UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year
ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number 1-12579
OGE Energy Corp.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1481638
(State or other jurisdiction
of
(I.R.S. Employer
incorporation or
organization)
Identification No.)
321 North Harvey
P. O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area
code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock
New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase Series A Preferred Stock
New York Stock Exchange and Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90
days. Yes X
No
Indicate by check mark if disclosure of delinquent
filers pursuant to Item 405 of regulation S-K is not contained herein, and will
not be contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [ X ]
As of February 28, 2002, 77,991,713 shares of
common stock were outstanding and the aggregate market value of such shares held
by non-affiliates was $1,710,358,266 based on the reported closing market price
of the common stock on the New York Stock Exchange on such date of
$21.93.
DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement for the Company's 2002 annual meeting of stockholders is incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
Item 1. Business...................................................................................... 1
The Company................................................................................... 1
Electric Operations........................................................................... 2
General.............................................................................. 2
Regulation and Rates................................................................. 5
Rate Activities and Proposals........................................................ 11
Fuel Supply.......................................................................... 12
Enogex........................................................................................ 13
Finance and Construction...................................................................... 17
Environmental Matters......................................................................... 19
Employees..................................................................................... 20
Item 2. Properties.................................................................................... 21
Item 3. Legal Proceedings............................................................................. 22
Item 4. Submission of Matters to a Vote of Security Holders........................................... 25
Executive Officers of the Registrant.......................................................... 26
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......................... 30
Item 6. Selected Financial Data....................................................................... 31
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......... 32
Item 8. Financial Statements and Supplementary Data................................................... 52
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 89
PART III
Item 10. Directors and Executive Officers of the Registrant............................................ 89
Item 11. Executive Compensation........................................................................ 89
Item 12. Security Ownership of Certain Beneficial Owners and Management................................ 89
Item 13. Certain Relationships and Related Transactions................................................ 89
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................... 89
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PART I
Item 1. Business.
THE COMPANY
OGE Energy Corp. (collectively with its subsidiaries, the "Company") is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company conducts these activities through two business segments, the electric utility and the energy supply segments.
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 the jurisdiction of the Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC") and the Federal Energy Regulatory Commission ("FERC"). OG&E owns and operates eight generating stations with a total capability of 5,732 megawatts. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in the State of Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area, which is the second largest market area in that state. OG&E continues to substantially impact the financial results and condition of the Company. OG&E is expected to grow moderately, consistent with historic trends. Expansion will primarily result from continued economic growth in its service territory. The citizens of Oklahoma recently passed a "right to work" referendum. This action along with other initiatives are intended to enhance the state's ability to promote itself as a business - friendly location.
The energy supply segment produces, gathers, processes, transports, markets and stores natural gas and produces, transports, and markets natural gas liquids in Oklahoma, Arkansas and west Texas. These operations are conducted primarily through Enogex Inc. and its subsidiaries ("Enogex"). Enogex is also involved in commodity sales and services related to natural gas and electric power and provides energy related services for corporate commodity price risk management and energy forward price evaluations primarily through its subsidiary, OGE Energy Resources Inc. ("OERI"). Enogex owns and operates the tenth largest natural gas pipeline system in the United States in terms of miles of pipe in service. Enogex has a significant investment in natural gas gathering, processing, transmission and storage in the major gas producing basins of Oklahoma, as well as gathering and processing operations in west Texas. Enogex also has investments in exploration and production of natural gas and oil with properties located primarily in Michigan and Oklahoma.
The Company's business strategy is to assemble a portfolio of assets, people, skills and customers that create optimal value from the convergence occurring in the electricity and natural gas markets. The Company believes its converged portfolio is well positioned to take advantage of opportunities in the south central United States.
OG&E has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred in the wholesale electric markets at the federal level and significant changes are expected at the retail level in the states served by OG&E. In Oklahoma, legislation was passed in April 1997 to provide for the orderly restructuring of the electric industry with the goal to provide retail customers with the ability to choose their electric suppliers by July 1, 2002. In May 2001, the Oklahoma Legislature passed legislation postponing the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, the
1
legislation calls for a nine-member task force to further study the issues surrounding deregulation. In April 1999, Arkansas passed a law calling for restructuring of the electric utility industry at the retail level. The law initially targeted customer choice of electricity providers by January 1, 2002, but the law was amended to delay customer choice until October 1, 2003. See "Electric Operations - Regulation and Rates - State Restructuring Initiatives" for further discussion of these developments.
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of OG&E. OG&E's rates had last been formally reviewed in 1995. In the filing, the OCC requested that OG&E submit information in accordance with OCC minimum standard filing requirements by January 28, 2002, for a test year ending September 30, 2001. On January 28, 2002, OG&E filed its response requesting a $22 million annual rate increase. OG&E's filing also outlined several new customer programs and offered not to seek another increase for at least three years. It has been 16 years since OG&E requested a rate increase. A final order in the OG&E rate case is not expected until later in 2002. At this time, management cannot predict the outcome of this rate case or the impact on its consolidated financial position or results of operation. See "Electric Operations - Regulation and Rates - Recent Regulatory Matters" for further discussion of these developments.
The Company was incorporated in August 1995 in the State of Oklahoma and its executive offices are located at 321 North Harvey, P. O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
ELECTRIC OPERATIONS
General
As stated previously, 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 270 communities and their contiguous rural and suburban areas. During 2001, seven other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area, with an estimated population of 1.7 million, covers approximately 30,000 square miles in Oklahoma and western Arkansas; including Oklahoma City, the largest city in Oklahoma, and Ft. Smith, Arkansas, the second largest market in that state. Of the 279 communities served, 252 are located in Oklahoma and 27 in Arkansas. Approximately 90 percent of total electric operating revenues for the year ended December 31, 2001, were derived 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 for the year was approximately 5,788 megawatts on July 12, 2001. OG&E's load responsibility peak demand was approximately 5,600 megawatts on July 12, 2001, resulting in a capacity margin of approximately 14.7 percent. As reflected in the table on page 3 and in the operating statistics on page 4, total kilowatt-hour sales decreased 1.3 percent in 2001 as compared to an increase of 5.9 percent in 2000 and a decrease of 2.2 percent in 1999. Kilowatt-hour sales to OG&E's customers ("system sales") decreased 1.9 percent in 2001, due to milder weather. Cooling degree days and heating degree days were approximately 5.1 percent and 5.3 percent below 2000 levels, respectively. Sales to other utilities and power marketers ("off-system sales") increased 65.2 percent in 2001 and decreased 31.5 percent and 48.6 percent in 2000 and 1999, respectively.
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Variations in kilowatt-hour sales for the three years are reflected in the following table:
SALES (Millions of Kwh)
Increase/ Increase/ Increase/
2001 (Decrease) 2000 (Decrease) 1999 (Decrease)
- -----------------------------------------------------------------------------------------------
System Sales 24,518 (1.9%) 25,002 6.5% 23,468 (0.7%)
Off-System Sales 423 65.2% 256 (31.5%) 374 (48.6%)
------ ------ ------
Total Sales 24,941 (1.3%) 25,258 5.9% 23,842 (2.2%)
====== ====== ======
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. See Item 3 "Legal Proceedings" for a further discussion of this matter. 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 "Electric Operations - Regulation and Rates - Recent Regulatory Matters" 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
2001 2000 1999
--------------- -------------- --------------
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use).......... 23,041 23,327 21,788
Purchased...................................... 3,703 3,634 3,795
--------------- -------------- --------------
Total generated and purchased.............. 26,744 26,961 25,583
Company use, free service and losses........... (1,803) (1,703) (1,741)
--------------- -------------- --------------
Electric energy sold....................... 24,941 25,258 23,842
=============== ============== ==============
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential.................................... 7,982 7,974 7,509
Commercial and industrial...................... 12,401 12,729 11,985
Public street and highway lighting............. 71 70 69
Other sales to public authorities.............. 2,530 2,458 2,354
System sales for resale........................ 1,534 1,771 1,551
--------------- -------------- --------------
Total system sales......................... 24,518 25,002 23,468
Off-system sales............................... 423 256 374
--------------- -------------- --------------
Total sales................................ 24,941 25,258 23,842
=============== ============== ==============
ELECTRIC OPERATING REVENUES:
(Dollars in Thousands)
Electric Revenues:
Residential.................................. $ 578,881 $ 575,656 $ 515,299
Commercial and industrial.................... 637,962 643,576 557,884
Public street and highway lighting........... 10,877 10,301 9,736
Other sales to public authorities............ 127,954 124,217 108,159
System sales for resale...................... 52,506 58,117 42,918
Provision for FERC rate refund............... (1,000) --- ---
--------------- -------------- --------------
Total system sales......................... 1,407,180 1,411,867 1,233,996
Off-system sales............................. 12,977 12,948 27,894
--------------- -------------- --------------
Total Electric Revenues.................... 1,420,157 1,424,815 1,261,890
Miscellaneous revenues....................... 36,645 28,770 24,954
--------------- -------------- --------------
Total Electric Operating Revenues.......... $ 1,456,802 $ 1,453,585 $ 1,286,844
=============== ============== ==============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential.................................... 609,408 603,826 599,702
Commercial and industrial...................... 87,511 86,659 86,837
Public street and highway lighting............. 250 250 249
Other sales to public authorities.............. 12,566 11,615 11,151
Sales for resale............................... 62 52 56
--------------- -------------- --------------
Total...................................... 709,797 702,402 697,995
=============== ============== ==============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)....................... 13,131 13,264 12,546
Average annual revenue......................... $ 952.32 $ 957.54 $ 860.98
Average price per Kwh (cents).................. $ 7.25 $ 7.22 $ 6.86
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Regulation and Rates
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC, and in Arkansas by the APSC. 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.
