ITEM 1. BUSINESS
GENERAL
Energen Corporation is a Birmingham-based diversified energy holding company engaged primarily in the acquisition, development, exploration and production of oil, natural gas and natural gas liquids in the continental United States and in the purchase, distribution, and sale of natural gas, principally in central and north Alabama. Its two major subsidiaries are Energen Resources Corporation and Alabama Gas Corporation (Alagasco).
Energen was incorporated in Alabama in 1978 in connection with the reorganization of its oldest subsidiary, Alagasco. Alagasco was formed in 1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. Alagasco became a public company in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco and became a subsidiary of Energen in the 1978 reorganization.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is provided in Note 17, Industry Segment Information, in the Notes to Financial Statements.
NARRATIVE DESCRIPTION OF BUSINESS
- - OIL AND GAS OPERATIONS
GENERAL: Energen's oil and gas operations focus on increasing production and adding proved reserves through the acquisition and exploitation of oil and gas properties with varying levels of development potential. To a lesser extent, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. Energen Resources also provides operating services in the Black Warrior Basin in Alabama for its partners and third parties. All current oil and gas operations are located in the continental United States.
At the end of fiscal year 2001, Energen Resources' inventory of proved oil and gas reserves totaled 0.9 trillion cubic feet equivalent. Approximately 96 percent of the company's 901.9 billion cubic feet equivalent (Bcfe) of reserves are located in the San Juan Basin in New Mexico, the Black Warrior Basin in Alabama, the Permian Basin in west Texas, and the north Louisiana/east Texas region. Energen Resources' reserve base is conservative in nature, with approximately 91 percent of year-end reserves classified as proved developed; in addition, the reserve base is long-lived, with a reserves-to-production ratio of 13 at fiscal year-end. Natural gas represents approximately 70 percent of Energen Resources' proved reserves, with oil and natural gas liquids comprising the balance.
GROWTH STRATEGY: Energen has completed six years under an aggressive strategy to grow its non-regulated oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $542 million in property acquisitions, $287 million in related development, and $80 million in exploration and associated development. Energen Resources' capital investment for oil and gas activities over the five-year period ending September 30, 2006, is expected to be approximately $1 billion.
Energen Resources' approach to the oil and gas business calls for the company to pursue onshore North American property acquisitions which offer significant amounts of proved undeveloped (PUD) and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers gas to oil properties, long-lived reserves and operated properties that offer multiple pay-zone exploitation opportunities; however, Energen Resources does not preclude possible acquisitions of properties that otherwise meet its investment requirements.
Following an acquisition, Energen Resources focuses on increasing production and reserves through exploitation of the properties' PUD and behind-pipe reserve potential. These exploitation activities include development well drilling, behind-pipe recompletions, workovers, secondary recovery and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of exploitation activities. Energen Resources' exploitation activities can result in the addition of new proved reserves as well as serve to reclassify proved undeveloped reserves to proved developed reserves.
Over the last three fiscal years the Company's exploitation efforts have added approximately 245 Bcfe of proved reserves from the drilling of approximately 395 gross development wells and the performance of some 405 well recompletions and pay-adds. In fiscal year 2001, Energen Resources' successful development wells and other exploitation activities added approximately 50 Bcfe of proved reserves. The company drilled 140 gross development wells, performed some 145 well recompletions and pay-adds, and conducted other performance-related enhancements. Energen Resources' production totaled 68.5 Bcfe in fiscal 2001 and, is estimated to total 73 Bcfe in fiscal 2002, including 4.5 Bcfe of production from anticipated acquisitions and exploration activity.
Most of Energen Resources' coalbed methane production generates nonconventional fuels tax credits through December 31, 2002, when the credits are scheduled to expire. In fiscal 2001, Energen Resources' nonconventional fuels tax credits totaled $13.6 million; and, in fiscal years 2002 and 2003, Energen Resources expects to generate approximately $13 million and $3 million, respectively, of the production credits. These credits have been instrumental in Energen Resources' successful development of large-scale coalbed methane projects in the Black Warrior Basin. As the tax credit expiration date approaches, Energen Resources plans to replace income generated by the tax credits with long-term, revenue-generating property acquisitions and related development in a manner that does not negatively affect corporate earnings in fiscal year 2003 and beyond.
RISK MANAGEMENT: Energen Resources attempts to lower the risk associated with its oil and gas business. A key component of the company's efforts to manage risk is its acquisition versus exploration orientation and its
preference for long-lived reserves. To help reduce short-term commodity price risk, Energen Resources uses market-driven pricing estimates and hedging strategies. In pursuing an acquisition, Energen Resources primarily uses in its evaluation models the then-current oil and gas futures prices, the prevailing swap curve and, for the longer-term, its own pricing assumptions. After a purchase, Energen Resources may use futures, swaps and/or fixed-price contracts to lock in commodity prices on flowing production for up to 36 months to help protect targeted returns from price volatility. On an on-going basis, Energen Resources may hedge up to 80 percent of its flowing production in any given fiscal year depending on its pricing outlook.
At September 30, 2001, Energen Resources had entered into contracts and swaps for 9.3 Bcf of its fiscal 2002 gas production at an average NYMEX price of $3.84 per Mcf and 478 MBbl of its oil production at an average NYMEX price of $27.44 per barrel. Energen Resources had basin-specific hedges in place for 3.6 Bcf of gas production at an average contract price of $4.30 per Mcf and 0.8 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf. In addition, the Company had hedged the basis difference on 6 Bcf of its gas production and 202 MBbl of its oil production.
As of September 30, 2001, Energen Resources had entered into basin-specific swaps for 1.9 Bcf of its gas production at an average contract price of $3.77 per Mcf for fiscal year 2003. For fiscal 2004 and 2005, Energen Resources had entered into swaps for 1.8 Bcf and 1.6 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.
In addition to the derivatives described above, Energen Resources has three-way pricing, physical sales contracts in place for approximately 30 percent and 19 percent of its estimated gas production, excluding anticipated acquisition and exploration volumes, in fiscal years 2002 and 2003, respectively. This is more fully described in Note 7, Commitments and Contingencies, in the Notes to Financial Statements.
See Note 18, Subsequent Event, for discussion regarding Enron North America Corp.'s bankruptcy filing, which raises uncertainty as to their ability to perform under its contracts included in the derivatives described above.
The Company adopted SFAS No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting for Derivative Instruments and Hedging Activities," on October 1, 2000. This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change.
See the Forward-Looking Statement and Risk in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion with respect to price and other risk.
ENVIRONMENTAL MATTERS: Energen Resources is subject to various environmental regulations. Management believes that Energen Resources is in compliance with currently applicable standards of the environmental agencies to which it is subject and that potential environmental liabilities, if any, are minimal. Also, to the extent that Energen Resources has operating agreements with various joint venture partners, environmental costs, if any, would be shared proportionately.
OTHER: For a discussion of risks inherent in the Company's businesses, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
- - NATURAL GAS DISTRIBUTION
GENERAL: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate marketers and suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from producers, marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers' facilities.
Alagasco's service territory is located in central and parts of north Alabama and includes approximately 188 cities and communities in 27 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.3 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During fiscal year 2001, Alagasco served an average of 428,663 residential customers and 35,882 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 9,600 miles of main and more than 11,100 miles of service lines, odorization and regulation facilities, and customer meters.
APSC REGULATION: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which, in 1983, established the Rate Stabilization and Equalization (RSE) rate setting process. RSE was extended with modifications in 1990, 1987 and 1985. On October 7, 1996, RSE was extended, without change, through January 1, 2002, and will continue after January 1, 2002, unless, after notice to the Company and a hearing, the APSC votes to either modify or discontinue its operation. RSE replaced the traditional utility rate case with quarterly reviews and adjustments designed to give Alagasco an opportunity to earn a return on average equity at year-end within a designated range, which presently is 13.15 percent to 13.65 percent.
Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and fiscal year-to-date performance, whether Alagasco's return on equity for the fiscal year will be within the allowed range. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each fiscal year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expenses. If the change in O&M per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index for All Urban Consumers (index range), no adjustment is required. If the change in O&M per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments.
The temperature adjustment rider to Alagasco's rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco performs this real-time temperature adjustment calculation monthly, and the adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that permits the pass-through to customers of changes in the cost of gas supply.
The APSC approved an Enhanced Stability Reserve (ESR) beginning fiscal year 1998 in the amount of $3.9 million, with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a fiscal year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the fiscal year, if such losses cause Alagasco's return on equity to fall below 13.15 percent. During 2001, Alagasco charged $1.2 million against the ESR related to extraordinary bad debt expense and revenue losses from certain large industrial customers. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is
achieved. At September 30, 2001 and 2000, the ESR balance of $2.7 million and $3.9 million, respectively, was included in the consolidated financial statements.
