owned subsidiary of Enogex, converted from an Oklahoma corporation to an Oklahoma limited liability company.

 

In September 2008, OGE Energy and Energy Transfer Partners, L.P. (“ETP”) entered into an agreement to form a joint venture combining Enogex’s midstream business with ETP’s interstate operations as well as its midstream operations in the Rocky Mountains. One of the conditions to completing the joint venture was obtaining financing that met the minimum specified terms the parties had agreed to in the joint venture agreement. Under the terms of the agreement, if OGE Energy and ETP did not complete the financing and close the joint venture by March 31, 2009, either OGE Energy or ETP could terminate the contribution agreement relating to the formation of the joint venture. Due to the significant downturn in the national economy and resulting uncertainty in the capital markets, the parties determined that obtaining the financing and completing the formation of the joint venture was not feasible and not in their best interests. Accordingly, on February 12, 2009, the parties terminated the agreement to form the joint venture.

 

In light of the September 28, 2008 announcement of the proposed joint venture as well as market conditions, OGE Enogex Partners, L.P., a partnership formed by the Company to further develop Enogex’s natural gas midstream assets and operations, which had previously filed a registration statement with the SEC for a proposed initial public offering of its common units, has determined not to proceed with the offering contemplated by the registration statement and withdrew the registration statement on September 23, 2008.

 

In July 2008, OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture to construct high-capacity transmission line projects in western Oklahoma. The Company will own 50 percent of the joint venture. The joint venture is intended to allow the companies to lead development of renewable wind by sharing capital costs associated with the planned transmission construction. Work on the joint venture projects is scheduled to begin in late 2009 and is targeted for completion by the end of 2013. The joint venture’s initial projects will include 765 kilovolt lines from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from Woodward 50 miles north to the Kansas border. A Southwest Power Pool (“SPP”) study estimates cost for the two projects to be approximately $500 million, of which OGE Energy’s portion will be approximately $250 million. For additional information regarding this joint venture, see Note 15 of Notes to Consolidated Financial Statements.

 

Executive Overview

 

Strategy

 

The Company’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream natural gas business. The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a weather-normalized basis, an annual total return in the top third of its peer group, dividend growth, maintenance of a dividend payout ratio consistent with its peer group and maintenance of strong credit ratings. The Company believes it can accomplish these financial goals by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

 

OG&E has been focused on increased investment at the utility to improve reliability and meet load growth, leverage unique geographic position to develop renewable energy resources for wind and transmission, replace infrastructure equipment, replace aging transmission and distribution systems, provide new products and services and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, OG&E has taken, or has committed to take, the following actions:

 

 

 

 

OG&E continues to pursue additional renewable energy and the construction of associated transmission facilities required to support this renewable expansion. In 2008, OG&E established a “Quick Start” Demand Side Management program to encourage more efficient use of electricity. OG&E also announced a “Positive Energy SmartPower” initiative (commonly referred to in the industry as “Smart Grid” technologies) that will empower customers to proactively manage their energy consumption during periods of peak demand. If these initiatives are successful, OG&E believes it may be able to defer the construction of any incremental fossil fuel generation capacity until 2020.

 

The increase in wind power generation and the building of the transmission lines are subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP. Other projects involve installing new emission-control and monitoring equipment at existing OG&E power plants to help meet OG&E’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see Note 16 of Notes to Consolidated Financial Statements.

 

Results of operations from the transportation and storage business are determined primarily by the volumes of natural gas transported on Enogex’s intrastate pipeline system, volumes of natural gas stored at Enogex’s storage facilities and the level of fees charged to Enogex’s customers for such services. Enogex generates a majority of its revenues and margins for its pipeline business under fee-based transportation contracts that are directly related to the volume of natural gas capacity reserved on its system. The margin Enogex earns from its transportation activities is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, Enogex’s revenues from these arrangements would be reduced. Results of operations from the gathering and processing business are determined primarily by the volumes of natural gas Enogex gathers and processes, its current contract portfolio and natural gas and natural gas liquids (“NGL”) prices. 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 or our control. Any decrease in supplies of natural gas could adversely affect Enogex’s gathering and processing business. 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 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.

 

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets, capturing growth opportunities through expansion projects and increased utilization of existing assets and strategic acquisitions. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Over the past several years, Enogex has initiated multiple organic growth projects. Currently, Enogex’s organic growth capital expenditures are focused on three primary areas:

 

 

 

 

For additional information regarding current or recently completed projects, see Note 15 of Notes to Consolidated Financial Statements.