As part of the corporate reorganization whereby the Company became the holding company parent of OG&E, OG&E obtained the approval of the OCC. The order of the OCC authorizing OG&E to reorganize into a holding company structure contains certain provisions which, among other things, ensure the OCC access to the books and records of the Company and its subsidiaries relating to transactions with OG&E; require the Company and its subsidiaries to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and prohibit the Company from pledging OG&E assets or income for affiliate transactions.
For the year ended December 31, 2001, approximately 87 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC, and five percent to the FERC.
Recent Regulatory Matters
The OCC Staff ("Staff") annually conducts a review ("Matrix Review") to assess utility operations. The purpose of the Matrix Review is to enable the Staff to specifically identify regulated utilities that have experienced material or significant changes in operating characteristics, or in the underlying cost of service, as a means of evaluating the need to pursue rate hearings. The Staff also uses the Matrix Review to identify regulated utilities that require a Staff review of some specific operational activity conducted by the utility. The Matrix Review is composed of 11 indicators that are the basic guide for the Staff's initial review of a regulated utility. The 11 indicators include such items as the time from a utility's last rate review and service quality complaints. Each indicator is given a rating by the Staff from zero to three. A rating of zero is considered not relevant, a rating of one is considered slightly relevant, a rating of two is considered moderately relevant, while a rating of three is considered significantly relevant. The Staff believes that an aggregate rating of less than ten and with no individual indicator receiving a rating of three, should indicate that no further assessment is required. Any rating above these levels could result in a Staff recommendation requesting that a further review should be performed. In July 2001, the OCC held a hearing at which the Staff reported the results of its Matrix Review of OG&E. The review resulted in an aggregate score of 17 for OG&E, with only one indicator "Time since last formal rate review", achieving a rating of three. OG&E's last formal rate review by the Staff occurred in 1995. As part of its written report, the Staff recommended that a general rate review be performed on OG&E.
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of OG&E. In the filing, the Staff requested that OG&E submit information in accordance with OCC minimum standard filing requirements by January 28, 2002, for a test year ending September 30, 2001. On December 14, 2001, OG&E, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in OG&E's electric rates. On January 28, 2002, OG&E filed testimony with the OCC supporting OG&E's request for a $22 million annual rate increase. If granted, the increase would be the first for OG&E since 1985. Over the past 16 years, OG&E has had rate reductions of more than $142 million. Attempting to make security investments at the proper level, OG&E developed a set of guidelines to arrive at the appropriate steps to minimize the ability to cause long-term or widespread outages, minimize the impact on critical national
5
defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on OG&E that might be caused by an attack, and accomplish these efforts with minimal impact on ratepayers. Approximately $10 million of the rate increase requested by OG&E was to invest in increased security. The additional $12 million is for investment in increased system reliability and for increased utility costs. OG&E has added new generation capacity to meet growing customer demand and has determined a need to increase expenditures for distribution system reliability that has been brought about, in no small part, by a series of record-breaking storms, including a 1995 windstorm in the Oklahoma City area affecting 175,000 customers, 1999 tornadoes affecting about 150,000 customers and knocking out a power plant, July 2000 thunderstorms affecting 110,000 customers, a Christmas 2000 ice storm affecting 140,000 customers, Memorial Day 2001 storms leaving 143,000 customers without power and at least two other storms affecting at least 100,000 customers each. Additionally, OG&E has experienced an overall increase in operating expenses. As part of it's filing, OG&E also is seeking approval to offer several new rate program choices to customers. One such pilot program involves flat billing. This option would set a customer's bill at a fixed dollar amount and would not change throughout the year regardless of the amount of power consumed. The bill amount would then be adjusted in the following year based on the previous year's usage and other factors. Another proposed rate program, a Green Power option, would involve OG&E contracting with wind generators to purchase a quantity of wind-generated energy, then offering that power to customers. The rate would reflect the higher cost of wind-generated power. Also included in the filing was OG&E's offer to not seek a rate increase for three years. A final order in the OG&E rate case is not expected until later in 2002.
In January 2002, a significant ice storm hit OG&E's service territory. This ice storm inflicted major damage to the transmission and distribution infrastructure. Total expenditures are currently estimated at $136 million. Based on current estimates, the vast majority of these expenditures for restoration of the utility's system will be capitalized as part of the utility's plant. The Company believes that the capital costs will be considered in the pending rate case. The remaining costs will be deferred pending regulatory approval of a recovery plan.
As previously reported, certain aspects of OG&E's electric rates recently have been addressed by the OCC. In March 2000, the OCC approved, and OG&E implemented, the Acquisition Premium Credit Rider ("APC Rider") reflecting the completion of the recovery of the amortization premium paid by OG&E when it acquired Enogex in 1986. The effect of the APC Rider is to remove $10.7 million annually from the amount being recovered by OG&E from its Oklahoma customers in current rates.
In June 2000, the OCC approved modifications to OG&E's Generation Efficiency Performance Rider ("GEP Rider"). The GEP Rider was established initially in 1997 in connection with OG&E's last general rate review and was intended to encourage OG&E to lower its fuel costs by: (i) allowing OG&E to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261%) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739%) of the average fuel costs of other investor-owned utilities. The modifications enacted in June 2000 had the effect of reducing the amount OG&E could recover under the GEP Rider by: (i) changing OG&E's peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if OG&E's costs exceed the new peer group by changing the percentage above which OG&E will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing OG&E's share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to OG&E or penalties charged to OG&E. For the period between July 1, 2001 and June 30, 2002, OG&E estimates that it will recover $5.1 million under the GEP Rider. The GEP Rider is scheduled to
6
expire in June 2002, however, the OCC could decide to establish a similar reward mechanism in a subsequent action upon proper showing.
The final action addresses the competitive bid process of OG&E's gas transportation needs following which OG&E's affiliate, Enogex, contracted to provide gas transportation service to all of OG&E's generation plants. In the 1997 Order, the OCC approved a stipulation wherein OG&E agreed to initiate a competitive bidding process for gas transportation service to its gas-fired plants, with the competitive services commencing no later than April 30, 2000. The order also set annual compensation for the transportation services provided by Enogex to OG&E at $41.3 million annually until March 1, 2000, at which time the rate would drop to $28.5 million (reflecting removal of the APC Rider, upon the completion of the recovery from customers of the amortization premium paid by OG&E when it acquired Enogex in 1986) and remain at that level until competitively-bid gas transportation began. Final firm bids were submitted by Enogex and other pipelines on April 15, 1999. In July 1999, OG&E filed an application with the OCC requesting approval of a performance-based rate plan for its Oklahoma retail customers from April 2000 until the introduction of customer choice for electric power in July 2002. As part of this application, OG&E stated that Enogex had submitted the only viable bid ($33.4 million per year) for gas transportation to OG&E's six gas-fired power plants that were the subject of the competitive bid. As part of its application to the OCC, OG&E offered to discount Enogex's bid from $33.4 million annually to $25.2 million annually. OG&E executed a gas transportation contract with Enogex under which Enogex continues to serve the needs of OG&E's power plants at a price to be paid by OG&E of $33.4 million annually and, if OG&E's proposal had been approved by the OCC, OG&E would have recovered a portion of such amount ($25.2 million) from its customers. OG&E negotiated with the Staff, the Office of the Oklahoma Attorney General and a coalition of industrial customers in an effort to settle all issues (including the competitive bid process) associated with its application for a performance-based rate plan. When these negotiations failed, OG&E withdrew its application, which withdrawal was approved by the OCC in December 1999.