GAS SUPPLY: Alagasco's distribution system is connected to and has firm transportation contracts with two major interstate pipeline systems - Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Corporation (Transco). On Southern's system, Alagasco has 251,679 Mcfd (thousand cubic feet per day) of No-Notice Firm Transportation service through October 31, 2008, and 40,000 Mcfd and 92,373 Mcfd of Firm Transportation service through April 30, 2005 and October 31, 2008, respectively. The Transco Firm Transportation contract, which expires October 31, 2002, provides for up to 100,000 Mcfd. Alagasco has requested proposals for replacement of the Transco Firm Transportation contracts and expects to have a new contract in place when the existing contract expires. As a result, Alagasco has a peak day firm interstate pipeline transportation capacity of 484,052 Mcfd. Alagasco has 12,464,074 Mcf of storage capacity on Southern's system, with a maximum withdrawal rate of 251,679 Mcfd from storage and a maximum injection rate of 95,878 Mcfd to storage. Alagasco also operates two liquified natural gas (LNG) facilities used to meet peak demand. During 2001 Alagasco replaced the liquifier at one of its LNG facilities.
Alagasco purchases gas from various gas producers and marketers, including affiliates of Southern and Transco, and from certain intrastate producers and marketers. Alagasco has contracts in place to purchase up to 293,776 Mcfd of firm supply, of which 232,373 Mcfd is supported by firm transportation on the Transco and Southern systems and approximately 21,700 Mcfd is purchased at the city gate under intrastate firm supply contracts. These firm supply volumes along with Alagasco's maximum withdrawal from storage of 251,679 Mcfd and LNG peak-shaving capacity of 200,000 Mcfd, give Alagasco a peak day firm supply of 745,455 Mcfd. Alagasco also utilizes the Southern pipeline systems to access spot market gas in order to supplement its firm system supply and serve its industrial and large commercial transportation customers. Deliveries of sales and transportation gas totaled 99,107 million cubic feet in fiscal year 2001.
See Note 18, Subsequent Event, for discussion related to contracts Alagasco had in place with Enron North America Corp.
COMPETITION AND RATE FLEXIBILITY: The price of natural gas is a significant competitive factor in Alagasco's service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and/or alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customers' gas load in the deregulated marketplace. Rate flexibility remains critical as the utility faces competition for the large customer load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas.
In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs. Alagasco's core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and small commercial and industrial customers. In fiscal year 2001, approximately 300 of Alagasco's transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled approximately $7.2 million.
The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco's ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco's tariff allows the Company to recover the reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system's fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco's sales profit margin so that operating margins are unaffected. During 2001 substantially all of Alagasco's large commercial and industrial
customer deliveries were the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for approximately 99 percent of its transportation customers. Alagasco also uses long-term special contracts as a vehicle for retaining large customer load. At the end of fiscal year 2001, 44 of the utility's largest commercial and industrial transportation customers were under special contracts of varying lengths.
Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption by Alagasco for various reasons; the most common occurrence is curtailment of industrial customers during periods of peak core market heating demand. Interruptible service typically is provided to large commercial and industrial transportation customers who can reduce their gas consumption by adjusting production schedules or by switching to alternate fuels for the duration of the service interruption. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and small commercial and industrial customers; these core market customers depend on natural gas primarily for space heating.
GROWTH: Customer growth presents a major challenge for Alagasco, given its mature, slow-growth service area. In fiscal year 2001, Alagasco's average number of customers remained relatively flat while penetrating 92 percent of the new single-family housing market in its service area and 16 percent of the new multi-family housing market. For fiscal year 2002, Alagasco will continue its efforts to increase gas usage by focusing on conversion prospects and by promoting, in addition to gas furnaces and water heaters, other energy-efficient natural gas products such as fireplace logs, outdoor gaslights, grills, ovens and cooktops. In addition, Alagasco will continue to pursue opportunities to invest in revenue-generating or cost-saving projects.
A vehicle for supplementing Alagasco's normal growth continues to be Alagasco's municipal acquisition program. Since 1985, Alagasco has acquired 23 municipally owned systems adding more than 43,000 customers through initial system purchases and subsequent customer additions. In September 2001, Alagasco acquired a municipal gas system located in central Alabama, adding approximately 1,000 customers in its service territory. Approximately 75 municipal systems remain in Alabama. Alagasco will continue to pursue the purchase of municipal gas systems, and company management believes that such acquisitions offer future growth opportunities.
SEASONALITY: Alagasco's gas distribution business is highly seasonal since a material portion of the utility's total sales and delivery volumes is to space heating customers. Alagasco's rate tariff includes a temperature adjustment rider primarily for residential, small commercial and small industrial customers which substantially mitigates the effect of departures from normal temperature on Alagasco's earnings. The calculation is performed monthly, and adjustments are made to customers' bills in the actual month the weather variation occurs.
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former manufactured gas plant sites and five manufactured gas distribution sites. It still owns four of the plant sites and one of the distribution sites. An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share of any associated costs will not materially affect the results of its operations or financial condition.
OTHER: For a discussion of risks inherent in the Company's businesses, see Management's Discussion and Analysis of Financial Condition and Results of Operations as set forth in Item 7 of Part II of this Form 10-K.
EMPLOYEES
The Company has 1,485 employees; Alagasco employs 1,266; Energen Resources employs 206; and Energen's other subsidiaries employ 13. The Company believes that its relations with its employees are good.
ITEM 2.
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. In addition to its corporate headquarters in Birmingham, Energen Resources maintains leased offices in Houston and Midland, Texas, in Farmington, New Mexico and in Arcadia, Louisiana.
For a description of Energen Resources' oil and gas properties, see the discussion under Item 1 - Business. Information concerning Energen Resources' production, reserves and development is included in Note 16, Oil and Gas Operations (unaudited), in the Notes to Financial Statements which is included in this Form 10-K. The proved reserve estimates are consistent with comparable reserve estimates filed by Energen Resources with any federal authority or agency.
The properties of Alagasco consist primarily of its gas distribution system, which includes more than 9,600 miles of main, more than 11,100 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two liquified natural gas facilities, seven division offices, six payment centers, five district offices, nine service centers, and other related property and equipment, some of which are leased by Alagasco. For a further description of Alagasco's properties, see discussion under Item 1 - Business.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages thus making it difficult to predict litigation results.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of fiscal 2001.
EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
NOTES: (1) All executive officers of Energen except for Ms. Carr have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of its Board of Directors.
(2) Mr. Warren has been employed by the Company in various capacities since 1983. In January 1992 he was elected President and Chief Operating Officer of Energen and all of its subsidiaries, in October 1995 he was elected Chief Executive Officer of Alagasco and Energen Resources, in February 1997 he was elected Chief Executive Officer of Energen, and effective January 1, 1998, he was elected Chairman of the Board of Energen and each of its subsidiaries. Mr. Warren serves as a Director of Energen and each of its subsidiaries. He is a director of Associated Electric and Gas Insurance Services Limited, a mutual insurance company serving the United States public utility industries, and a director of Protective Life Corporation. He is also a city director of AmSouth Bank of Alabama and a member of the Board of Trustees of Birmingham-Southern College.
(3) Mr. Ketcham has been employed by the Company in various capacities since 1981. He has served as Executive Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries since April 1991.
(4) Mr. Youngblood has been employed by the Company in various capacities since 1969. He was elected Executive Vice President of Alagasco in October 1993, Chief Operating Officer of Alagasco in October 1995, and President of Alagasco in April 1997.
(5) Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Vice President-Finance and Corporate Development of Energen and Vice President-Finance and Planning of Alagasco in April 1991. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997.
(6) Mr. Reynolds has been employed by the Company in various capacities since 1980. He has served as General Counsel and Secretary of Energen and each of its subsidiaries since April 1991.
(7) Mr. Woodruff has been employed by the Company in various capacities since 1986. He has served as Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries since April 1991 and as Vice President-Corporate Development of Energen since October 1995.
(8) Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from April 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On December 3, 2001, there were approximately 8,400 holders of record of Energen's common stock. For restrictions on Energen's present and future ability to pay dividends, see Note 3 to the Financial Statements which is included in Part II, Item 8, herein.
At the date of this filing, Energen Corporation owns all the issued and outstanding common stock of Alabama Gas Corporation.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data as set forth below should be read in conjunction with the Consolidated Financial Statements and the Notes to Financial Statements included in this Form 10-K.
SELECTED FINANCIAL AND COMMON STOCK DATA ENERGEN CORPORATION
Note: All information has been adjusted to reflect the 2-for-1 stock split effective March 2, 1998
SELECTED BUSINESS SEGMENT DATA ENERGEN CORPORATION
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen Corporation's net income for the fiscal year 2001 totaled $67.9 million, or $2.18 per diluted share. This reflects a 24.6 percent increase in earnings per diluted share (EPS) over prior-year net income of $53 million, or $1.75 per diluted share. A significant increase in the 2001 financial performance of Energen Resources Corporation, Energen's oil and gas subsidiary, more than offset a slight decline at Alabama Gas Corporation (Alagasco), Energen's utility subsidiary. In fiscal year 1999, Energen reported earnings of $41.4 million, or $1.38 per diluted share.