 

In addition to focusing on growing its earnings, Enogex has reduced its exposure to changes in commodity prices and minimized its exposure to keep-whole processing arrangements. Enogex’s profitability increased significantly from 2003 to 2008 due to the performance improvement plan initiated in 2002 as well as an overall favorable business environment coupled with higher commodity prices. While the Company believes substantial progress has been achieved, additional opportunities remain. Enogex continues to review its work processes, evaluate the rationalization of assets, negotiate better terms for both new contracts and replacement contracts, manage costs and pursue opportunities for organic growth, all in an effort to further improve its cash flow and net income, while at the same time decreasing the volatility associated with commodity prices.

 

The Company’s business strategy is to continue maintaining the diversified asset position of OG&E and Enogex so as to provide competitive energy products and services to customers primarily in the south central United States. The Company will continue to focus on those products and services with limited or manageable commodity exposure. Also, the Company believes that many of the risk management practices, commercial skills and market information available from OERI provide value to all of the Company’s businesses.

 

Summary of Operating Results

 

Prior to January 1, 2008, Enogex had engaged in natural gas marketing through OERI. On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Accordingly, in the discussions below regarding the results of Enogex, the results of OERI are only included for the years ended December 31, 2007 and 2006.

 

2008 compared to 2007. The Company reported net income of approximately $231.4 million, or $2.49 per diluted share, in 2008 as compared to approximately $244.2 million, or $2.64 per diluted share, in 2007. The decrease in net income of approximately $12.8 million, or $0.15 per diluted share, during 2008 as compared to 2007 was primarily due to:

 

 

 

2007 compared to 2006. The Company reported net income of approximately $244.2 million, or $2.64 per diluted share, in 2007 as compared to approximately $262.1 million, or $2.84 per diluted share, in 2006. The decrease in net income of approximately $17.9 million, or $0.20 per diluted share, during 2007 as compared to 2006 was primarily due to:

 

51

 

 

 

Timing Items. Enogex’s net income for 2007 was approximately $86.2 million, which included a loss of approximately $2.2 million resulting from recording OERI’s natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first and second quarters of 2008.

 

Recent Developments and Regulatory Matters

 

Changes in the Capital, Credit and Commodity Markets

 

As a result of recent volatile conditions in global capital markets, including the bankruptcy filing of Lehman Brothers Holdings, Inc. (“Lehman”), general liquidity in short-term credit markets has been constrained despite several pro-active intervention measures undertaken by the Federal Reserve, the Department of the Treasury, the United States Congress and the President of the United States. As explained in more detail below, OGE Energy and OG&E historically have maintained access to short-term liquidity through the A2/P2 commercial paper market and utilization of direct borrowings on certain committed credit agreements, although the ability to access the commercial paper market has been more limited in recent months.

 

The recent volatility in global capital markets has lead to a reduction in the current value of long-term investments held in OGE Energy’s pension trust and post-retirement benefit plan trusts. The recent decline in asset value for the plans, if it continues for any length of time, could require additional future funding requirements.

 

On September 15, 2008, Lehman filed for bankruptcy protection and has not funded their portion of OGE Energy’s and OG&E’s revolving credit agreements. At December 31, 2008, approximately $4 million and $11 million, respectively, of OGE Energy’s and OG&E’s revolving credit agreements are not available as this portion was assigned to Lehman. The Company has no direct credit exposure in its short-term wholesale and commodity trading activity to Lehman or its subsidiaries.

 

Enogex’s gathering and processing margins generally improve when NGL prices are high relative to the price of natural gas (sometimes referred to as high commodity spreads). For much of the first nine months of 2008, commodity spreads were relatively high. Recently, commodity spreads have been significantly lower. If this trend continues, Enogex’s results for 2009 will be affected as its 2008 results were affected. See 2009 Outlook below. Also, prices of natural gas and NGLs have been extremely volatile, and Enogex expects this volatility to continue.

 

Acquisition of Redbud Power Plant

 

On September 29, 2008, OG&E acquired a 51 percent interest in the Redbud Facility for approximately $434.5 million. OG&E will jointly own the Redbud Facility with the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”), and OG&E will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Each of the joint owners will be entitled to its respective portion of the output and will pay its pro rata share of all costs of operating and maintaining the Redbud Facility. OG&E implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes. For

 

additional information regarding the acquisition of the Redbud Facility, see Note 16 of Notes to Consolidated Financial Statements.