In July 2000, OG&E entered into a stipulation (the "Stipulation") with the Staff, the Office of the Attorney General and a coalition of industrial customers regarding the competitive bid process of OG&E's gas transportation service. In June 2001, the OCC approved the Stipulation declaring the Stipulation to be fair, just and reasonable and representing a reasonable settlement of the issues and thereby serving the public interest. OG&E had previously collected $28.5 million on an annual basis through its base rate and APC Rider for gas transportation services from Enogex for the power plant requirements covered by the competitive bid. The Stipulation permits OG&E to recover $25.2 million annually for the gas transportation services provided by Enogex pursuant to the competitive bid process. The Stipulation directs OG&E to reduce rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of a Gas Transportation Adjustment Credit Rider ("GTAC Rider"). The GTAC Rider is a credit for gas transportation cost recovery and is applicable to and becomes part of each Oklahoma retail rate schedule to which OG&E's Fuel Cost Adjustment rider applies. The GTAC Rider became effective with the first billing cycle of July 2001, and will remain in effect until amended by OG&E at the direction of the OCC.
On February 13, 1998, the APSC staff filed a motion for a show cause order to review OG&E's electric rates in the State of Arkansas. The Staff recommended a $3.1 million annual rate reduction (based on a test year ended December 31, 1996). The Staff and OG&E reached a settlement for a $2.3 million annual rate reduction, which was approved by the APSC in August 1999.
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State Restructuring Initiatives
Oklahoma: As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997 (the "Act"), which was designed to provide for choice by retail customers of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 ("SB 440"), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, the SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Attorney General, the OCC Chair and several legislative leaders, among others. The Company will continue to participate actively in the legislative process and expects to remain a competitive supplier of electricity. The Company cannot predict what, if any, legislation will be adopted at the next legislative session.
Arkansas: In April 1999, Arkansas passed a law ("the Restructuring Law") calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the Oklahoma law, would significantly affect OG&E's future operations. OG&E's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. The Restructuring Law also provides that utilities owning or controlling transmission assets must transfer control of such transmission assets to an independent system operator, independent transmission company or regional transmission group, if any such organization has been approved by the FERC. Other provisions of the Restructuring Law permit municipal electric systems to opt in or out, permit recovery of stranded costs and transition costs and require filing of unbundled rates for generation, transmission, distribution and customer service. OG&E filed preliminary business separation plans with the APSC on August 8, 2000. The APSC has established a timetable to establish rules implementing the Arkansas restructuring statutes.
Automatic Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to that component in cost-of-service for ratemaking, are charged to substantially all of OG&E's electric customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. As discussed previously, in June 2001, the OCC approved the GTAC Rider for $2.7 million annually. The GTAC Rider is a credit for gas transportation cost recovery. In March 2000, the OCC approved the APC Rider for $10.7 million annually. The purpose of the APC Rider is to credit the Oklahoma retail customers for the completion of the OCC authorized recovery of the premium paid by OG&E when it acquired Enogex in 1986. The GTAC Rider and the APC Rider are both applicable to each Oklahoma retail rate schedule to which OG&E's fuel cost adjustment clause applies.
National Energy Legislation
Federal law imposes numerous responsibilities and requirements on OG&E. The Public Utility Regulatory Policies Act of 1978 requires electric utilities, such as OG&E, to purchase electric power
8
from, and sell electric power to, qualified cogeneration facilities and small power production facilities ("QFs"). Generally stated, electric utilities must purchase electric energy and production capacity made available by QFs at a rate reflecting the cost that the purchasing utility can avoid as a result of obtaining energy and production capacity from these sources; rather than generating an equivalent amount of energy itself or purchasing the energy or capacity from other suppliers. OG&E has entered into agreements with four such cogenerators. Electric utilities also must furnish electric energy to QFs on a non-discriminatory basis at a rate that is just and reasonable and in the public interest and must provide certain types of service which may be requested by QFs to supplement or back up those facilities' own generation.
The efforts to increase competition in the electric industry at the retail level in Oklahoma and Arkansas have been paralleled and even surpassed by efforts at the federal level to increase competition in the wholesale markets for electricity. The National Energy Policy Act of 1992 ("Energy Act"), among other things, promoted the development of independent power producers ("IPPs"). The Energy Act was followed by FERC Order 888 and Order 889, which facilitated third-party utilization of the transmission grid for sales of wholesale power.
The Energy Act, Orders 888 and 889, and other FERC policies and initiatives have significantly increased competition in the wholesale power market. Utilities, including OG&E, have increased their own in-house wholesale marketing efforts and the number of entities with whom they trade. Moreover, power marketers are an increasingly important presence in the industry. These entities typically arbitrage wholesale price differentials by buying power produced by others in one market and selling it in another. IPPs also are becoming a more significant sector of the electric utility industry. In both Oklahoma and Arkansas, significant additions of new power plants have been announced, almost all of it from IPPs.
Notwithstanding these developments in the wholesale power market, FERC recognized that impediments remained to the achievement of fully competitive wholesale markets including: (i) engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid and (ii) continuing opportunities for transmission owners (primarily electric utilities) to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. In the past, FERC only encouraged utilities to join and place their transmission systems under the operational control of independent system operators ("ISOs"). On December 20, 1999, FERC issued Order 2000, its final rule on regional transmission organizations ("RTOs"). Order 2000 is intended to have the effect of turning the nation's transmission facilities into independently operated "common carriers" that offer comparable service to all would-be-users. Although adopting a voluntary approach towards RTO formation, FERC stressed that Order 2000 does not preclude it from requiring RTO participation. Order 2000 set out a timetable for every jurisdictional utility (including OG&E) to either join in an RTO filing, or, alternatively, to submit a filing describing its efforts to join an RTO, the reasons for not participating in an RTO proposal and any obstacles to participation, and its plans for further work toward participation.
OG&E is a member of the Southwest Power Pool ("SPP"), the regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and part of Texas. OG&E participated with the SPP in the development of regional transmission tariffs and executed an Agency Agreement with the SPP to facilitate interstate transmission operations within this region. In October 2000, the SPP filed its application with the FERC to become an RTO. In July 2001, the FERC determined that the SPP did not have adequate scope and configuration to be granted RTO status. The SPP was encouraged to explore the possibility of joining an RTO to be formed in the southeastern region of the United States and to explore the feasibility of becoming a part of the recently approved RTO being established by the
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Midwest Independent System Operator ("MISO"). The SPP and MISO entered negotiations during the late summer of 2001 to combine the SPP and MISO and to form a new regional transmission entity that would combine the control areas of MISO and SPP, capture certain synergies that would be available from the combined organization, and allow member companies in the SPP certain options with respect to membership in the combined organization. The officers of MISO and of SPP, under the direction of their respective Boards of Directors have developed documentation to effect the merger of SPP and MISO into a new organization, and the transaction has been approved by the SPP Board of Directors and the required number of SPP member companies. OG&E intends to meet its obligations under Order 2000 and under the Restructuring Law in Arkansas first by executing a Conditional Withdrawal Agreement with the SPP. The Conditional Withdrawal Agreement will have the effect of terminating OG&E's membership in the SPP, except for regional reliability purposes, at such time as the MISO - SPP combination has received all necessary regulatory approvals and the transaction is closed. Following the closing of the transaction, OG&E currently anticipates that it will join the MISO. The transfer of operational control of OG&E's transmission system to a FERC-approved RTO is not expected to significantly impact OG&E's financial results. Yet, it is expected to increase the markets in which OG&E can sell power at wholesale and, at the same time, to increase competition in such wholesale markets. As a low-cost producer of electricity with two of the most efficient power plants in the country, OG&E expects to remain a competitive supplier of electricity.
Another impact of complying with FERC's Order 888 is a requirement for utilities to offer a transmission tariff that includes network transmission service ("NTS") to transmission customers. NTS allows transmission service customers to fully integrate load and resources on an instantaneous basis, in a manner similar to how OG&E has historically integrated its load and resources. Under NTS, OG&E and participating customers share the total annual transmission cost for their combined joint-use systems, net of related transmission revenues, based upon each company's share of the total system load. Management expects minimal annual expenses as a result of Orders 888 and 889.