2001 VS 2000: Energen Resources' net income in fiscal 2001 rose 55.2 percent to $42.6 million, primarily due to a 24.4 percent increase in realized sales prices for natural gas, oil and natural gas liquids. The significantly higher realized commodity prices more than compensated for the negative impact of increased lease operating expense and a 2 billion cubic feet equivalent (Bcfe) production decrease. Earnings in fiscal year 2000 were negatively affected by a one-time $2.2 million (7 cents per diluted share) after-tax writedown under Statement of Financial Accounting Standards (SFAS) No. 121 of certain oil and gas properties resulting from a downward reserve revision.
Alagasco's earnings declined 1.2 percent from $26.3 million last year to $26 million in fiscal year 2001. This slight decrease in income was primarily a result of increased bad debt expense from significantly colder weather and higher natural gas prices during the past winter as well as industrial load loss due to an economic slow-down. Alagasco achieved a return on average equity (ROE) of 12.3 percent in 2001 as compared to 13.4 percent in 2000.
2000 VS 1999: Energen Resources' net income increased 58.5 percent to $27.4 million in fiscal 2000, primarily due to significantly higher realized commodity prices. The higher realized natural gas, oil and natural gas liquids prices more than compensated for reduced production levels primarily resulting from prior-year property sales and the after-tax writedown under SFAS No. 121 discussed above. Fiscal year 1999 results included a $2.1 million after-tax gain on the June 1999 sale of certain offshore Gulf of Mexico properties. Alagasco's 2000 net income of $26.3 million increased 13 percent over 1999 earnings of $23.3 million, reflecting the utility's ability to earn within its allowed range of return on an increased level of equity.
OPERATING INCOME
Consolidated operating income in 2001, 2000 and 1999 totaled $124 million, $95.8 million and $77.4 million, respectively. This significant growth in operating income was influenced by continued improvement in financial performance from Energen Resources under Energen's diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with the increase in the level of equity upon which it has been able to earn a return. In the current year, the growth in operating income at Alagasco was partially offset by increased bad debt expense and industrial load loss.
OIL AND GAS OPERATIONS: Revenues from oil and gas operations continued to increase in the current fiscal year largely as a result of significantly higher commodity prices. Realized gas prices rose 24.9 percent to $3.11 per Mcf, while realized oil prices increased 32.6 percent to $24.02 per barrel. Natural gas liquids prices increased 9.9 percent to an average price of $17.62 per barrel. During 2001, total production declined slightly to 68.5 Bcfe. Natural gas production decreased 3.4 percent to 46.5 Bcf and oil volumes declined 5.1 percent to 2,187 MBbl. Production of natural gas liquids increased 3.7 percent to 1,482 MBbl. For the current year, the 2 Bcfe decrease in production largely was due to normal production declines in Energen Resources' coalbed methane and south Louisiana properties. Drilling in the San Juan and Permian basins and in the north Louisiana/east Texas area served to replace aggregate production in these areas.
In fiscal 2000, realized gas prices rose 12.7 percent to $2.49 per Mcf, realized oil prices increased 51.9 percent to $18.11 per barrel and natural gas liquids prices increased 67.4 percent to an average price of $16.04 per barrel. Total
production volumes in 2000 decreased 8.7 percent to 70.5 Bcfe primarily due to the offshore property sales occurring in the latter half of fiscal 1999. Natural gas production decreased 10.7 percent to 48.1 Bcf and oil volumes declined 26.2 percent to 2,304 MBbl. Production of natural gas liquids increased 87.5 percent to 1,429 MBbl as a result of higher liquids prices, which led to substantially all natural gas liquids being removed from the gas stream during processing.
During 1999, revenues from oil and gas production grew mainly as a result of the TOTAL Minatome Corporation (TOTAL) property acquisition and prior-year property acquisitions. Energen Resources gained an estimated 200 Bcfe of proved domestic oil and natural gas reserves as a result of the TOTAL acquisition.
Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $7.6 million, $4.3 million and $3.9 million in 2001, 2000 and 1999, respectively.
Energen Resources may, in the ordinary course of business, be involved in the sale of developed and undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. In 2001, Energen Resources recorded in operating revenues a net pre-tax gain from the sale of properties and adjustments to the fair value of properties held for sale of $0.8 million. Pre-tax gains from the sale of properties of $1.1 million and $4.2 million were recorded in operating revenues in 2000 and 1999, respectively.
Operations expense increased $11 million in 2001 and decreased $3.4 million in 2000. In 2001, lease operating expense increased by $12 million largely due to significantly higher operational costs driven by market conditions resulting from increased commodity costs. Lease operating expense decreased by $3.8 million in 2000 primarily due to the sale of offshore properties in 1999. In the current fiscal year, administrative expense decreased $0.5 million and increased $1 million in 2000. Exploration expense decreased $0.7 million in 2001 and $0.1 million in 2000, primarily due to decreased exploratory efforts.
Depreciation, depletion and amortization (DD&A) expense decreased $2.3 million in 2001 primarily due to lower production volumes and additional pre-tax DD&A expense of $3.5 million recorded in 2000 under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and For Long-Lived Assets to Be Disposed Of" (see Note 10). DD&A expense decreased $3.5 million in 2000 largely due to lower production volumes partially offset by the additional pre-tax DD&A expense recorded under SFAS No. 121. The average depletion rate (excluding the effect of the prior-year writedown) was $0.80 per Mcf in 2001 as compared to $0.76 per Mcf in the prior year.
Energen Resources' expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes for 2001 and 2000 of $24.3 million and $17.6 million, respectively, as a result of increased commodity prices. In 1999, severance taxes were $11.3 million.
NATURAL GAS DISTRIBUTION: As discussed more fully in Note 2 in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On October 7, 1996, the APSC issued an order to extend Alagasco's rate-setting mechanism, Rate Stabilization and Equalization (RSE), through January 1, 2002. Under terms of the extension, RSE will continue after January 1, 2002, unless, after notice to the company and a hearing, the APSC votes to either modify or discontinue its operation.
Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco's rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but operating margins essentially remain unaffected due to a real-time temperature adjustment mechanism that allows Alagasco to adjust customer bills monthly to reflect changes in usage due to departures from normal temperatures. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial.
Alagasco's natural gas and transportation sales revenues totaled $553.9 million, $366.2 million and $325.6 million in fiscal years 2001, 2000 and 1999, respectively. Significantly higher commodity gas costs and weather that was 29.9 percent colder than in the prior year contributed to the increase in sales revenue in the current fiscal year. Sales revenue in 2000 rose due to weather that was 12.8 percent colder than in fiscal 1999 as well as to higher commodity gas costs.
In the current fiscal year, significantly colder weather in Alagasco's service territory caused a 19.2 percent increase in residential sales volumes and a 16.2 percent increase in small commercial and industrial sales volumes. Transportation volumes decreased 23.5 percent, primarily due to the prior-year closing of a steel manufacturing plant and reduced consumption resulting from an economic downturn during the year. In fiscal 2000, residential sales volumes increased 5.3 percent primarily due to the impact of colder weather. Small commercial and industrial volumes, also sensitive to weather, increased 3.7 percent. Transportation volumes rose 6.3 percent, primarily due to increased volumes to a power generation facility and a large cogeneration customer.
Higher commodity cost of gas, including record high prices in fiscal year 2001, along with increased purchased volumes resulting from colder weather generated a 111.5 percent and a 23.4 percent increase in cost of gas for fiscal years 2001 and 2000, respectively.
Operations and maintenance (O&M) expense at the utility increased 1.5 percent in fiscal 2001 primarily as a result of increased bad debt expense and higher insurance costs largely offset by reduced marketing and labor-related costs. In the prior year, O&M expense increased 3.7 percent primarily due to higher labor and related costs partially offset by reduced bad debt and general liability insurance expense. In 2001 and 2000, the increase in O&M expense on a per-customer basis fell within the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility's rate-setting mechanism. In 1999, the increase in O&M expense per customer fell below the CCM resulting in the utility benefiting by $0.7 million pre-tax, or one-half the difference, in future rate adjustments (see Note 2).
Consistent with growth in the utility's depreciable base, depreciation expense rose 7.8 percent in 2001 and 7.4 percent in 2000. Alagasco's expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.
NON-OPERATING ITEMS
CONSOLIDATED: Fiscal 2001 interest expense increased $4.3 million primarily due to $150 million of medium term notes (MTNs) issued by Energen in December 2000 and, in part, from the issuance by Alagasco of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August 2001. The proceeds from the MTNs and the Notes were used to repay borrowings under Energen and Alagasco's short-term credit facilities incurred as a result of the growth at Energen Resources and general corporate purposes at Alagasco. The average daily outstanding balance under short-term credit facilities was $80.7 million in 2001. Interest expense remained relatively stable in fiscal year 2000 compared to fiscal 1999. The average daily outstanding balance under short-term credit facilities was $146.8 million in 2000 as compared to $155 million in fiscal year 1999.