 

Cancelled Red Rock Power Plant and Storm Cost Recovery Rider

 

On October 11, 2007, the OCC issued an order denying OG&E and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. On June 27, 2008, OG&E filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs ($35.9 million at December 31, 2007) and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, OG&E will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with OG&E’s next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date OG&E begins to recover the regulatory asset through the base rates established in OG&E’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in OG&E’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover OG&E’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess sulfur dioxide (“SO2”) allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 allowances above the amount retained by OG&E and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. In June 2008, OG&E wrote down the Red Rock deferred cost and the storm costs to their net present value, which resulted in a pre-tax charge of approximately $9.0 million, which is currently included in Deferred Charges and Other Assets with an offset in Other Expense on the Company’s Consolidated Financial Statements.

 

OG&E Arkansas Rate Case Filing

 

On August 29, 2008, OG&E filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that OG&E can reliably meet growing customer demand for electricity, and a return on equity of 12.25 percent. In January 2009, the APSC Staff recommended a $12.0 million rate increase based on a 10.5 percent return on equity. The Attorney General’s consultant recommended a return on equity at the current authorized level of 10.0 percent and stated that his analysis identified at least $10.9 million in reductions to OG&E’s rate increase request. A hearing is scheduled for April 7, 2009. An order from the APSC is expected in June 2009 with new rates targeted for implementation in July 2009.

 

OG&E 2009 Oklahoma Rate Case Filing

 

Beginning in October 2008, OG&E began developing a rate case filing for the Oklahoma jurisdiction. On January 20, 2009, OG&E notified the OCC that it will make its planned Oklahoma rate case filing on or about February 26, 2009. OG&E is finalizing the preparation of the rate case and expects to request an increase of between $100 million and $110 million. The case is expected to proceed through the first half of 2009. If an increase is approved by the OCC, electric rates would likely be implemented in September 2009 at the earliest.

 

OG&E Proposed Wind Power Project

 

OG&E signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the future OU Spirit wind project in western Oklahoma. OG&E will seek regulatory recovery from the OCC and plans to have this project in-service by the end of 2009. Capital expenditures associated with this project are expected to be approximately $260 million.

 

OG&E announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, OG&E issued an RFP to wind developers for construction of up to 300 MWs of new capability. OG&E intends to add the new capacity to its power-generation portfolio

 

no later than the end of 2010.

 

Texas Panhandle / West Side Expansions

 

In August 2006, Enogex completed a project to expand its gathering pipeline capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas area of the Texas Panhandle that has allowed Enogex to benefit from growth opportunities in that marketplace. Since the pipeline was put in service, Enogex has completed the construction of five new gas gathering compressor stations totaling approximately 26,500 horsepower of compression, and several miles of gathering pipe, including a new 16-inch line that extends the original pipeline project an additional 20 miles to the west.  Enogex is continuing to expand in the Wheeler and Hemphill counties in Texas and expects to add another 16,000 horsepower of low pressure compression to the Wheeler area by October 2009.

 

Southeastern Oklahoma / East Side Expansions

 

In February 2008, Enogex completed construction of a new 20-mile pipeline project that connects Enogex’s Hughes, Coal and Pittsburgh county gathering system with the 30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex mainline pipeline to Wilburton, Oklahoma.  The gathering project created additional gathering capacity of 75 million cubic feet per day (“MMcf/d”) for customers desiring low-pressure services. The pipeline was complemented by approximately 16,000 horsepower of new gathering compression which was completed in the third quarter of 2008. Also, Enogex is planning to add approximately 16 miles of 20-inch steel pipe and 60 MMcf/d of additional treating facilities.  Under the assumed operating conditions, the gathering pipe is expected to have throughput capacity of approximately 300 MMcf/d and is expected to be in service by June 2009. The capital expenditures associated with the additional pipe and treating facilities are expected to be approximately $20 million.

 

Enogex Additional Processing Capacity

 

Enogex will consider building or acquiring additional processing capacity in areas where the capacity is needed. Enogex completed construction of a new 100 MMcf/d refrigeration dew point conditioning plant in Roger Mills County of Oklahoma, which became operational in August 2008. In addition, Enogex is constructing a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant will process new gas developing in the area and is expected to be in service by mid-2009. Also, Enogex has placed an order for a cryogenic processing plant that is scheduled for delivery in the fourth quarter of 2009, which is expected to add another 120 MMcf/d of processing capacity to Enogex’s system.