Regulatory Assets and Liabilities
As discussed previously, legislation was enacted in Oklahoma and Arkansas that was to restructure the electric utility industry in those states. Although implementation of this restructuring legislation has been delayed, if and when implemented this legislation would deregulate OG&E's electric generation assets and discontinue the use of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" with respect to the related regulatory assets. This may result in either full recovery of generation-related regulatory assets (net of related regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary charge of up to $28 million, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma and Arkansas 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 assets is appropriate. However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory methodologies in the future that are not based on cost-of-service, the continued use of SFAS No. 71 with respect to the regulatory assets related to the electric transmission and distribution assets may no longer be 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.
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Summary
The Energy Act, the actions of the FERC, the restructuring legislation in Oklahoma and Arkansas, and other factors are expected to significantly increase competition in the electric industry. OG&E has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While OG&E is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and OG&E is advocating this position vigorously.
Rate Activities and Proposals
As previously discussed, the OCC initiated a rate review proceeding for OG&E in September of 2001. The review is performed to capture the effects of changing costs, customer growth changes, changes in technology, or changes in customer's needs. The review provides an opportunity by the OCC and OG&E to review rate structures, to review terms and conditions of service, to address any new customer issues, and to make modifications as needed in meeting the needs of OG&E's customers, employees and the Company's shareholders.
OG&E has proposed in this rate proceeding several new programs and rate options, as well as modifications to existing rate structures. Some of the new programs being promoted include a Guaranteed Flat Bill ("GFB") option for Residential and small General Service accounts. These voluntary GFB programs will allow qualifying customers the opportunity to purchase their electricity needs at a set price for an entire year. A second option provided to customers in this proceeding is a "Green Power" option. This option is a wind power program and will be available as a voluntary option to all of OG&E's Oklahoma customers that wish to purchase Green Power. A third new rate offering is levelized demand. This program will be beneficial for medium to large size customers of consistent demand levels who wish to reduce monthly billing variability. Setting a flat demand price for the entire year eliminates seasonal demand price variability. The levelized demand offering is not for every customer, but many customers will benefit from this tariff. Finally, the last new program being offered to OG&E's commercial and industrial customers is voluntary load curtailment. This program will provide customers with the opportunity to curtail on a voluntary basis when OG&E system conditions merit curtailment action. They will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required.
OG&E believes that due to the positive economic impact on Oklahoma when new power plants are built, it is in Oklahoma's best interest to encourage the development of new power plants. A significant number of new power plants have been proposed in Oklahoma and a number of them are actually under construction.
OG&E has proposed the Transmission Investment Recovery Rider ("TIR Rider") which would be applicable to investments necessary for increased transmission sevice and interconnect costs not funded by a new transmission customer (such as an IPP) or for investment to improve available transfer capability as defined and approved by the RTO. While the transmission system in Oklahoma is serving native load customers well, it is evident that transmission upgrades will be necessary to accommodate the growing number of power generators. OG&E believes that increased investments in the transmission infrastructure along with the investments already occurring in Oklahoma and surrounding states to construct new generating plants, will produce a viable regional wholesale power marketplace. The enhanced transmission system will allow electric utilities in Oklahoma more options for competitively priced power to evaluate with respect to load growth of customers they have an obligation to serve. To
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the extent that wholesale competition is enhanced, the ultimate cost of electricity to Oklahoma customers is expected to be less than would be the case in the absence of competition. To the extent that OG&E would be required to pay for certain types of transmission upgrades to the system, OG&E believes the TIR Rider would provide a timely and reasonable means of recovering costs.
The TIR Rider would be a per kilowatt-hour rate, applied monthly to all Oklahoma retail customers bills to collect revenue requirements associated with prospective types of transmission investments. The TIR Rider rate would be determined on a calendar year basis, recognizing revenue requirements for investment during the year and the effects of depreciation on investment incurred in prior years. At the time of OG&E's next rate review, the remaining value of the transmission assets applicable to the TIR Rider will be placed into rate base and the components of the TIR Rider redetermined.
OG&E also is proposing a Coal Utilization Performance Rider ("CUP Rider"), the CUP Rider is designed to reward OG&E based on its performance in the utilization of its coal generation facilities. The greater the coal plant utilization, the greater the benefits received by OG&E's customers. OG&E's coal plants are among the nations most efficient and the energy produced by those plants displaces higher cost energy. The CUP Rider provides additional incentive for OG&E by encouraging OG&E to aggressively pursue even greater efficiencies from these best-in-class plants. Additional CUP Rider incentives begin at 72 percent coal utilization and increase as percentages rise above the 72 percent threshold level. For 2001, coal plant utilization was 73 percent. It is no small task to increase this utilization percentage, but the customers, the stockholders, and OG&E all benefit if OG&E is able to increase coal plant utilization.
These new rate options coupled with OG&E's existing rate choices should be very valuable for OG&E's customers in making the best rate choices for their particular electricity needs.
Fuel Supply
During 2001, approximately 73 percent of the OG&E-generated energy was produced by coal-fired units and 27 percent by natural gas-fired units. A slight decline in the percentage of coal generation in future years is expected to result from increases in natural gas-fired generation required to meet growing energy needs while coal generation will remain fairly constant. Over the last five years, the average cost of fuel used, by type, per million British thermal unit ("MMBtu") was as follows:
2001 2000 1999 1998 1997
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Coal.............. $0.81 $0.87 $0.85 $0.85 $0.84
Natural Gas....... $4.91 $4.93 $3.14 $2.83 $3.60
Weighted Avg...... $1.97 $1.96 $1.54 $1.48 $1.39
A portion of the fuel cost is included in base rates and differs for each jurisdiction. The portion of these costs that is not included in base rates is recovered through automatic fuel adjustment clauses. See "Electric Operations - Regulation and Rates - Automatic Fuel Adjustment Clauses."
Coal-Fired Units: All of OG&E's coal units, with an aggregate capability of 2,539 megawatts, are designed to burn low sulfur western coal. OG&E purchases coal primarily under long-term contracts. During 2001, OG&E purchased 8.7 million tons of coal from the following Wyoming suppliers: Kennecott Energy Company, Thunder Basin Coal Company, Powder River Coal Company, and Triton Coal Company. The combination of all coal has a weighted average sulfur content of less than 0.3 percent and can be burned in these units under existing federal, state and local environmental standards
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(maximum of 1.2 pounds of sulfur dioxide per MMBtu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, OG&E units have an approximate emission rate of 0.63 pounds of sulfur dioxide per MMBtu. In anticipation of the more strict provisions of Phase II of The Clean Air Act, which began in the year 2000, OG&E had contracts in place to allow for a supply of very low sulfur coal from suppliers in the Powder River Basin to meet the new sulfur dioxide standards.
OG&E has continued its efforts to maximize the utilization of its coal units at both the Sooner and Muskogee generating plants. See "Environmental Matters" for a discussion of an environmental proposal that, if implemented as proposed, could inhibit OG&E's ability to use coal as its primary boiler fuel.
Gas-Fired Units: OG&E utilizes a Request for Bid to acquire natural gas supplies. For calendar year 2002, successful bids wer accepted that are expected to supply approximately 70 percent of OG&E's estimated annual gas requirements. The additional gas requirements will be secured through monthly and day-to-day purchases as needed.
In 1993, OG&E began utilizing a natural gas storage facility that allows OG&E to optimize the use of its generation assets.
ENOGEX
The energy supply segment includes Enogex, which owns and operates the tenth largest natural gas pipeline system in the United States in terms of miles of pipe in service. Enogex is an Oklahoma intrastate natural gas pipeline, which also conducts operations in related business through subsidiary companies. These businesses include gas processing operations and natural gas liquids marketing ("Gas Processing"); exploration and production of oil and natural gas ("Exploration and Production"); commodity sales and services related to natural gas and electric power ("Marketing"); and the gas gathering and interstate gas transmission operations ("Gas Transportation").
Enogex has a significant investment in natural gas gathering, processing, transmission and storage in the major gas producing basins of Oklahoma, as well as gathering and processing operations in west Texas. Enogex also has a seventy-five percent interest in the NOARK Pipeline System Limited Partnership ("NOARK"), which owns the Ozark Gas Transmission System ("Ozark"). Ozark is a FERC regulated interstate pipeline that is operated by Enogex, and is located from southeast Oklahoma through Arkansas and terminates just across the state line in southeast Missouri. Enogex, through its affiliate OERI, markets energy products, including natural gas and electric power, and provides energy related services for corporate commodity price risk management and energy forward price evaluations. Enogex also has investments in exploration and production of natural gas and oil with properties located primarily in Michigan and Oklahoma.