The Company's effective tax rates in 2001, 2000 and 1999 were lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits and the amortization of investment tax credits. Nonconventional fuels tax credits are generated annually on qualified production through December 31, 2002. They are expected to be recognized fully in the financial statements, and effective tax rates are expected to continue to remain lower than statutory federal rates in the near future. Income tax expense increased in 2001 and 2000 primarily due to higher pre-tax income. The Company recognized $13.6 million, $14.4 million and $14.8 million in nonconventional fuels tax credits in 2001, 2000 and 1999, respectively. As of September 30, 2001, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $56 million.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $156.5 million, $105 million and $130.6 million in 2001, 2000 and 1999, respectively. Operating cash flow in the current year and in 2000 benefited from significantly higher realized oil, gas and natural gas liquids prices at Energen Resources. Working capital needs at Alagasco were affected by increased gas costs and colder-than-normal weather resulting in higher storage inventory balances. In fiscal 1999, operating cash flow benefited from significantly higher production volumes related to Energen Resources' property acquisitions. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years.
During fiscal 2001, the Company made net investments of $174.4 million. Energen Resources invested $34.3 million for property acquisitions, $103.6 million for development of proved properties and $1.2 million for exploration. Energen Resources drilled 140 gross development wells, during the current year adding approximately 50 Bcfe of reserves. Energen Resources sold or traded certain properties during the current year, resulting in cash proceeds of $17.3 million. Utility expenditures for the year totaled $56.1 million and primarily represented support facilities and normal system distribution expansion along with $3 million for a municipal acquisition. Cash used in investing activities totaled $131.7 million in 2000. Energen Resources invested $2.4 million for property acquisitions, $66.7 million for development and $1.2 million for exploration. Energen Resources' successful development wells and other exploitation activities added approximately 76 Bcfe of reserves in fiscal year 2000. Utility expenditures in 2000 totaled $67.1 million. During fiscal 1999, the Company made net investments of $188.1 million largely due to the acquisition of oil and gas properties. Energen Resources invested $144 million for property acquisitions, including
$137.5 million for TOTAL, $55.5 million for development and $1.7 million for exploration. Energen Resources' acquisitions in 1999 added approximately 200 Bcfe of proved reserves while its 88 successful development wells and other exploitation activities added approximately 120 Bcfe of reserves. Utility expenditures in 1999 totaled $46 million. The Company had cash proceeds of $56.9 million resulting from the sale-leaseback of the headquarters building and the sale of certain offshore and onshore properties during 1999.
Net cash provided by financing activities totaled $19.4 million in 2001. In December 2000, Energen issued $150 million of long-term debt redeemable December 15, 2010, and in August 2001 Alagasco issued 6.25% Notes for $40 million, redeemable September 1, 2016, and 6.75% Notes for $35 million, redeemable September 1, 2031. The $223.8 million in net proceeds were used to repay short-term borrowings incurred to finance Energen Resources' growth activities and to repay additional borrowings by the utility as a result of higher capital expenditures primarily related to replacement of liquifaction equipment and for general corporate purposes. The proceeds also were used to reduce long-term debt by $36.3 million, including the retirement of the 8% Debentures for $18.3 million. Net cash used in financing activities totaled $114.9 million in 2000 resulting primarily from fluctuations in the amount and timing of short-term debt at year-end. Financing activities provided a net source of cash totaling $99.6 million in 1999. Due to a change in tax law during fiscal 2000, the Company had no borrowings at September 30, 2001 or 2000, to purchase short-term federal obligations for tax planning purposes as in previous years. The Company borrowed $140.9 million at September 30, 1999 to invest in short-term federal obligations for tax planning purposes that were sold in early October with the proceeds used to repay the related debt. In 1999, the Company utilized $74.7 million in short-term credit facilities to finance Energen Resources' acquisition strategy and reduced long-term debt by $6.2 million. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and direct stock purchase plan and the employee savings plans.
CAPITAL EXPENDITURES
OIL AND GAS OPERATIONS: Energen Resources spent $415.5 million for capital projects over the last three fiscal years, $12.9 million of which was charged to income as exploration expense. Property acquisition expenditures totaled $181 million, $225.8 million was spent in development activities and exploratory expenditures totaled $4 million.
NATURAL GAS DISTRIBUTION: During the last three fiscal years, Alagasco invested $169.2 million for capital projects: $98.2 million for normal expansion, replacements and support of its distribution system, $68 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems, and $3 million to purchase a municipal gas system.
FUTURE CAPITAL RESOURCES AND LIQUIDITY
The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources' oil and gas operations through the acquisition and exploitation of producing properties with development potential while building on the strength of the Company's utility foundation. Since the inception of this strategy, implemented beginning with fiscal year 1996, Energen's goal has been to generate EPS growth of at least 10 percent a year, on average, over each rolling five-year period. Over the last five fiscal years under this strategy, Energen's EPS grew at an average compound rate of 17.6 percent a year.
To finance Energen Resources' investment program, the Company will continue to utilize its short-term credit facilities to supplement internally generated cash flow, with long-term debt and equity providing permanent financing. Energen has available short-term credit facilities of $220 million to help accommodate its growth plans. Energen's management plans to utilize increases in cash flows to help finance Energen Resources' acquisition and exploitation strategy and to help reduce Energen's debt-to-total capitalization ratio to near 50 percent over the next five years.
In fiscal year 2002, Energen Resources plans to invest approximately $261 million, including $175 million in property acquisitions and $74 million in exploitation activities. Energen Resources' exploratory exposure in fiscal 2002 is estimated to be $5 million, along with an additional $5 million in associated development. Capital investment at Energen Resources in fiscal year 2003 is expected to approximate $150 million for acquisitions, $39 million for exploitation and $10 million for exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending September 30, 2006, is estimated to be approximately $1 billion. During this period, the Company expects to issue approximately $100 million in long-term debt to replace short-term obligations and to provide permanent financing for its acquisition strategy. Energen Resources' continued ability to invest in property acquisitions will be influenced significantly by industry trends, as the producing property acquisition market historically has been cyclical. From time to time, Energen Resources also may be engaged in negotiations to sell, trade or otherwise dispose of properties.
During fiscal year 2002, Alagasco plans to invest approximately $65 million in utility capital expenditures for normal distribution and support systems, including approximately $15 million for revenue-producing main projects and $10 million for information technology application projects. Alagasco maintains an investment in storage gas that is expected to average approximately $46 million in 2002. Alagasco plans to invest approximately $56 million in utility capital expenditures during fiscal year 2003. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Over the Company's five-year planning period ending September 30, 2006, Alagasco anticipates capital investments of approximately $275 million.
OUTLOOK
OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its acquisition and exploitation program with capital spending in fiscal years 2002 and 2003 as outlined above. Production in fiscal 2002 is expected to be approximately 73 Bcfe. This estimate includes 4.5 Bcfe of production from anticipated acquisitions and exploration activity. In fiscal year 2003, production is expected to increase to approximately 88 Bcfe, including 19.4 Bcfe of production from anticipated acquisitions and exploration activity in that fiscal year, as well as production from planned property acquisitions in fiscal year 2002 and associated exploitation.
Energen Resources expects to generate approximately $13.2 million and $3.1 million of nonconventional fuels tax credits during fiscal years 2002 and 2003, respectively. Nonconventional fuels tax credits are generated annually on qualified production through December 31, 2002. As the tax credit expiration date approaches, Energen Resources plans to replace the tax credits with revenue-generating property acquisitions and related development in a manner that does not negatively affect corporate earnings in fiscal year 2003 and beyond.
In the event Energen Resources is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production and proved reserves could be negatively affected. Energen Resources' major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of Petroleum Exporting Countries. Basis
differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.
Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to oil and gas price fluctuations. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions.
As of September 30, 2001, 31 percent of Energen Resources' estimated 2002 gas production, excluding anticipated acquisition and exploration volumes, was hedged or under contract; 9.3 Bcf of its gas production at an average NYMEX price of $3.84 per Mcf, 3.6 Bcf of basin-specific hedges at an average contract price of $4.30 and 0.8 Bcf of gas production hedged with a NYMEX collar price of $4.25 to $6.15 per Mcf. The Company also had hedges in place for 20 percent of its estimated 2002 oil production, excluding anticipated acquisition and exploration volumes, at an average NYMEX price of $27.44 per barrel. In addition, the Company had hedged the basis difference on 6 Bcf of its fiscal 2002 gas production and 202 MBbl of its oil production.
At September 30, 2001, Energen Resources had entered into basin-specific swaps for 1.9 Bcf of its gas production at an average contract price of $3.77 per Mcf for fiscal year 2003. For fiscal 2004 and 2005, Energen Resources had entered into swaps for 1.8 Bcf and 1.6 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively. As acquisitions are made, Energen Resources may use futures, swaps and/or fixed-price contracts to lock in commodity prices for up to 36 months in order to protect targeted returns. Energen Resources may hedge up to 80 percent of its estimated annual production as approved by the Company's Board of Directors.