 

2009 Outlook

 

The Company’s 2009 earnings guidance remains unchanged at $2.30 to $2.60 per average diluted share. The Company currently projects 2009 earnings to be towards the lower half of the range primarily due to lower commodity prices in Enogex’s business. The key factors and assumptions underlying this guidance are risk-adjusted to determine the ranges described below. Therefore, the ranges by component may not add to the total. The key factors and assumptions underlying this guidance have been updated to reflect current economic conditions and other developments. Management will monitor its assumptions throughout the year and will seek to take appropriate actions to offset any adverse change in its assumptions.

 

 

Key factors and assumptions for 2009 include:

 

Consolidated

·	Between 96 million and 97 million average diluted shares outstanding;

·	An effective tax rate of approximately 31 percent; and

·	A projected loss at the holding company of between $5 million and $10 million, or $0.05 to $0.10 per diluted share, primarily due to interest expense relating to long and short-term debt borrowings.

 

 

OG&E

  

Enogex

 

 

 

 

The foregoing would result in estimated Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”) at Enogex of between $190 million to $220 million.

 

Reconciliation of projected EBITDA to projected net cash provided from operating activities

 

(A) Based on midpoint of 2009 guidance.

 

Reconciliation of projected EBITDA to projected net income

 

(A) Based on midpoint of 2009 guidance.

  

 

 

For a discussion of the reasons for the use of EBITDA, as well as the limitations of EBITDA as an analytical tool, see “Enogex’s Non-GAAP Financial Measures” below.

 

Dividend Policy

 

The Company’s dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management’s estimation of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends no more than 65 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 our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. At the Company’s December 2008 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 $0.3550 per share from $0.3475 per share effective with the Company’s first quarter 2009 dividend.

 

Results of Operations

 

The following discussion and analysis presents factors that affected the Company’s consolidated results of operations for the years ended December 31, 2008, 2007 and 2006 and the Company’s consolidated financial position at December 31, 2008 and 2007. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

 

 

In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Consolidated Statements of Income as operating income indicates the ongoing profitability of the Company excluding the cost of capital and income taxes.

 

Operating Income (Loss) by Business Segment

 

(A) On  January 1, 2008,  Enogex  distributed  the  stock  of  OERI to OGE Energy, and as a result, OERI is no

longer a subsidiary of Enogex.

(B) Other Operations primarily includes the operations of the holding company and consolidating eliminations.

  

The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements.

 

 

 

 

OG&E

 

(A)  Megawatt-hour.

(B)  Kilowatt-hour.

(C)  Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

 

 

 

2008 compared to 2007. OG&E’s operating income decreased approximately $13.7 million in 2008 as compared to 2007 primarily due to higher operating expenses, higher depreciation and amortization expense and higher taxes other than income partially offset by a higher gross margin.

 

Gross Margin

 

Gross margin was approximately $844.6 million in 2008, as compared to approximately $810.0 million in 2007, an increase of approximately $34.6 million, or 4.3 percent. The gross margin increased primarily due to:

 

 

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was approximately $857.2 million in 2008 as compared to approximately $756.1 million in 2007, an increase of approximately $101.1 million, or 13.4 percent, primarily due to higher natural gas prices. OG&E’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2008, OG&E’s fuel mix was 68 percent coal, 30 percent natural gas and two percent wind. In 2007, OG&E’s fuel mix was 62 percent coal, 36 percent natural gas and two percent wind. Purchased power costs were approximately $257.0 million in 2008 as compared to approximately $268.6 million in 2007, a decrease of approximately $11.6 million, or 4.3 percent. This decrease was primarily due to lower purchases from the energy imbalance service market partially offset by capacity payments made to Redbud due to the purchase power agreement in effect prior to OG&E’s purchase of the Redbud Facility.

 

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex.

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $351.6 million in 2008 as compared to approximately $320.7 million in 2007, an increase of approximately $30.9 million, or 9.6 percent. The increase in other operation and maintenance expenses was primarily due to:

 

 

These increases in other operation and maintenance expenses were partially offset by:

 

 

 

 

 

Depreciation and amortization expense was approximately $155.0 million in 2008 as compared to approximately $141.3 million in 2007, an increase of approximately $13.7 million or 9.7 percent. The increase was primarily due to additional assets, including the Redbud Facility, being placed into service in 2008 and amortization of the Arkansas storm costs that are currently recorded as a regulatory asset (see Note 1 of Notes to the Consolidated Financial Statements).