Recent Actions: In 2001, Enogex filed for fuel-recovery rate adjustments with FERC to resolve the under-recovery of pipeline system fuel expenses. FERC approved the new rates and they became effective on March 1, 2001.
Gas Transportation: One of Enogex's primary lines of business is the transportation of natural gas, which includes both interstate and intrastate transportation along with natural gas gathering in Oklahoma, Arkansas and Texas. Interruptible transportation service is offered to most interstate and intrastate pipelines and end-users connected to Enogex's systems. As mentioned previously, Enogex owns and operates the tenth largest natural gas pipeline in the United States in terms of miles of pipe in
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service (approximately 9,700 miles) that gather and transport gas from the Arkoma basin of eastern Oklahoma and Arkansas, the Anadarko basin of western Oklahoma and the Permian basin of west Texas.
In July 1999, Enogex acquired Tejas Transok Holding, L.L.C. and its subsidiaries ("Transok"). Transok was established in 1955 to transport boiler fuel to the gas-powered electric generating facilities of Public Service Company of Oklahoma ("PSO"). PSO, a subsidiary of Central and South West Corporation, is the second largest electric utility in Oklahoma, serving the Tulsa market. Transok was acquired by PSO in 1961 and maintained a sole-supplier relationship with PSO until 1998, when Oklahoma Natural Gas began supplying gas to three of the PSO generating stations pursuant to a competitive bid process put in place by the OCC. Notwithstanding the loss of the sole-supplier status, PSO remains an important customer of Transok. Transok continues to provide gas transmission delivery services to all of PSO's gas-fueled electric generation units in Oklahoma under a firm intrastate transportation contract. The current contract, which expires January 1, 2003, provides for a monthly demand charge plus a variable transportation rate depending on the origins of the gas supply being transported. In addition, Transok provides straight fee transportation services to West Texas Utilities ("WTU"), an affiliate of PSO, for gas delivery service to certain WTU generating stations in the Texas Panhandle under a contract that expires on December 31, 2004. In 2001, Transok's revenues from the PSO and WTU contracts were $13.3 million and $2.5 million, respectively.
The rates charged by Enogex and Transok for transporting natural gas on behalf of an interstate natural gas pipeline company or a local distribution company served by an interstate natural gas pipeline company are subject to the jurisdiction of the FERC under Section 311 of the Natural Gas Policy Act. This statute entitles Enogex and Transok to charge a "fair and equitable" rate that is subject to review and approval by the FERC at least once every three years. This rate review may involve an administrative-type trial and an administrative appellate review. In addition, Enogex and Transok have agreed to open their systems to all interstate shippers that are interested in transporting natural gas through the systems. Enogex and Transok are required to conduct this transportation on a non-discriminatory basis, although this transportation is subordinate to that performed for OG&E and PSO. This decision does not increase appreciably the federal regulatory burden on Enogex and Transok, but does give Enogex and Transok the opportunity to utilize any unused capacity on an interruptible basis and thus increase its transportation revenues.
Gas Processing: With the acquisition of Transok, Enogex is now one of the largest gas processors in the state of Oklahoma. Enogex now owns 11 gas processing plants, with an inlet capacity of over one billion cubic feet per day ("Bcfd"), and has ownership interest in two other gas processing plants, with an inlet capacity of 310 million cubic feet per day ("MMcfd"), on a net percentage of ownership basis. The gas processing operations are conducted through Enogex Products Corporation ("Products") and Transok. Products has been active since 1968 in the processing of natural gas and marketing of natural gas liquids. The NuStar Joint Venture ("NuStar"), in which Products owns an 80 percent interest, has been engaged in the processing of natural gas since 1951. Products' and NuStar's natural gas processing plant operations consist of the extraction and sale of natural gas liquids. The products extracted from Transok's natural gas stream include 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. All Transok processing plants are cryogenic expander processing plants capable of recovering or rejecting ethane.
A portion of the commercial grade propane processed at Products Calumet facility and two Transok plants are sold on the local market. The other natural gas liquids produced by Products and Transok are delivered into pipeline facilities of Koch Hydrocarbon ("Koch") and transported to Conway, Kansas and Mont Belvieu, Texas, where they are sold under contract or on the spot market. Ethane,
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which is produced at all plants except Calumet, is sold under a contract with Equistar Chemicals LP, Dow Hydrocarbons and Resources Inc. and Koch. Natural gas liquids from NuStar are sold to the Huntsman Chemicals plant (formerly Rexene Chemicals) in Midland, Texas.
In processing and marketing natural gas liquids, Enogex competes against virtually all other gas processors producing and selling natural gas liquids. Enogex believes it will be able to continue to compete favorably against such companies. With respect to the factors affecting the natural gas liquids industry generally, as the price of natural gas liquids fall without a corresponding decrease in the price of natural gas, it may become uneconomical to extract certain natural gas liquids. As explained under Item 7 of this report, this factor had a significant adverse impact on the results of Enogex during 2001. As to factors affecting Enogex specifically, the volume of natural gas processed at their plants is dependent upon the volume of natural gas gathered by Enogex and other gatherers through their pipeline systems. Generally, if the volume of natural gas gathered increases, then the volume of liquids extracted by Enogex should also increase.
Marketing: Commodity sales and services related to natural gas and electric power are conducted by Enogex primarily through its subsidiary OERI.
Natural Gas - Enogex's gas marketing is conducted through OERI. OERI also markets natural gas developed by Enogex Exploration Corporation ("Exploration") when volumes are sufficiently concentrated to justify OERI's involvement. OERI did not perform the gas purchasing function for OG&E during 2001.
OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas both on and off the Enogex pipeline system 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 allow OERI to leverage the strategic location of the Enogex system and its multiple interconnections with the interstate pipeline system that moves natural gas from the major producing basins in the south central United States to the natural gas consuming north central and mid Atlantic regions of the United States.
OERI participates in both long-term markets and short-term "spot" markets for natural gas. Although OERI continues to increase its focus on long-term sales, short-term sales of natural gas will continue to play a critical role in overall strategy because they provide an important source of market intelligence as well as an important portfolio balancing function.
OERI's risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. At the same time, price risk beyond OERI's risk tolerance on extended term gas purchase or sales contracts is hedged on the New York Mercantile Exchange futures exchange in accordance with corporate policy.
Electricity - OERI participates actively as a wholesale purchaser and reseller in the physical wholesale power markets of the mid-continent region. It has a fully-staffed 24-hour power desk that continually monitors the physical marketplace seeking to create value by matching market participants with power surpluses to those market participants with power needs. The expertise of OERI's power desk in managing customer relationships and the complexities of the transmission grid enable the continued ability to extract value from the marketplace. As the physical power broker for OG&E, OERI assists in the sale to and purchase from the physical power markets as required to meet the needs of
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OG&E. Since March 2000, virtually all of OG&E's surplus power sales activity has been performed by OERI.
Exploration and Production: The exploration and production activities are conducted through Exploration, which was formed in 1988 primarily to engage in the development and production of oil and natural gas. Exploration focused its early drilling activity in the Antrim Devonian shale trend in the state of Michigan but in recent years has concentrated on drilling opportunities in Oklahoma. As part of this refocusing, Exploration sold its interests in Texas and Utah during 2000. As of December 31, 2001, Exploration had interests in over 378 active wells and estimated proved reserves of 50,387 million cubic fees equivalent. In 1998, OERI initiated a program of hedging the future gas selling price on a portion of Exploration's net production through commodity futures contracts to cushion against unfavorable monthly price swings.
Additional Actions and Outlook: Beginning with the first quarter of 2002, Enogex's operations will be reported into four activities: Transportation and Storage, Gathering and Processing, Marketing and Trading and Exploration and Production. During 2002, the Company expects approximately 64 percent of Enogex's earnings before interest and taxes ("EBIT") to be generated by Transportation and Storage due to increased revenues attributable to, among other things, two new long-term transportation contracts with IPPs. Enogex utilizes natural gas storage both to capture price differentials between periods and to support transmission operations. Favorable price differentials are captured by putting physical gas into storage and entering into forward natural gas sales contracts. Storage margins may be optimized by selling physical gas in the cash market to capture short-term opportunities. The Company expects approximately 27 percent of Enogex's EBIT to be generated by Gathering and Processing due to increased revenues, increased fractionation spreads and a better processing environment. The Company's budgets for 2002 assumes a fractionation spread (i.e., the value of liquids after they are processed out of natural gas, less the gas itself) of $1.531 per MMBtu. A $0.10 per MMBtu change in the fractionation spread generally increases or decreases gross margin on revenues by approximately $2.3 million. In 2002, Enogex also began charging pipeline shippers a treating fee for gas that requires processing for delivery into interstate pipelines when the fractionation spreads are not sufficient to cover the cost of processing the gas, as was experienced in 2001. The Company expects approximately eight percent of Enogex's EBIT to be generated by Marketing and Trading through improved gas marketing efforts.
During 2002, the Company expects Enogex to continue to improve its operational performance by reducing the volatility related to natural gas processing. The Company continually monitors the market instruments available to hedge the fractionation spread, however, at this time there are no products available that in management's opinion satisfactorily accomplish this objective. Also, effective January 1, 2002, the Enogex and Transok pipeline systems have been merged to simplify for both Enogex and its customers and administration and operation of maintaining two separate pipelines.
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FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financing. Cash flows from operations have enabled the Company to internally generate the required funds to satisfy construction expenditures.
Management expects that internally generated funds will be adequate over the next three years to meet the Company's anticipated construction expenditures. The primary capital requirements and future contractual obligations for 2001 and as estimated for 2002 through 2005 and beyond are as follows:
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2005 and
(dollars in millions) 2001 2002 2003 2004 Beyond
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OG&E construction expenditures including AFUDC......... $132.3 $221.0 $113.0 $116.0 N/A
Enogex construction expenditures and acquisitions...... 83.4 30.0 37.0 33.0 N/A
Other Operations capital expenditures.................. 9.4 13.0 11.0 11.0 N/A
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Total capital expenditures.................... 225.1 264.0 161.0 160.0 N/A
Maturities of long-term debt........................... 12.0 115.0 14.3 53.0 1,461.6
Capital lease obligations.............................. 1.1 1.1 1.0 0.9 14.0
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Total capital requirements.................... 238.2 300.1 176.3 213.9 1,475.6
Operating lease obligations............................ 16.6 18.9 18.2 17.4 126.8
Unconditional purchase obligations:
Cogeneration capacity payments.................... 191.0 191.0 163.0 151.0 262.0
Other purchased power capacity payments........... 23.0 11.0 N/A N/A N/A
Fuel minimum purchase commitments................. 120.0 134.0 135.0 127.0 654.0
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Total unconditional purchase obligations...... 334.0 336.0 298.0 278.0 916.0
Total capital requirements, operating lease obligations
and unconditional purchase obligations............. 588.8 735.0 492.5 509.3 2,518.4
Amounts recoverable through automatic fuel
adjustment clause.................................. (344.3) (349.1) (312.5) (292.5) (1,032.9)
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Total, net.................................... $244.5 $385.9 $180.0 $216.8 $1,485.5
===========================================================================================================
N/A - not applicable
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In January 2002, a significant ice storm hit OG&E's service territory. This ice storm inflicted major damage to the transmission and distribution infrastructure. Total expenditures are currently estimated at $136 million. The OG&E 2002 construction expenditures in the above chart include the costs for restoration of the electric utility's system. The Company believes its short-term borrowing capacity is adequate to finance the restoration of the system. The area of damage is within counties that were declared a federal disaster area. OG&E intends to pursue a plan with the OCC to seek recovery of this cost in future rates.
The Company's primary needs for capital are related to replacing or expanding existing facilities in OG&E's electric utility business and to replacing or expanding existing facilities at Enogex. Other capital requirements are primarily related to maturing debt, capital and operating lease obligations and unconditional purchase obligations.
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 electric customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related operating leases and the vast majority of unconditional purchase obligations of OG&E may increase capital requirements, such costs are recoverable through automatic fuel adjustment clauses and have little, if any, impact on total net capital requirements. The automatic 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 Enogex, which OG&E seeks to recover through the fuel adjustment clause or other tariffs.
The Company's construction program for the next several years does not include additional base-load generating units. Rather, to meet the increased electricity needs of OG&E's electric utility customers during the foreseeable future, OG&E will concentrate on maintaining the reliability and increasing the utilization of existing capacity, increasing demand-side management efforts and, if necessary, purchasing capacity from third parties. OG&E will continue to evaluate these strategies against the construction of additional peaking units or another base-load generating unit. These evaluations will consider, among other things, the amount of capital requirements and the relative cost of fuel supply, compared to other alternatives. Approximately $2.3 million of the Company's construction expenditures budgeted for 2002 are to comply with environmental laws and regulations.
The Company will continue to use short-term borrowings to meet temporary cash requirements. OG&E has the necessary approvals to incur up to $400 million in short-term borrowings at any one time. At December 31, 2001, the Company had in place a line of credit for up to $315 million, with $200 million expiring on January 15, 2002, $15 million expiring on June 26, 2002, and $100 million expiring on January 15, 2004. In January 2002, the Company's $200 million line of credit was renewed for $195 million, with an expiration date of January 19, 2003. Short-term borrowings will consist of some combination of bank borrowings and commercial paper. The Company's ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The line of credit contains ratings triggers that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of a downgrade would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers.
The Company continues to evaluate opportunities to enhance shareowner returns and achieve long-term financial objectives through acquisitions of assets that may complement its existing portfolio. Permanent financing could be required for such acquisitions if one was to occur.
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The Company's financial results continue to be substantially impacted by the rates OG&E charges customers and the actions of the regulatory bodies that set those rates, the amount of energy used by OG&E's customers, the cost and availability of external financing and the cost of conforming to government regulations.
ENVIRONMENTAL MATTERS
The Company's management believes all of its operations are in substantial compliance with present federal, state and local environmental standards. It is estimated that the Company's total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $44.2 million during 2002, compared to approximately $42.7 million utilized in 2001. Approximately $2.3 million of the Company's construction expenditures budgeted for 2002 are to comply with environmental laws and regulations. The Company continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position itself in a competitive market.
As required by Title IV of the Clean Air Act Amendments of 1990 ("CAAA"), OG&E has completed installation and certification of all required continuous emissions monitors at its generating stations. OG&E submits emissions data quarterly to the Environmental Protection Agency ("EPA") as required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements affected OG&E beginning in the year 2000. OG&E met the SO2 limits without additional capital expenditures due to OG&E's earlier decision to purchase low sulfur coal. In 2001, OG&E's SO2 emissions were well below the allowable limits.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of the CAAA, OG&E committed to meeting a 0.45 lbs/MMBtu NOx emission level in 1997 on all coal-fired boilers. As a result, OG&E was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. OG&E's average NOx emissions from its coal-fired boilers for 2001 was 0.33lbs/MMBtu.
OG&E has submitted all of its required Title V permit applications. As a result of the Title V Program, OG&E paid approximately $0.5 million in fees in 2001.
Other potential air regulations have emerged that could impact OG&E. On December 14, 2000, the EPA announced its decision to regulate mercury emissions from coal-fired utility boilers. Limits on the amount of mercury emitted are expected to be finalized by December 2004, although full compliance by OG&E is not expected to be required until 2008. Depending upon the final regulations implemented, this could result in significant capital and operating expenditures.
In 1997, the EPA finalized revisions to the ambient ozone and particulate standards. However, the standards were challenged in court and the ozone standard was subsequently remanded back to the EPA for further consideration. The EPA appealed the decision to the U.S. Supreme Court and the Supreme Court issued its decision on February 27, 2001. In its decision, the Supreme Court remanded the case to the District of Columbia Court of Appeals, in part, to allow additional challenges to the standards. If the proposed standard is eventually upheld, then it is likely that Tulsa County will fail to meet the new standard for ozone. The EPA has already indicated that in addition to Tulsa County, Muskogee County will also be considered non-attainment because of its impact on Tulsa. If this occurs NOx reductions at OG&E's Muskogee Generating Station could be required. In addition, the EPA projects that Muskogee, Kay, Tulsa and Comanche Counties in Oklahoma would fail to meet the
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standard for particulate matter. If reductions are required in Muskogee, Kay and Oklahoma Counties, significant capital expenditures could be required by OG&E.
The EPA also has issued regulations concerning regional haze. These regulations are intended to protect visibility in national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains would be the only area covered under the regulation. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. Under these regulations, it is possible that controls on emission sources hundreds of miles away from the affected area may be required. The EPA has begun the process of determining what, if any, impact emission sources in Oklahoma have on national parks and wilderness areas. If an impact is determined, then significant capital expenditures could be required for both Sooner and Muskogee Generating Stations.
In 1997, the United States was a signatory to the Kyoto Protocol on global warming. While the Protocol is not likely to be ratified by the U.S. Senate, legislation has been drafted that would limit carbon dioxide emissions. If legislation is passed this could have a tremendous impact on OG&E's operations, by requiring OG&E to significantly reduce the use of coal as a fuel source.
OG&E has and will continue to seek new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2001, OG&E obtained refunds of approximately $211,000 from its recycling efforts. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to reuse of existing materials. Similar savings are anticipated in future years.
OG&E has received approvals to renew its Oklahoma Pollution Discharge Elimination System ("OPDES") permits for all facilities except one, which is awaiting final regulatory action. All of the renewed permits issued to date offer greater operational flexibility than those in the past. In addition, OG&E has made application for a new OPDES permit to cover gas turbine generating units that were constructed at one of its existing plants.
OG&E requested that the State agency responsible for the development of Water Quality Standards remove the agriculture beneficial use classification from one of its cooling water reservoirs. Without removal of this classification, OG&E could be subjected to costly treatment and/or facility reconfiguration requirements. Both the State and EPA have now approved this request.
Enogex, like OG&E, is subject to numerous environmental laws and regulations that affect its operations. See Item 3 "Legal Proceedings" for a description of a recent consent decree and pending notices of violations involving Enogex's operations.
The Company has and will continue to evaluate the impact of its operations on the environment. As a result, contamination on Company property may be discovered from time to time. One site has been identified as having been contaminated by historical operations. Remedial options based on the future use of this site are being pursued with appropriate regulatory agencies. The cost of these actions has not had and is not anticipated to have a material adverse impact on the Company's consolidated financial position or results of operations.
EMPLOYEES
The Company and its subsidiaries had 3,255 employees at December 31, 2001.
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Item 2. Properties.
OG&E owns and operates an interconnected electric production, transmission and distribution system, located in Oklahoma and western Arkansas, which includes eight generating stations with an aggregate capability of 5,732 megawatts. The following table sets forth information with respect to electric generating facilities, all of which are located in Oklahoma:
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
Seminole 1 Gas 1971 517.0
2 Gas 1973 505.0
3 Gas 1975 508.0 1,530
Muskogee 3 Gas 1956 149.0
4 Coal 1977 515.0
5 Coal 1978 514.0
6 Coal 1984 502.0 1,680
Sooner 1 Coal 1979 503.0
2 Coal 1980 505.0 1,008
Horseshoe 6 Gas 1958 154.0
Lake 7 Gas 1963 227.0
8 Gas 1969 390.0
9 Gas 2000 46.0
10 Gas 2000 46.0 863
Mustang 1 Gas 1950 55.0
2 Gas 1951 51.0
3 Gas 1955 115.0
4 Gas 1959 248.0
5 Gas 1971 65.0 534
Conoco 1 Gas 1991 32.0
2 Gas 1991 31.0 63
Enid 1 Gas 1965 11.0
2 Gas 1965 10.0
3 Gas 1965 11.0
4 Gas 1965 12.0 44
Woodward 1 Gas 1963 10.0 10
-----------
Total Generating Capability (all stations) 5,732
===========
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At December 31, 2001, OG&E's transmission system included: (i) 31 substations with a total capacity of approximately 13.3 million kilo Volt-Amps ("kVA") and approximately 4,002 structure miles of lines in Oklahoma; and (ii) two substations with a total capacity of approximately 1.4 million kVA and approximately 252 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 335 substations with a total capacity of approximately 7.4 million kVA, 22,403 structure miles of overhead lines, 1,783 miles of underground conduit and 7,246 miles of underground conductors in Oklahoma; and (ii) 36 substations with a total capacity of approximately 1.2 million kVA, 1,870 structure miles of overhead lines, 209 miles of underground conduit and 424 miles of underground conductors in Arkansas.
At December 31, 2001, Enogex and its subsidiaries own: (i) approximately 9,700 miles of intrastate transmission and gathering lines in the states of Oklahoma and Texas; (ii) 11 natural gas processing plants with a capacity to process over one Bcfd, all located in Oklahoma; (iii) 75 percent interest in NOARK, which consists of 925 miles of interstate transmission and gathering pipelines, located in eastern Oklahoma and Arkansas; (iv) an 18 billion cubic feet ("Bcf") gas storage field in Oklahoma with a withdrawal capacity of 450 MMcfd; (v) five Bcf of gas storage in Oklahoma with a withdrawal capacity of 400 MMcfd; (vi) an 80 percent interest in NuStar, which includes a 66.67 percent interest in the 110 MMcfd capacity Benedum processing plant, a 100 percent interest in a smaller 30 MMcfd by-pass plant, over 200 miles of gathering pipelines and 52 miles of NGL pipeline, all located in the Permian Basin of west Texas; and (vii) 100 percent of the Belvan Corp., which consists of a natural gas processing plant with a capacity of process 15 MMcfd, a sulfur recovery plant, and an eight mile NGL pipeline, and 344 miles of gathering lines in west Texas. See Note 13 of Notes to Consolidated Financial Statements for a discussion of recent actions concerning Belvan Corp.
During the three years ended December 31, 2001, the Company's gross property, plant and equipment additions approximated $1.1 billion and gross retirements approximated $143.3 million. These additions were provided by internally generated funds from operating cash flows, permanent financing and short-term borrowings. The additions during this three-year period amounted to approximately 23 percent of total property, plant and equipment at December 31, 2001.
Item 3. Legal Proceedings.
In the normal course of business, various lawsuits and claims have risen against the Company. When appropriate, management, after consultation with legal counsel, records an estimate of the probable cost of settlement or other disposition for such matters to the extent not covered by insurance or recoverable through regulated rates.
1. The City of Enid, Oklahoma ("Enid") through its City Council, notified OG&E of its intent to purchase OG&E's electric distribution facilities for Enid and to terminate OG&E's franchise to provide electricity within Enid as of June 26, 1998. On August 22, 1997, the City Council of Enid adopted Ordinance No. 97-30, which in essence granted OG&E a new 25-year franchise subject to approval of the electorate of Enid on November 18, 1997. In October 1997, 18 residents of Enid filed a lawsuit against Enid, OG&E and others in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-829-01. Plaintiffs seek a declaration holding that (i) the Mayor of Enid and the City Council breached their fiduciary duty to the public and violated Article 10, Section 17 of the Oklahoma Constitution by allegedly "gifting" to OG&E the option to acquire OG&E's electric system when the City Council approved the new franchise by Ordinance No. 97-30; (ii) the subsequent approval of the new franchise by the electorate of the City of Enid at the November 18, 1997, franchise election cannot cure the alleged breach of fiduciary duty or the alleged constitutional violation; (iii) violations of the Oklahoma Open Meetings Act occurred and that such violations render the resolution approving Ordinance No. 97-30 invalid; (iv) OG&E's support of the Enid Citizens' Against the Government
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Takeover was improper; (v) OG&E has violated the favored nations clause of the existing franchise; and (vi) the City of Enid and OG&E have violated the competitive bidding requirements found at 11 O.S. 35-201, et seq. Plaintiffs seek money damages against the Defendants under 62 O.S. 372 and 373. Plaintiffs allege that the action of the City Council in approving the proposed franchise allowed the option to purchase OG&E's property to be transferred to OG&E for inadequate consideration. Plaintiffs demand judgment for treble the value of the property allegedly wrongfully transferred to OG&E. On October 28, 1997, another resident filed a similar lawsuit against OG&E, Enid and the Garfield County Election Board in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-852-01. However, Case No. CJ-97-852-01 was dismissed without prejudice in December 1997. On December 8, 1997, OG&E filed a Motion to Dismiss Case No. CJ-97-829-01 for failure to state claims upon which relief may be granted. This motion is currently pending. While the Company cannot predict the precise outcome of this proceeding, the Company believes at the present time that this lawsuit is without merit and intends to vigorously defend this case.
2. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation (now, OGE Energy Resources Inc.) and OG&E. (United States 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. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.) On June 15, 1999, the Company was served with Plaintiff's Complaint. Plaintiff's action is a qui tam action under the False Claims Act. Jack J. Grynberg, as individual Relator on behalf of the United States Government, Plaintiff, alleges: (i) each of the named Defendants have improperly and intentionally mismeasured gas (both volume and Btu content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) 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. Plaintiff has filed over 70 other cases naming over 300 other defendants in various Federal Courts across the country containing nearly identical allegations.
In qui tam actions, the United States Government can intervene and take over such actions from the Relator. The Department of Justice, on behalf of the United States Government, has decided not to intervene in this action or any of the other Grynberg qui tam actions.
On November 16, 1999, the Multidistrict Litigation Panel ("MDL Panel") entered its order transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.
On November 17, 1999, the Company filed a motion to dismiss, seeking: (i) a stay of discovery until after the dispositive motions are resolved; and (ii) dismissal of the complaint on various bases under the Federal Rules of Civil Procedure. A number of other defendants adopted the Company's pleadings or filed similar motions. On December 22, 1999, the Company joined a number of other defendants in filing Defendants' Statement of Points and Authorities regarding discovery issues. Grynberg's responses to all motions to dismiss were filed on January 14, 2000, and the Company's reply and those of other defendants were filed on February 14, 2000. A hearing on the motions to dismiss was held on March 17, 2000. Plaintiffs supplemented their Response on January 11, 2001. The Company filed a
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Response to Plaintiffs' Supplement on January 23, 2001. The Court denied the Company's Motion to Dismiss on May 18, 2001.
On April 10, 2000, the MDL Panel transferred another qui tam case (Quinque Operating Company, et al. v. Enogex Services Corporation, Enogex, Inc., Transok LLC, Transok, Inc., and Oklahoma Gas & Electric Company, et al.) ("Quinque") to Judge Downes in Wyoming and the MDL Panel consolidated it with this case.
On July 27, 2000, the Department of Justice ("DOJ") filed a Motion to Dismiss certain of Grynberg's claims on the basis Grynberg was not the first to file such qui tam allegations. On August 28, 2000, Grynberg filed his Response to the DOJ's Motion. On September 8, 2000, the DOJ filed its Reply. On November 16, 2000, Grynberg filed a Supplement. The DOJ's Motion to Dismiss was heard on February 22, 2001. The Court has not yet ruled on the DOJ's Motion to Dismiss.
3. On September 24, 1999, the Company was served with an Amended Class Action Petition filed in United States District Court, State of Kansas by Quinque Operating Company, on behalf of itself and others, alleging approximately 200 defendants, including OG&E, Enogex and two subsidiaries of Enogex, including Transok, have improperly and intentionally mismeasured gas (both volume and Btu content) purchased from all lands in the United States except from federal and Indian lands. Plaintiffs claim: (i) underpayment by the Company and all other Defendants of gas royalties claimed to be owed to the Plaintiffs and the punitive class; (ii) breach of contract; (iii) negligence or intentional misrepresentation; (iv) civil conspiracy; (v) fraud; and (vi) breach of fiduciary duty. Plaintiffs seek the following damages: (a) actual damages in excess of $75,000; (b) punitive damages; (c) certification of the class; and (d) injunction to prevent mismeasurement in the future.
On October 5, 1999, the Company filed its Notice with the MDL Panel advising the MDL Panel of a possible tag-along action to the Grynberg qui tam actions discussed in Item 3, number 2 above. On April 10, 2000, the MDL Panel transferred this case to Judge Downes in Wyoming and consolidated it with the Grynberg cases above.
On September 8, 2000, Plaintiffs filed a Motion for Expedited Hearing on Motion to Remand. On January 12, 2001, the Court issued its oral order granting Plaintiff's Motion to Remand. The Court is currently reviewing a Motion to Reconsider before sending the Order to the Stevens County Clerk, effectively remanding the case back to the Kansas State Court.
On September 12, 2001, the Company filed a Motion to Dismiss Plaintiffs' Second Amended Petition for failure to state a claim, and included a request for dismissal based on lack of personal jurisdiction. The Reply was filed by the Company on November 2, 2001. Oral argument on the Motion to Dismiss was held on November 29, 2001. The Court has not yet ruled.
A Discovery Planning Conference will be held by the Court on January 13, 2003. Until then, all discovery is stayed except for limited discovery related to Defendants' Motions to Dismiss for lack of personal jurisdiction and discovery related to class certification. The Company has asserted a personal jurisdiction defense.
The Company intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, we are unable to comment on any potential exposure to loss of the Company or likely outcome at this time.
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4. In April, 2001, Enogex received a Notice of Violation ("NOV") from the Oklahoma Department of Environmental Quality )"ODEQ") regarding potential permitting issues at its Verden Compressor Station, acquired in the Transok acquisition. The NOV related to the operation of a glycol dehydrator and alleged: (1) Enogex had not utilized the proper mechanism to evaluate emissions from the glycol dehydrator; (2) the Facility was subject to the recently promulgated Maximum Achievable Control Technology ("MACT"); (3) failure to install MACT on the dehydrator; (4) deficiencies and/or absence of air quality major source construction/operating permits and periodic reports; and (5) exceedance of certain air quality permit limits. After working closely with the ODEQ to resolve the issues raised in the NOV, the parties finalized a Consent Order on February 4, 2002, pursuant to which Enogex has taken the following actions: (1) installed the required MACT and Best Available Control Technology ("BACT"); (2) filed a Title V operating permit application; (3) conducted performances tests on the control equipment, filed the test results and filed all required periodic reports; and (4) paid a $103,150 penalty on February 6, 2002. Installation of the MACT cost approximately $40,000.
Similar emission and permitting issues relating to glycol dehydration may exist at nine (9) other Enogex facilities. The ODEQ has issued NOV's for these sites and Enogex is working with the ODEQ to attempt to resolve the issues at these sites. The allegations in these NOV's are essentially similar to the allegations contained in the NOV relating to the Verden Compressor Station.
The ODEQ has submitted proposed consent orders relating to four of the sites (Custer Electric Compressor Station, Grandview Compressor Station, Maple Compressor Station, and Thomas Tie Compressor Station). The proposed consent orders would require Enogex to install BACT at a cost ranging from $20,000 to $40,000 per Station, file permits, establish periodic reporting procedures and pay penalties. The penalties proposed by the ODEQ do not exceed $100,000 individually, but in the aggregate total approximately $200,000. Enogex is negotiating with the ODEQ to eliminate or reduce the proposed penalties and to allow Enogex to apply supplemental environmental projects to any penalty amounts assessed for each specific facility.
For the five remaining sites (Clinton Gas Plant, Comanche Tap Gas Processing Plant, Moorewood Compressor Station, South Oakwood Compressor Station and Strong City Compressor Station) the ODEQ and Enogex are currently exchanging information and no specific actions or penalties have been proposed. Enogex expects to resolve the issues at these remaining sites in a manner similar to that proposed above. Enogex believes that the amounts of any penalty or expenditures for supplemental environmental projects will not exceed $100,000 for any single facility but in the aggregate may exceed $100,000.
Enogex continues to monitor its operations to insure compliance with applicable air quality permitting and other environmental requirements.
Item 4. Submission of Matters to a Vote of Security Holders.
None
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Executive Officers of the Registrant.
The following persons were Executive Officers of the Registrant as of March 15, 2002:
Name Age Title
- -------------------- --- --------------------------------
Steven E. Moore 55 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 58 Executive Vice President and
Chief Operating Officer
Roger A. Farrell 49 President and Chief Executive
Officer - Enogex Inc.
James R. Hatfield 44 Senior Vice President and
Chief Financial Officer
Jack T. Coffman 58 Senior Vice President - Power
Supply
Melvin D. Bowen, Jr. 60 Vice President - Electric Services
Michael G. Davis 52 Vice President - Process Management
Irma B. Elliott 63 Vice President and
Corporate Secretary
Steven R. Gerdes 45 Vice President - Shared
Services
David J. Kurtz 40 Vice President - Business
Development
Donald R. Rowlett 44 Vice President and Controller
Don L. Young 61 Internal Audit Officer
Eric B. Weekes 50 Treasurer
Gary D. Huneryager 51 Assistant Internal Audit Officer
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Strecker, Hatfield, Davis, Gerdes, Rowlett, Young, Weekes, Huneryager and Ms. Elliott 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 16, 2002.
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The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
Name Business Experience
- -------------------- -------------------------------------------------
Steven E. Moore 1997-Present: Chairman of the Board,
President and Chief
Executive Officer
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1997-1998: Senior Vice President
Roger A. Farrell 1998-Present: President an