In addition to the derivatives described above, the Company has three-way pricing, physical sales contracts in place for approximately 30 percent of its estimated gas production, excluding anticipated acquisition and exploration volumes, in fiscal year 2002. These contracts provide for Energen Resources to receive a basin-specific weighted average price between $2.82 and $3.94 per Mcf. If the market price falls between $2.40 and $2.82 per Mcf, Energen Resources will receive $2.82 per Mcf. If the market price falls below $2.40 per Mcf, Energen Resources will receive the market price plus a premium of $0.33-$0.45, depending on the contracts. For fiscal year 2003, the Company has three-way pricing, physical sales contracts in place for approximately 19 percent of its estimated gas production. These contracts provide for Energen Resources to receive a basin-specific weighted average price between $2.72 and $3.94 per Mcf. If the market price falls between $2.40 and $2.72 per Mcf, Energen Resources will receive $2.72 per Mcf. If the market price falls below $2.40 per Mcf, Energen Resources will receive the market price plus a premium of $0.23-$0.35, depending on the contracts.
The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At September 30, 2001 and 2000, the Company estimated that a 10 percent change in the underlying commodities prices would have resulted in a $6.9 million and a $23.6 million change, respectively, in the fair value of open derivative contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. Due to the short duration of the contracts, the time value of money was ignored. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the variance in basis difference or the impact of related taxes on actual cash prices.
See Note 18, Subsequent Event, for discussion regarding Enron North America Corp.'s bankruptcy filing, which raises uncertainty as to their ability to perform under its contracts.
NATURAL GAS DISTRIBUTION: The five-year extension of RSE in October 1996 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through January 1, 2002. Under the terms
of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. Over this period, Alagasco has the potential for net income growth as the investment in additional utility plant affects the level of equity required in the business. Alagasco's 13-month average equity is estimated to be $219 million and $235 million at the end of fiscal years 2002 and 2003, respectively. The utility continues to rely on rate flexibility to effectively prevent bypass of its distribution system. Even though the utility enjoys a market saturation rate higher than the national average, customer growth in the service territory is limited. In the year 2002, Alagasco will continue to focus on enhancing customer growth by aggressively pursuing conversion opportunities and municipal acquisitions.
On December 4, 2000, the APSC authorized Alagasco to engage in energy risk management activities to manage the utility's cost of gas supply. As of September 30, 2001, Alagasco had recorded a $117,000 liability representing the fair value of derivatives. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses, including gains or losses resulting from fair value measurement of derivatives, are passed through to customers using the mechanisms of the GSA in accordance with Alagasco's APSC-approved tariff.
FORWARD-LOOKING STATEMENT AND RISK: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. We undertake no obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, future business decisions, and other uncertainties, all of which are difficult to predict. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. In the event Energen Resources is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns and these risks can be affected by lease and rig availability, complex geology and other factors. Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate risk, fluctuations in future oil and gas prices could affect materially the Company's financial position and results of operation; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts.
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD
In June 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires business combinations to be accounted for using the purchase method. SFAS No. 142 requires that goodwill and certain other intangible assets no longer be amortized and be tested for impairment annually. The consolidated financial statements do not include existing goodwill or other intangible assets.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses accounting and reporting standards for long-lived assets. The Company is required to adopt these statements in fiscal year 2003. The impact of these pronouncements on the Company currently is being evaluated and is not expected to be material.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item in respect to market risk is set forth in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Outlook" and in Note 9, Financial Instruments and Risk Management, in the Notes to Financial Statements.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ENERGEN CORPORATION ALABAMA GAS CORPORATION AND FINANCIAL STATEMENT SCHEDULES
Schedules other than those listed above are omitted because they are not required or not applicable, or the required information is shown in the financial statements or notes thereto.
REPORT OF MANAGEMENT
The accompanying consolidated financial statements and related notes of Energen Corporation and subsidiaries and the financial statements and related notes of Alabama Gas Corporation (collectively, "the financial statements") were prepared by management, which has the primary responsibility for the integrity of the financial information therein. These financial statements were prepared in conformity with accounting principles generally accepted in the United States of America appropriate in the circumstances and include amounts which are based necessarily on management's best estimates and judgments. Financial information presented elsewhere in this report is consistent with the information in the financial statements.
Management maintains a comprehensive system of internal accounting controls and relies on the system to discharge its responsibility for the integrity of the financial statements. This system provides reasonable assurance that corporate assets are safeguarded and that transactions are recorded in such a manner as to permit the preparation of materially reliable financial information. Reasonable assurance recognizes that the cost of a system of internal accounting controls should not exceed the related benefits. This system of internal accounting controls is augmented by written policies and procedures, internal auditing, and the careful selection and training of qualified personnel. As of September 30, 2001, management was aware of no material weaknesses in Energen or Alabama Gas Corporation's systems of internal accounting controls.
The financial statements have been audited by the Company's independent accountants, whose opinions are expressed elsewhere in this Form 10-K. Their audits were conducted in accordance with generally accepted auditing standards; and, in connection therewith, they obtained an understanding of the Company's systems of internal accounting controls and conducted such tests and related procedures as they deemed necessary to arrive at an opinion on the fairness of presentation of the financial statements.
The functioning of the accounting system and related internal accounting controls is under the general oversight of the Audit Committee of the Board of Directors, which is comprised of five outside Directors. The Audit Committee meets regularly with the independent accountants and representatives of management to discuss matters regarding internal accounting controls, auditing and financial reporting.
Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer
REPORT OF INDEPENDENT ACCOUNTANTS TO THE SHAREHOLDERS OF ENERGEN CORPORATION:
In our opinion, the consolidated financial statements of Energen Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and subsidiaries at September 30, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 of the Notes to Financial Statements, effective October 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."
PricewaterhouseCoopers LLP Birmingham, Alabama October 23, 2001, except for Note 18, as to which the date is December 5, 2001
REPORT OF INDEPENDENT ACCOUNTANTS TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF ALABAMA GAS CORPORATION:
In our opinion, the financial statements of Alabama Gas Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at September 30, 2001 and 2000, and the results of its operations and cash flows for each of the three years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP Birmingham, Alabama October 23, 2001, except for Note 18, as to which the date is December 5, 2001
CONSOLIDATED STATEMENTS OF INCOME ENERGEN CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS ENERGEN CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS ENERGEN CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY ENERGEN CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS ENERGEN CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF INCOME ALABAMA GAS CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
BALANCE SHEETS ALABAMA GAS CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
BALANCE SHEETS ALABAMA GAS CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF SHAREHOLDER'S EQUITY ALABAMA GAS CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF CASH FLOWS ALABAMA GAS CORPORATION
The accompanying Notes to Financial Statements are an integral part of these statements.
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - -------------------------------------------------------------------------------
Energen Corporation (Energen or the Company) is a diversified energy holding company engaged primarily in the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution, and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company's significant accounting policies and practices.
A. PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation.
B. OIL AND GAS OPERATIONS
PROPERTY AND RELATED DEPLETION: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil and gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. All development costs are capitalized. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the unit-of-production method based on proved reserves. A provision for anticipated abandonment and restoration costs at the end of a property's useful life is made through depreciation expense.
OPERATING REVENUE: Energen Resources utilizes the sales method of accounting to recognize oil and gas production revenue. Under the sales method, revenue is recognized for the Company's total takes of oil and gas production, and over-production liabilities are established only when it is estimated that a property's over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at September 30, 2001. Gains and losses on the sale of property in the ordinary course of business are classified as operating revenue.
DERIVATIVE COMMODITY INSTRUMENTS: The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting for Derivative Instruments and Hedging Activities," on October 1, 2000. This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change.
Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists.
All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative is not determined to be highly effective as a hedge or has ceased to be a highly effective hedge.
C. NATURAL GAS DISTRIBUTION
UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and, together with the cost of removal less salvage, is charged to the accumulated reserve for depreciation. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.5 percent in 2001, 2000 and 1999.
INVENTORIES: Inventories, which consist primarily of gas stored underground, are stated at average cost.
OPERATING REVENUE AND GAS COSTS: In accordance with industry practice, Alagasco records natural gas distribution revenues on a monthly- and cycle-billing basis. The commodity cost of purchased gas applicable to gas delivered to customers but not yet billed under the cycle-billing method is deferred as a current asset.
REGULATORY ACCOUNTING: Alagasco is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." In general, SFAS No. 71 requires utilities to capitalize or defer certain costs or revenues, based upon approvals received from regulatory authorities, to be recovered from or refunded to customers in future periods.
D. INCOME TAXES
The Company uses the liability method of accounting for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Alagasco files a consolidated federal income tax return with its parent. Consolidated federal income taxes are allocated to appropriate subsidiaries using the separate return method.
E. CASH EQUIVALENTS
The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents.
F. EARNINGS PER SHARE
The Company's basic earnings per share amounts have been computed based on the weighted-average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities (see Note 13).
G. ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and the related present value of estimated future net revenues therefrom (see Note 16).
2. REGULATORY MATTERS - -------------------------------------------------------------------------------
As an Alabama utility, Alagasco is subject to regulation by the APSC which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended with modifications in 1990, 1987 and 1985. On October 7, 1996, RSE was extended, without change, for a five-year period through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and fiscal year-to-date performance, whether Alagasco's return on average equity at the end of the fiscal year will be within the allowed range of 13.15 percent to 13.65 percent. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each fiscal year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. In fiscal 1999, the increase in O&M expense per customer was below the index range; as a result, the utility benefited by $0.7 million. Under RSE as extended, a $9.1 million, $4.5 million and a $6.6 million annual increase in revenues became effective December 1, 2000, 1999 and 1998, respectively.
Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. The calculation is performed monthly, and the adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply.
The APSC approved an Enhanced Stability Reserve (ESR), beginning fiscal year 1998 in the amount of $3.9 million with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a fiscal year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the fiscal year, if such losses cause Alagasco's return on average equity to fall below 13.15 percent. During 2001, Alagasco charged $1.2 million against the ESR related to extraordinary bad debt expense and revenue losses from certain large industrial customers. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. At September 30, 2001 and 2000, the ESR balance of $2.7 million and $3.9 million, respectively, was included in the consolidated financial statements.
The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco's rate-setting mechanism on a straight-line basis over approximately 23 years. At September 30, 2001 and 2000, the net acquisition adjustment was $12.4 million and $13.4 million, respectively.
3. LONG-TERM DEBT AND NOTES PAYABLE - -------------------------------------------------------------------------------
Long-term debt consisted of the following:
The aggregate maturities of Energen's long-term debt for the next five years are as follows:
The aggregate maturities of Alagasco's long-term debt for the next five years are as follows:
The Company is subject to various restrictions on the payment of dividends. Under its Series 1993 Notes, the most restrictive provision states that dividends or other distributions with respect to common stock may not be made unless the Company maintains a minimum consolidated tangible net worth of $80 million; at September 30, 2001, Energen had a tangible net worth of $481 million.
Energen and Alagasco had short-term credit lines and other credit facilities of $220 million available as of September 30, 2001, for working capital needs; Alagasco has been authorized to borrow up to $70 million of the available credit lines by the APSC. At September 30, 1999, the Company had $140.9 million of borrowings to purchase U.S. Treasury securities for tax planning. These securities matured in early October 1999, and the proceeds were used to repay such borrowings. The following is a summary of information relating to notes payable to banks:
Total interest expense for Energen in 2001, 2000 and 1999 was $42,070,000, $37,769,000 and $37,173,000, respectively. In 2001, 2000 and 1999, total interest expense for Alagasco was $12,316,000, $9,870,000 and $10,366,000, respectively.
4. INCOME TAXES - -------------------------------------------------------------------------------
The components of Energen's income taxes consisted of the following:
The components of Alagasco's income taxes consisted of the following:
Temporary differences and carryforwards which gave rise to a significant portion of Energen's and Alagasco's deferred tax assets and liabilities for 2001 and 2000 were as follows:
Total income tax expense for the Company differed from the amount which would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes as illustrated below:
Total income tax expense for Alagasco differed from the amount which would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes as illustrated below:
The Company files a consolidated federal income tax return with all of its subsidiaries. As of September 30, 2001, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $56 million. No valuation allowance with respect to deferred taxes is deemed necessary, as the Company anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets on the consolidated balance sheets.
5. EMPLOYEE BENEFIT PLANS - -------------------------------------------------------------------------------
The Company has two defined benefit non-contributory pension plans: Plan A covers a majority of the employees and Plan B covers employees under certain labor union agreements. Benefits are based on years of service and final earnings. The Company's policy is to use the projected unit credit actuarial method for funding and financial reporting purposes.
The status of the plans was as follows:
The components of net pension expense were:
In 2001, 2000 and 1999, net pension expense for Alagasco was $1,812,000, $1,466,000 and $2,458,000, respectively.
The Company has supplemental retirement plans with certain key executives providing payments on retirement, termination, death or disability. Expense under these agreements for 2001, 2000 and 1999 was $381,000, $372,000 and $(75,000), respectively. At June 30, 2001 and 2000, the accumulated post-retirement benefit obligation related to these agreements was $5,465,000 and $3,204,000, respectively, and the projected benefit obligation was $10,750,000 and $10,356,000, respectively. An accrued post-retirement benefit liability of $2,408,000 was recorded at June 30, 2001. A prepaid post-retirement benefit asset of $566,000 was recorded at June 30, 2000.
In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.
The status of the post-retirement benefit programs was as follows:
Net periodic post-retirement benefit expense included the following:
In 2001, 2000 and 1999, net periodic post-retirement benefit expense for Alagasco was $3,959,000, $5,449,000 and $6,644,000, respectively.
The weighted average health care cost trend rate used in determining the accumulated post-retirement benefit obligation has a significant effect on the amounts reported. For example, with respect to salaried employees, increasing the weighted average health care cost trend rate by 1 percentage point would increase the accumulated post-retirement benefit obligation by $993,000 and the net periodic post-retirement benefit cost by $32,000. For union employees, increasing the weighted average health care cost trend rate by 1 percentage point would increase the accumulated post-retirement benefit obligation by $3,004,000 and the net periodic post-retirement benefit cost by $257,000.
For both defined benefit plans and other post-retirement plans, certain financial assumptions are used in determining the Company's projected benefit obligation. These assumptions are examined periodically by the Company, and any required changes are reflected in the subsequent determination of projected benefit obligations.
The Company has a long-term disability plan covering most salaried employees. The Company had no expense for this plan in the years ended September 30, 2001 and 2000. Expense for the year ended September 30, 1999 was $177,000.
6. COMMON STOCK PLANS - -------------------------------------------------------------------------------
A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by investing a portion of their compensation in the ESP, with the Company matching a part of the employee investment
by contributing Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. The ESP also contains employee stock ownership plan provisions. At September 30, 2001, a total of 419,453 common shares were reserved for issuance under the ESP. Expense associated with Company contributions to the ESP was $3,597,000, $3,381,000 and $3,421,000 for 2001, 2000 and 1999, respectively.
In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance Plan which provides for the award of up to 1,000,000 performance units, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined performance criteria at the end of a four-year award period. Under the Plan, a portion of the performance units is payable with Company common stock; accordingly, 700,000 shares have been reserved for issuance. Under the Plan, 76,120, 102,860, and 100,100 performance units were awarded in 2001, 2000 and 1999, respectively. According to the provisions of the Plan, no additional performance units can be awarded after September 30, 2001. In October 2001, the Company added provisions for the award of future performance units, comparable to the 1992 Long-Range Performance Plan, under the 1997 Stock Incentive Plan. The Company recorded expense of $2,311,000, $4,448,000 and $1,530,000 for 2001, 2000 and 1999, respectively, under the Plan.
On November 27, 1997, the Company adopted the Energen Corporation 1997 Stock Incentive Plan. The 1997 Stock Incentive Plan, along with the Energen Corporation 1988 Stock Option Plan, provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plans provide for purchase of Company common stock at not less than the fair market value on the date the option is granted. In addition, the 1997 Stock Incentive Plan provides for the grant of restricted stock with 57,190, 12,500 and 5,500 shares awarded in 2001, 2000 and 1999, respectively. The sale or transfer of the shares is limited during the restricted period. The Company recorded expense of $583,000, $97,000 and $31,000 in 2001, 2000 and 1999, respectively, related to the restricted stock. Under the 1988 Stock Option Plan, 540,000 shares of Company common stock reserved for issuance have been granted. Under the 1997 Stock Incentive Plan, 1,300,000 shares of Company common stock have been reserved for issuance. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date. Transactions under the Plans are summarized as follows:
The following table summarizes information about options outstanding as of September 30, 2001:
The weighted-average grant-date fair value of options granted in 2001, 2000 and 1999 was $9.27, $5.91, and $5.42, respectively. The fair value of each option grant was estimated using the Black-Scholes option-pricing model. The Company has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." Accordingly, no compensation expense has been recognized for its stock options. Had compensation cost for these options been determined in accordance with SFAS No. 123, the Company's net income and diluted earnings per share would have been $67.4 million, or $2.17 per share, in 2001, $52.5 million, or $1.73 per share, in 2000, and $40.9 million, or $1.37 per share, in 1999.
In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to pay part of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 2,400, 3,254 and 4,914 shares were issued in 2001, 2000 and 1999, respectively, leaving 147,039 shares reserved for issuance as of September 30, 2001.
In 1996 the Company amended its Dividend Reinvestment and Common Stock Purchase Plan to include a direct stock purchase feature which allows purchases by non-shareholders. Accordingly, 1,500,000 shares were added to the Plan. As of September 30, 2001, 926,462 common shares were reserved under this Plan.