 

Taxes other than income were approximately $59.7 million in 2008 as compared to approximately $56.0 million in 2007, an increase of approximately $3.7 million, or 6.6 percent, primarily due to higher ad valorem and payroll taxes.

 

Additional Information

 

Interest Income. Interest income was approximately $4.4 million in 2008. There was less than $0.1 million of interest income in 2007. The increase in interest income was primarily due to interest from customers related to the fuel under recovery balance during 2008 and interest income from short-term investments.

 

Other Income. Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $3.6 million in 2008 as compared to approximately $5.0 million in 2007, a decrease of approximately $1.4 million, or 28 percent, primarily due to a lower gain on the guaranteed flat bill tariff due to warmer than normal weather with more customers participating in this plan.

 

Other Expense. Other expense includes, among other things, expenses from losses on the sale and retirement of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions and expenses. Other expense was approximately $11.8 million in 2008 as compared to approximately $7.2 million in 2007, an increase of approximately $4.6 million or 63.9 percent. The increase in other expense was primarily due to:

 

 

These increases in other expense were partially offset by a write-off of approximately $3.1 million associated with the Red Rock power plant for the Arkansas and the FERC jurisdictions during 2007.

 

Interest Expense. Interest expense was approximately $79.1 million in 2008 as compared to approximately $54.9 million in 2007, an increase of approximately $24.2 million, or 44.1 percent. The increase in interest expense was primarily due to:

 

 

These increases in interest expense were partially offset by a decrease of approximately $3.1 million in interest expense associated with the interest due to customers related to the fuel over recovery balance in 2007.

 

Income Tax Expense. Income tax expense was approximately $52.4 million in 2008 as compared to approximately $73.2 million in 2007, a decrease of approximately $20.8 million, or 28.4 percent, primarily due to lower pre-tax income during 2008 as compared to 2007 as well as a lower overall effective income tax rate primarily due to an increase in Federal renewable energy credits and additional state income tax credits in 2008 as compared 2007.

 

2007 compared to 2006. OG&E’s operating income decreased approximately $1.9 million, or 0.7 percent, in 2007 as compared to 2006 primarily due to higher operation and maintenance expenses, higher depreciation and amortization expense and higher taxes other than income partially offset by a higher gross margin.

 

 

 

Gross Margin

 

Gross margin was approximately $810.0 million in 2007 as compared to approximately $795.7 million in 2006, an increase of approximately $14.3 million, or 1.8 percent. The gross margin increased primarily due to:

 

 

These increases in the gross margin were partially offset by:

 

 

Fuel expense was approximately $756.1 million in 2007 as compared to approximately $730.3 million in 2006, an increase of approximately $25.8 million, or 3.5 percent, primarily due to increased natural gas generation in 2007 and a gain recognized from the sale of SO2 allowances of approximately $8.9 million in 2006. OG&E’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2007, OG&E’s fuel mix was 62 percent coal, 36 percent natural gas and two percent wind. In 2006, OG&E’s fuel mix was 67 percent coal and 33 percent natural gas. Purchased power costs were approximately $268.6 million in 2007 as compared to approximately $219.7 million in 2006, an increase of approximately $48.9 million, or 22.3 percent. This increase was primarily due to OG&E’s entrance into the energy imbalance service market on February 1, 2007 (see Note 1 of Notes to Consolidated Financial Statements for a further discussion).

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $320.7 million in 2007 as compared to approximately $316.5 million in 2006, an increase of approximately $4.2 million, or 1.3 percent. The increase in other operation and maintenance expenses was primarily due to:

 

 

These increases in other operation and maintenance expenses were partially offset by:

 

 

Depreciation and amortization expense was approximately $141.3 million in 2007 as compared to approximately $132.2 million in 2006, an increase of approximately $9.1 million, or 6.9 percent, primarily due to the Centennial wind farm being placed in service during January 2007.

 

Taxes other than income were approximately $56.0 million in 2007 as compared to approximately $53.1 million in 2006, an increase of approximately $2.9 million, or 5.5 percent, primarily due to increased ad valorem tax accruals and increased payroll tax expenses.

 

Additional Information

 

Interest Income. There was less than $0.1 million of interest income in 2007. Interest income was approximately $1.9 million in 2006. The decrease was primarily due to interest income earned on fuel under recoveries in 2006 while there was a fuel over recovery balance in 2007.

 

 

 

Allowance for Equity Funds Used During Construction. There was no allowance for equity funds used during construction in 2007 as compared to approximately $4.1 million in 2006, a decrease of approximately $4.1 million primarily due to construction costs for the Centennial wind farm that exceeded the average daily short-term borrowings in 2006.

 

Other Income. Other income was approximately $5.0 million in 2007 as compared to approximately $4.0 million in 2006, an increase of approximately $1.0 million or 25.0 percent. The increase in other income was primarily due to an increase of approximately $3.6 million related to the guaranteed flat bill tariff resulting from more customers participating in this plan, along with milder weather in 2007. This was partially offset by a decrease of approximately $2.6 million associated with the tax gross up of allowance for equity funds used during construction in 2006 with no comparable item recorded in 2007.

 

Other Expense. Other expense was approximately $7.2 million in 2007 as compared to approximately $9.7 million in 2006, a decrease of approximately $2.5 million, or 25.8 percent, primarily due to a loss on the retirement of fixed assets of approximately $5.2 million in 2006 partially offset by the write-off of non-recoverable Red Rock expenses of approximately $3.1 million for Arkansas and the FERC jurisdictions in 2007.

 

Interest Expense. Interest expense was approximately $54.9 million in 2007 as compared to $60.1 million in 2006, a decrease of approximately $5.2 million, or 8.7 percent. The decrease in interest expense was primarily due to:

 

 

These decreases in interest expense were partially offset by:

 

 

Income Tax Expense. Income tax expense was approximately $73.2 million in 2007 as compared to approximately $84.8 million in 2006, a decrease of approximately $11.6 million, or 13.7 percent, primarily due to renewable energy tax credits for which OG&E became eligible in 2007 on the wind power production from OG&E’s Centennial wind farm partially offset by higher pre-tax income for OG&E.

 

Enogex – Continuing Operations

 

 

 

 

 

 

 

 

 

Operating Data – Continuing Operations

 

(A) Includes wells behind central receipt points (as reported to management by third parties). A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site.

(B) Incremental transportation volumes (reported in trillion British thermal units per day) consist of natural gas moved only on the transportation pipeline.

(C) The estimated realized keep-whole spread is an approximation of the spread between the weighted-average sales price of the retained NGL commodities and the purchase price of the replacement natural gas shrink. The spread is based on the market commodity spread less any gains or losses realized from keep-whole hedging transactions. The market commodity spread is estimated using the average of the Oil Price Information Service daily average posting at the Conway, Kansas market for the NGL and the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract for natural gas prices.

 

2008 compared to 2007. Enogex’s operating income increased approximately $21.7 million in 2008 as compared to 2007 primarily due to a higher gross margin in both the gathering and processing business and the transportation and storage business partially offset by higher operating expenses in both segments.

 

 

 

Gross Margin

 

Enogex’s consolidated gross margin increased approximately $39.9 million in 2008 as compared to 2007. The increase resulted from a $50.9 million higher gross margin in the gathering and processing business and a $13.5 million higher gross margin in the transportation and storage business. Gross margin in 2007 included approximately $27.8 million attributable to OERI.

 

The transportation and storage business contributed approximately $146.2 million of Enogex’s consolidated gross margin in 2008 as compared to approximately $132.7 million in 2007, an increase of approximately $13.5 million, or 10.2 percent. The transportation operations contributed approximately $115.8 million of Enogex’s consolidated gross margin in 2008 as compared to approximately $97.8 million in 2007. The storage operations contributed approximately $30.4 million of Enogex’s consolidated gross margin in 2008 as compared to approximately $34.9 million in 2007. The transportation and storage gross margin increased primarily due to:

 

 

These increases in the transportation and storage gross margin were partially offset by:

 

 

The gathering and processing business contributed approximately $246.8 million of Enogex’s consolidated gross margin in 2008 as compared to approximately $195.9 million in 2007, an increase of approximately $50.9 million, or 26.0 percent. The gathering operations contributed approximately $90.9 million of Enogex’s consolidated gross margin in 2008 as compared to approximately $89.4 million in 2007. The processing operations contributed approximately $155.9 million of Enogex’s consolidated gross margin in 2008 as compared to approximately $106.5 million in 2007. The gathering and processing gross margin increased primarily due to:

 

 

 

 

 

These increases in the gathering and processing business were partially offset by:

 

 

Operating Expenses

 

The aggregate of other operation and maintenance expenses, depreciation and amortization expense, impairment of assets and taxes other than income was approximately $18.2 million higher in 2008 as compared to 2007. The variances in depreciation and amortization expense on both a consolidated basis and by segment reflects increased levels of depreciable plant in service during 2008. The $8.1 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to an increase in expenses for non-capitalized system projects, an increase in salaries, wages and benefits and increased allocations for overhead costs from OGE Energy and administrative service fees from OERI in 2008 as compared to 2007.

 

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $0.3 million, or 0.6 percent, lower in 2008 as compared to 2007 primarily due to:

 

 

These increases were partially offset by higher salaries, wages and other employee benefits expense of approximately $5.1 million primarily due to higher incentive compensation and hiring additional employees to support business growth.

 

Other operation and maintenance expenses for the gathering and processing business were approximately $15.2 million, or 21.1 percent, higher in 2008 as compared to 2007 primarily due to:

 

 

 

Enogex Consolidated Information

 

Interest Income. Enogex’s consolidated interest income was approximately $2.5 million in 2008 as compared to approximately $9.2 million in 2007, a decrease of approximately $6.7 million, or 72.8 percent, primarily due to a decrease in interest earned as the balance of advances to OGE Energy decreased due to dividends and capital expenditures.

 

Other Expense. Enogex’s consolidated other expense was approximately $7.5 million in 2008 as compared to approximately $2.3 million in 2007, an increase of approximately $5.2 million primarily due to an increase in the minority interest in the earnings of the Atoka joint venture, which began operations in August 2007.

 

Income Tax Expense. Enogex’s consolidated income tax expense was approximately $57.3 million in 2008 as compared to approximately $53.5 million in 2007, an increase of approximately $3.8 million, or 7.1 percent, primarily due to higher pre-tax income in 2008 as compared to 2007.

 

Timing Items. In 2007, Enogex’s consolidated net income was approximately $86.2 million, which included a loss of approximately $2.2 million resulting from recording OERI’s natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first and second quarters of 2008. On January 1, 2008, Enogex distributed its shares of common stock of OERI to OGE Energy.

 

2007 compared to 2006. Enogex’s operating income increased approximately $24.7 million in 2007 as compared to 2006 primarily due to a higher gross margin in each of Enogex’s segments, which was partially offset by higher operating expenses and higher depreciation and amortization expense.

 

Gross Margin

 

Enogex’s consolidated gross margin increased approximately $45.7 million in 2007 as compared to 2006. The increase resulted from a $28.3 million higher gross margin in the gathering and processing business, a $7.1 million higher gross margin in the transportation and storage business and $13.6 million higher gross margin in the marketing business.

 

The transportation and storage business contributed approximately $132.7 million of Enogex’s consolidated gross margin in 2007 as compared to approximately $125.6 million in 2006, an increase of approximately $7.1 million, or 5.7 percent. The transportation operations contributed approximately $97.8 million of Enogex’s consolidated gross margin in 2007. The storage operations contributed approximately $34.9 million of Enogex’s consolidated gross margin in 2007. The transportation and storage gross margin increased primarily due to:

 

 

These increases in the transportation and storage gross margin were partially offset by:

 

 

 

The gathering and processing business contributed approximately $195.9 million of Enogex’s consolidated gross margin in 2007 as compared to approximately $167.6 million in 2006, an increase of approximately $28.3 million, or 16.9 percent. The gathering operations contributed approximately $89.4 million of Enogex’s consolidated gross margin in 2007. The processing operations contributed approximately $106.5 million of Enogex’s consolidated gross margin in 2007.The gathering and processing gross margin increased primarily due to:

 

 

These increases in the gathering and processing gross margin were partially offset by the settlement on a throughput contract in 2007 associated with its processing operations, which decreased the gross margin by approximately $1.9 million.

 

The marketing business contributed approximately $27.8 million of Enogex’s consolidated gross margin in 2007 as compared to approximately $14.2 million in 2006, an increase of approximately $13.6 million, or 95.8 percent. The marketing gross margin increased primarily due to:

 

 

 

 

Operating Expenses

 

The aggregate of other operation and maintenance expenses, depreciation and amortization expense, impairment of assets and taxes other than income was approximately $21.0 million higher in 2007 as compared to 2006. The variances in depreciation and amortization expense and in taxes other than income on both a consolidated basis and by segment reflect

 

 

 

differing levels of depreciable plant in service and a slight decrease in property taxes. The $17.4 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to:

 

 

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $7.3 million, or 17.7 percent, higher in 2007 as compared to 2006 primarily due to:

 

 

These increases were partially offset by:

 

 

Other operation and maintenance expenses for the gathering and processing business were approximately $12.6 million, or 21.2 percent, higher in 2007 as compared to 2006 primarily due to:

 

 

Other operation and maintenance expenses for the marketing business were approximately $0.8 million, or 8.6 percent, higher in 2007 as compared to 2006 primarily due to higher allocations of approximately $1.5 million primarily due to increased costs in 2007.

 

Enogex Consolidated Information

 

Interest Income. Enogex’s consolidated interest income was approximately $9.2 million in 2007 as compared to approximately $11.1 million in 2006, a decrease of approximately $1.9 million, or 17.1 percent, primarily due to interest income earned on cash investments from the cash proceeds from the sale of certain gas gathering assets in the Kinta, Oklahoma area (the “Kinta Assets”) in May 2006.

 

Other Income. Enogex’s consolidated other income was approximately $0.9 million in 2007 as compared to approximately $7.7 million in 2006, a decrease of approximately $6.8 million, or 88.3 percent. The decrease was primarily due to:

 

 

 

 

 

Timing Items. In 2007, Enogex’s consolidated net income was approximately $86.2 million, which included a loss of approximately $2.2 million resulting from recording OERI’s natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first and second quarters of 2008. On January 1, 2008, Enogex distributed its shares of common stock of OERI to OGE Energy.

 

In 2006, Enogex’s consolidated net income, including the discontinued operations discussed below under the caption “Enogex—Discontinued Operations,” was approximately $113.5 million, which included a loss of approximately $6.3 million resulting from recording natural gas storage inventory held by OERI at the lower of cost or market value on December 31, 2006. The offsetting gains from the sale of withdrawals from inventory were realized during the first three months of 2007. Also, in 2006, Enogex had an increase in net income of approximately $41.2 million relating to various items that Enogex does not consider to be reflective of its ongoing performance. These increases in consolidated net income include:

 

 

These increases in net income were partially offset by a decrease in net income of approximately $0.2 million, related to an impairment of certain long-lived assets.

 

OERI

 

 

2008 compared to 2007. OERI’s operating income decreased approximately $10.7 million in 2008 as compared to 2007 primarily due to a lower gross margin and higher operation and maintenance expense.

 

Gross Margin

 

Gross margin was approximately $19.9 million in 2008 as compared to approximately $27.8 million in 2007, a decrease of approximately $7.9 million, or 28.4 percent. The gross margin decreased primarily due to:

 

 

These decreases in the gross margin were partially offset by:

 

 

 

 

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $12.9 million in 2008 as compared to approximately $10.1 million in 2007, an increase of approximately $2.8 million, or 27.7 percent, primarily due to a higher bad debt expense of approximately $1.5 million.

 

Additional Information

 

Income Tax Expense. Income tax expense was approximately $2.9 million in 2008 as compared to approximately $6.9 million in 2007, a decrease of approximately $4.0 million, or 58.0 percent, primarily due to lower pre-tax income in 2008 as compared to 2007.

 

Timing Items. In 2007, OERI’s net income was approximately $10.9 million, which included a loss of approximately $2.2 million resulting from recording its natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first and second quarters of 2008.

 

Enogex’s Non-GAAP Financial Measures

 

Enogex has included in this Form 10-K the non-GAAP financial measure EBITDA. Enogex defines EBITDA as net income before interest, income taxes and depreciation and amortization. EBITDA is used as a supplemental financial measure by external users of the Company’s financial statements such as investors, commercial banks and others, to assess:

 

 

The economic substance behind the use of EBITDA is to measure the ability of Enogex’s assets to generate cash sufficient to pay interest costs, support indebtedness and pay dividends to OGE Energy.

 

Enogex provides a reconciliation of EBITDA to its most directly comparable financial measures as calculated and presented in accordance with generally accepted accounting principles (“GAAP”). The GAAP measures most directly comparable to EBITDA are net cash provided from operating activities and net income. The non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net cash provided from operating activities and GAAP net income. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. EBITDA should not be considered in isolation or as a substitute for analysis of Enogex’s results as reported under GAAP. Because EBITDA excludes some, but not all, items that affect net income and net cash provided from operating activities and is defined differently by different companies in Enogex’s industry, Enogex’s definition of EBITDA may not be comparable to similarly titled measures of other companies.

 

To compensate for the limitations of EBITDA as an analytical tool, Enogex believes it is important to review the comparable GAAP measures and understand the differences between the measures.