On April 26, 2000, the Company authorized the repurchase of up to 1,000,000 shares of the Company's common stock, in addition to the 500,000 shares authorized on May 25, 1994. In 2001, 2000 and 1999 the Company repurchased 91,600, 290,000 and 30,189 shares, respectively. As of September 30, 2001, a total of 848,111 shares remain authorized for future repurchase.
On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, the 1998 Plan provides shareholders with the right to acquire the Company's Series 1998 Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights Agreement between the Company and its Rights Agent. Under the 1998 Plan, one right is associated with each outstanding share of common stock. Rights outstanding under the 1998 Plan at September 30, 2001, were convertible into 311,247 shares of Series 1998 Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable during the period. The price at which the rights would be exercised is $70 per right, subject to adjustment upon occurrence of certain take-over related events. In general, absent certain take-over related events as described in the Plan, the rights may be redeemed prior to the July 27, 2008, expiration for $0.01 per right.
In 1997 the Company adopted the 1997 Deferred Compensation Plan to allow officers and non-employee directors to defer certain compensation. Amounts earned under the Deferred Compensation Plan and invested in Company common stock have been recorded as treasury stock, along with the related deferred compensation obligation in the Consolidated Statements of Shareholders' Equity.
7. COMMITMENTS AND CONTINGENCIES - -------------------------------------------------------------------------------
CONTRACTS AND AGREEMENTS: Alagasco has various firm gas supply and firm gas transportation contracts which expire at various dates through the year 2008. These contracts typically contain minimum demand charge
obligations on the part of Alagasco. Energen Resources has three-way pricing, physical sales contracts in place for approximately 30 percent of its estimated gas production, excluding anticipated acquisition and exploration volumes, in fiscal year 2002. These contracts provide for Energen Resources to receive a basin-specific weighted average price between $2.82 and $3.94 per Mcf. If the market price falls between $2.40 and $2.82 per Mcf, Energen Resources will receive $2.82 per Mcf. If the market price falls below $2.40 per Mcf, Energen Resources will receive the market price plus a premium of $0.33-$0.45, depending on the contracts. For fiscal year 2003, the Company has three-way pricing, physical sales contracts in place for approximately 19 percent of its estimated gas production. These contracts provide for Energen Resources to receive a basin-specific weighted average price between $2.72 and $3.94 per Mcf. If the market price falls between $2.40 and $2.72 per Mcf, Energen Resources will receive $2.72 per Mcf. If the market price falls below $2.40 per Mcf, Energen Resources will receive the market price plus a premium of $0.23-$0.35, depending on the contracts. See Note 18, Subsequent Event, for discussion regarding Enron North America Corp.'s bankruptcy filing, which raises uncertainty as to their ability to perform under its contracts.
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the results of operations or financial condition of Alagasco.
Energen Resources is subject to various environmental regulations. Management believes that Energen Resources is in compliance with the currently applicable standards of the environmental agencies to which it is subject and that potential environmental liabilities, if any, are minimal. Also, to the extent Energen Resources has operating agreements with various joint venture partners, environmental costs, if any, would be shared proportionately.
LEGAL MATTERS: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages, thus making it increasingly difficult to predict litigation results. Various legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs.
LEASE OBLIGATIONS: In January 1999 Alagasco closed on a sale-leaseback of the Company's headquarters building. The proceeds from the sale approximated the investment in the facility. The building is being leased back from the purchaser over a 25-year lease term and the related lease is accounted for as an operating lease. Energen's total lease payments related to leases included as operating lease expense, inclusive of the sale-leaseback, were $7,324,000, $6,267,000 and $5,665,000 in 2001, 2000 and 1999, respectively. Minimum future rental payments required after 2001 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
Alagasco's total payments related to leases included as operating expense, inclusive of the sale-leaseback, were $2,343,000, $2,209,000 and $2,079,000 in 2001, 2000 and 1999, respectively. Minimum future rental payments required after 2001 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
8. SUPPLEMENTAL CASH FLOW INFORMATION - -------------------------------------------------------------------------------
Supplemental information concerning Energen's cash flow activities is as follows:
Supplemental information concerning Alagasco's cash flow activities is as follows:
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - -------------------------------------------------------------------------------
FINANCIAL INSTRUMENTS: The fair value of cash and cash equivalents, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's fixed-rate long-term debt, including the current portion, with a carrying value of $561,881,000, would be $582,635,000 at September 30, 2001. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, with a carrying value of $190,000,000, would be $198,843,000 at September 30, 2001. The fair values were based on the market value of debt with similar maturities and current interest rates.
Alagasco has entered into an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million. During 2001, 2000 and 1999, Alagasco sold $5,444,000, $6,879,000 and $6,391,000, respectively, of installment receivables. At September 30, 2001 and 2000, the balance of these installment receivables was $13,249,000 and $15,280,000, respectively. Receivables sold under this agreement are considered financial instruments with off-balance sheet risk. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables.
PRICE RISK: The Company adopted SFAS No. 133 (subsequently amended by SFAS Nos. 137 and 138) on October 1, 2000. This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change.
Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the NYMEX and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The Company has identified certain oil and gas derivatives which qualify as cash flow hedges under SFAS No. 133.
The Company had current gains on fair value of derivatives of $22.5 million included in prepayments and other and $3.2 million of non-current gains included in deferred charges and other on the consolidated balance sheet at September 30, 2001. Current deferred hedging losses of $83.5 million were included in prepayments and other, and non-current deferred hedging losses of $5.9 million were included in deferred charges and other on the consolidated balance sheet at September 30, 2000. Effective October 1, 2000, the Company reclassified the deferred hedging losses included in the consolidated balance sheet at September 30, 2000, as a cumulative effect-type adjustment to accumulated other comprehensive income as a component of equity.
As of September 30, 2001, $13.6 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve-month period. Gains and losses on derivative instruments that are not accounted for as hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded a $1.9 million after-tax loss in 2001 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax gain of $0.5 million in 2001 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of September 30, 2001, all Company swaps and hedges met the definition of a cash flow hedge. The Company had $9.9 million included in deferred income taxes on the consolidated balance sheet related to other comprehensive income as of September 30, 2001.
At September 30, 2001, Energen Resources had entered into contracts and swaps for 9.3 Bcf of its fiscal year 2002 gas production at an average NYMEX price of $3.84 per Mcf and 478 MBbl of its oil production at an average NYMEX price of $27.44 per barrel. Energen Resources had basin-specific hedges in place for 3.6 Bcf of gas production at an average contract price of $4.30 per Mcf and 0.8 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf. In addition, the Company had hedged the basis difference of 6 Bcf of its gas production and 202 MBbl of its oil production.
As of September 30, 2001, Energen Resources had entered into basin-specific swaps for 1.9 Bcf of its gas production at an average contract price of $3.77 per Mcf for fiscal year 2003. For fiscal year 2004 and 2005, Energen Resources had entered into swaps for 1.8 Bcf and 1.6 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.
All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative is not determined to be highly effective as a hedge or has ceased to be a highly effective hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through September 30, 2005.
On December 4, 2000, the APSC authorized Alagasco to engage in energy risk-management activities to manage the utility's cost of gas supply. As of September 30, 2001, Alagasco had recorded a $117,000 liability representing the fair value of derivatives. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in accordance with Alagasco's APSC- approved tariff.
See Note 18, Subsequent Event, for discussion regarding Enron North America Corp.'s bankruptcy filing, which raises uncertainty as to their ability to perform under its contracts.
CONCENTRATION OF CREDIT RISK: Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 465,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.
Revenues and related accounts receivable from exploration and production operations primarily are generated from the sale of produced natural gas and oil. This industry concentration has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be affected similarly by changes in economic, industry, or other conditions. The Company is not aware of any significant credit risks which have not been recognized in the provision for doubtful accounts.
10. ACCOUNTING FOR LONG-LIVED ASSETS - -------------------------------------------------------------------------------
SFAS No.121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", requires that an impairment loss be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flow of the asset. The Statement also provides that all long-lived assets to be disposed of be reported at the lower of the carrying amount or fair value. Accordingly, during the third fiscal quarter of 2000, Energen Resources recorded a pre-tax writedown of $3.5 million as additional depreciation, depletion and amortization expense caused by a downward reserve revision in a small oil and gas field, adjusting the carrying amount of the properties to their fair value based upon expected future discounted cash flows. In the fourth quarter of 2001, a pre-tax loss of $3.8 million was recorded in operating revenues for certain non-strategic properties held for sale. The properties which have a carrying amount of $9.5 million are being actively marketed for sale. The results of operations from these assets held for sale were immaterial.
11. RECENT PRONOUNCEMENTS OF THE FASB - -------------------------------------------------------------------------------
The Company has adopted SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires business combinations to be accounted for using the purchase method. SFAS No. 142 requires that goodwill and certain other intangible assets no longer be amortized and be tested for impairment annually. The consolidated financial statements do not include existing goodwill or other intangible assets.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses accounting and reporting standards for long-lived assets. The Company is required to adopt these statements in fiscal year 2003. The impact of these pronouncements on the Company currently is being evaluated and is not expected to be material.
12. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) - -------------------------------------------------------------------------------
The following data summarizes quarterly operating results. The Company's business is seasonal in character and strongly influenced by weather conditions.
The following data summarizes quarterly operating results. Alagasco's business is seasonal in character and strongly influenced by weather conditions.
13. RECONCILIATION OF EARNINGS PER SHARE - -------------------------------------------------------------------------------
14. ACQUISITION - -------------------------------------------------------------------------------
During fiscal year 1999, Energen Resources purchased the stock of the TOTAL Minatome Corporation (TOTAL), a Houston-based unit of TOTAL American Holding Inc. Immediately upon closing the transaction, Energen Resources sold a 31 percent undivided interest in TOTAL's net assets to Westport Oil and Gas Company Inc. Energen Resources' net adjusted price totaled approximately $137.5 million, including the assumption of certain legal and financial obligations. Energen Resources gained an estimated 200 Bcfe of proved domestic oil and natural gas reserves. The acquisition was accounted for as a purchase, and the results of operations since the acquisition date are included in the consolidated financial statements. A summary of net assets acquired follows:
15. TRANSACTIONS WITH RELATED PARTIES - -------------------------------------------------------------------------------
Alagasco purchased natural gas from affiliates amounting to $5,254,000, $3,662,000 and $3,232,000, in 2001, 2000 and 1999, respectively. These amounts are included in gas purchased for resale. Alagasco had net receivables from affiliates of $937,000 at September 30, 2001, net payables to affiliates of $1,156,000 at September 30, 2000 and net receivables from affiliates of $20,654,000 at September 30, 1999.
16 OIL AND GAS OPERATIONS (UNAUDITED) - -------------------------------------------------------------------------------
The following schedules detail historical financial data of the Company's oil and gas operations. Certain terms appearing in the schedules are prescribed by the Securities and Exchange Commission (SEC) and are briefly described as follows:
EXPLORATION EXPENSES are costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.
DEVELOPMENT COSTS include costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.
PRODUCTION (LIFTING) COSTS include costs incurred to operate and maintain wells.
GROSS REVENUES are reported after deduction of royalty interest payments.
GROSS WELL OR ACRE is a well or acre in which a working interest is owned.
NET WELL OR ACRE is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.
DRY WELL is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
PRODUCTIVE WELL is an exploratory or a development well that is not a dry well.
CAPITALIZED COSTS
COSTS INCURRED The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:
RESULTS OF OPERATIONS The following table sets forth results of the Company's oil and gas operations:
* Includes a $2.7 million, $3.8 million, and $3.3 million pre-tax writedown of a portion of an unproved leasehold in 2001, 2000, and 1999, respectively
** Includes a pre-tax writedown of $3.5 million in 2000 under SFAS No. 121 (see Note 10)
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE
DRILLING ACTIVITY The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
As of September 30, 2001, the Company was participating in the drilling of 10 gross development wells, with the Company's interest equivalent to 6.48 wells.
PRODUCTIVE WELLS AND ACREAGE The following table sets forth the total gross and net productive gas and oil wells as of September 30, 2001, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
There were 46 wells with multiple completions in 2001. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in the Permian Basin.
OIL AND GAS OPERATIONS The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that only proved categories of reserves be disclosed and that reserves and associated values be calculated using year-end prices and current costs. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. The proved reserves are located onshore in the United States.
During fiscal 2001, Energen Resources invested approximately $33.8 million in proved property acquisitions. Energen Resources sold approximately 18 Bcfe of proved reserves, recording net pre-tax gains of $4.6 million.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company's crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At September 30, 2001, 2000 and 1999, the Company had a deferred hedging gain of $25.7 million and deferred hedging losses of $89.4 million and $16.5 million, respectively, which are excluded from the calculation of standardized measure of future net cash flows.
Reserves and associated values were calculated using year-end prices and current costs. The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
COALBED METHANE ACTIVITIES Energen Resources is actively engaged in the production of pipeline-quality natural gas from coal seams (coalbed methane). The results of coalbed methane activities have been included in the oil and gas disclosures shown previously. Because of the significance of coalbed methane to Energen Resources, certain data are separately disclosed below:
Section 29 of the Internal Revenue Code of 1986, as amended, provides an income tax credit against federal regular income tax liability for sales of certain fuels produced from nonconventional sources (including natural gas from coal seams). Fuels qualifying for these credits must be produced from wells drilled after December 31, 1979, and before January 1, 1993, and must be sold before January 1, 2003. The credit for natural gas from coal seams is adjusted for inflation, and the Company estimates this credit will approximate $1.08 per Mcf of qualifying production in calendar year 2001. Accordingly, a significant portion of the value of proved coalbed methane reserves is associated with this tax credit.
17. INDUSTRY SEGMENT INFORMATION - -------------------------------------------------------------------------------
The Company is principally engaged in two business segments: the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1. Certain reclassifications have been made to conform the prior years' financial statements to the current year presentation.
18. SUBSEQUENT EVENT - -------------------------------------------------------------------------------
Certain of the physical sale contracts and swaps mentioned previously in Note 7 and Note 9 have Enron North America Corp. (Enron) as the counterparty. Enron filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 2, 2001. At November 30, 2001, Energen Resources had open swap positions with Enron for 8.98 Bcf of gas and 34,000 barrels of oil to be produced through the remainder of fiscal 2002 and open swap contracts for gas and oil basis differentials on its fiscal 2002 production, which constituted a net in-the-money position whereby Enron owes Energen Resources approximately $11.2 million. In addition, Energen Resources estimates it is due approximately $2.2 million for the value of its November 2001 swap positions. Energen Resources had also delivered approximately 1.5 Bcf of gas under a physical sales contract for which it was owed approximately $4.5 million by Enron at November 30, 2001. All of the previously mentioned three-way pricing, physical sales contracts were with Enron.
Alagasco had contracts in place with Enron with respect to its system supply. At November 30, 2001 Alagasco had received gas supply from Enron, for which it owed approximately $7.3 million.
In the days leading up to the bankruptcy filing, various events occurred which caused Enron to be in default under all of its agreements with Energen Resources and most of its agreements with Alagasco. These agreements provided Energen Resources and Alagasco with various remedies including, termination and liquidation rights in the event of such defaults. Energen Resources and Alagasco have and will continue to take the steps that they deem appropriate to avail themselves of the default remedies.
The Company has previously treated the swap agreements as qualifying for cash flow hedge accounting under SFAS No. 133. The Company is currently evaluating the implications of the present situation to its financial statements. It is possible that future earnings will be less than previously estimated due to collectibility issues with respect to the Energen Resources advantageous swap position. Energen Resources should be able to remarket physical volumes not taken by Enron, but these volumes as well as volumes covered by Enron hedges will be at current prices, provided the Company does not enter into new hedges. Alagasco expects to be able to replace any volumes not delivered by Enron without impact to the operation of its distribution system or reliability of supply. The ultimate resolution of the arrangements between Energen Resources and Enron as well as Alagasco and Enron cannot be determined at this time.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held January 30, 2002. The proxy statement will be filed on or about December 20, 2001.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held January 30, 2002.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information regarding the security ownership of the beneficial owners of more than five percent of Energen's common stock is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held January 30, 2002.
B. SECURITY OWNERSHIP OF MANAGEMENT
The information regarding the security ownership of management is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held January 30, 2002.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held January 30, 2002.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
A. DOCUMENTS FILED AS PART OF THIS REPORT
(1) FINANCIAL STATEMENTS The consolidated financial statements of Energen and the financial statements of Alagasco are included in Item 8 of this Form 10-K.
(2) FINANCIAL STATEMENT SCHEDULES The financial statement schedules are included in Item 8 of this Form 10-K.
(3) EXHIBITS The exhibits listed on the accompanying Index to Exhibits are filed as part of this Form 10-K.
B. REPORTS ON FORM 8-K
Form 8-K dated December 13, 2000, reporting Energen's Consolidated Ratios of Earnings to Fixed Charges for the years ended September 30, 2000, 1999, 1998, 1997 and 1996.
Form 8-K dated August 30, 2001, reporting two series of notes offered by Alagasco. The aggregate principal amount of notes offered was $75 million; $40 million of 6.25% Notes due September 1, 2016 and $35 million of 6.75% Notes due September 1, 2031.
ENERGEN CORPORATION ALABAMA GAS CORPORATION INDEX TO EXHIBITS ITEM 14(A)(3)
* Incorporated by reference
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION (Registrant)
ALABAMA GAS CORPORATION (Registrant)
December 5, 2001 By /s/ Wm. Michael Warren, Jr. - -------------------------- ------------------------------- Wm. Michael Warren, Jr. Chairman, President and Chief Executive Officer of Energen, Chairman and Chief Executive Officer of Alabama Gas Corporation
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrants and in the capacities and on the dates indicated: