UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
x |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE YEAR ENDED DECEMBER 31, 2005
¨ |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
Commission File Number |
Registrant |
State of Incorporation |
IRS Employer Identification Number |
|||
1-7810 | Energen Corporation | Alabama | 63-0757759 | |||
2-38960 | Alabama Gas Corporation | Alabama | 63-0022000 |
605 Richard Arrington Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class |
Exchange on Which Registered |
|
Energen Corporation Common Stock, $0.01 par value |
New York Stock Exchange | |
Energen Corporation Preferred Stock Purchase Rights |
New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO x
Indicate by a check mark whether registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. YES x NO ¨
Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).
Energen Corporation | Large accelerated filer x | Accelerated filer ¨ | Non-accelerated filer ¨ | |||
Alabama Gas Corporation | Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x |
Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2005:
Energen Corporation | $2,552,980,558 |
Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x
Indicate number of shares outstanding of each of the registrants classes of common stock as of March 2, 2006:
Energen Corporation |
73,469,820 shares | |||||
Alabama Gas Corporation |
1,972,052 shares |
Alabama Gas Corporation meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction I(2).
DOCUMENTS INCORPORATED BY REFERENCE
Energen Corporation Proxy Statement to be filed on or about March 24, 2006 (Part III, Item 10-13)
INDUSTRY GLOSSARY
For a more complete definition of certain terms defined below, please refer to Rule 4-10(a) of Regulation S-X,
promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.
Basis |
The difference between the futures price for a commodity and the corresponding cash spot price. The differential commonly is related to factors such as product quality, location and contract pricing. |
|
Basin-Specific |
A type of derivative contract whereby the contracts settlement price is based on specific geographic basin indices. |
|
Behind Pipe Reserves |
Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs. |
|
Call Option |
A contract that gives the investor the right, but not the obligation, to buy the underlying commodity at a certain price on an agreed upon date. |
|
Cash Flow Hedge |
The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale. |
|
Collar |
A financial arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price. |
|
Development Well |
A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. |
|
Exploratory Well |
A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. |
|
Futures Contract |
An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts. |
|
Hedging |
The use of derivative commodity instruments such as futures, swaps and collars to help reduce financial exposure to commodity price volatility. |
|
Liquified Natural Gas (LNG) |
Natural gas that is liquified by reducing the temperature to negative 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand. |
|
Long-Lived Reserves |
Reserves generally considered to have a productive life of approximately 10 years or more, as measured by the reserves-to-production ratio. |
|
Natural Gas Liquids (NGL) |
Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons. |
|
Odorization |
The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell. |
|
Operational Enhancement |
Any action undertaken to improve production efficiency of oil and gas wells and/or reduce well costs. |
|
Operator |
The company responsible for exploration, development and production activities for a specific project. |
|
Pay-Add |
An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s). |
|
Pay Zone |
The formation from which oil and gas is produced. |
Proved Developed Reserves |
The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. |
|
Proved Reserves |
Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. |
|
Proved Undeveloped Reserves (PUD) |
The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. |
|
Put Option |
A contract that gives the purchaser the right, but not the obligation, to sell the underlying commodity at a certain price on an agreed date. |
|
Recompletion |
An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone. |
|
Reserves-to- Production Ratio |
Ratio expressing years of supply determined by dividing the remaining recoverable reserves at year end by actual annual production volumes. |
|
Secondary Recovery |
The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts. |
|
Swap |
A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or swap variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk. |
|
Transportation |
Moving gas through pipelines on a contract basis for others. |
|
Throughput |
Total volumes of natural gas sold or transported by the gas utility. |
|
Working Interest |
Ownership interest in the oil and gas properties that is burdened with the cost of development and operation of the property. |
|
Workover |
A major remedial operation on a completed well to restore, maintain, or improve the wells production such as deepening the well or plugging back to produce from a shallow formation. |
|
-e |
Following a unit of measure denotes that the oil and natural gas liquids components have been converted to cubic feet equivalents at a rate of 6 thousand cubic feet per barrel. |
2005 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
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This Form 10 - K is filed on behalf of Energen Corporation (Energen or the Company)
and Alabama Gas Corporation (Alagasco).
Forward-Looking Statements: 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 forward-looking statements do not reflect the impact of possible or pending acquisition, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any 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, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.
Third Party Facilities: The forward-looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources Corporation, the Companys oil and gas subsidiary, relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.
Energen Resources Production: 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 reserve 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.
Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Companys financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Companys financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed- price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources position.
Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagascos risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagascos actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts.
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A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagascos position.
Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagascos, Energen Resources and/or the Companys financial position, results of operations and cash flows.
Alagasco Service Territory: Alagascos utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.
General
Energen Corporation, based in Birmingham, Alabama, is a 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 principal 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.
The Company maintains a Web site with the address www.energen.com . The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. Also, these reports are available in print upon shareholder request. These reports are provided as soon as reasonably practicable after being electronically filed with or furnished to the Securities and Exchange Commission. The Companys Web site also includes its Code of Ethics, Corporate Governance Guidelines, Audit Committee Charter, Officers Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter each of which is available in print upon shareholder request.
Financial Information About Industry Segments
The information required by this item is provided in Note 22, Industry Segment Information, in the Notes to Financial Statements.
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Narrative Description of Business
| Oil and Gas Operations |
General: Energens oil and gas operations focus on increasing production and adding proved reserves through the acquisition and development of oil and gas properties. To a lesser extent, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. Substantially all gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, San Juan and Permian basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations.
At the end of 2005, Energen Resources proved oil and gas reserves totaled 1,722 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 81 percent of Energen Resources year-end reserves are proved developed reserves. Energen Resources reserves are long-lived, with a year-end reserves-to-production ratio of 19 years. Natural gas represents approximately 63 percent of Energen Resources proved reserves, with oil representing approximately 26 percent and natural gas liquids comprising the balance.
Growth Strategy: Energen has operated for more than ten years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1.2 billion in property acquisitions, $838 million in related development, and $119 million in exploration and related development. Energen Resources capital investment for oil and gas activities over the five-year period ending December 31, 2010, is currently expected to approximate $372 million for development on existing properties and $38 million for exploratory and other activities. As an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energens acquisition criteria. These investments would result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years for property acquisitions that meet Energens acquisition criteria.
Energen Resources approach to the oil and gas business calls for the company to pursue onshore North American property acquisitions which offer proved undeveloped (PUD) and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers operated natural gas properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources will consider acquisitions of other types of properties which meet its investment requirements. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering exploration activities which complement its core expertise and meet its investment requirements.
Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties PUD and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, limited exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of development activities.
Energen Resources development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing which increase the number of available drilling locations; changes in the economic or operating environments which allow previously uneconomic locations to be added; technological advances which make reserve locations available for development; successful development of existing PUD locations which reclassify adjacent probable locations to PUD locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in managements intent to develop certain opportunities.
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During the three years ended December 31, 2005, the Companys development efforts have added 295 Bcfe of proved reserves from the drilling of 929 gross development wells and 333 well recompletions and pay-adds. In 2005, Energen Resources successful development wells and other activities added approximately 90 Bcfe of proved reserves. The company drilled 294 gross development wells, performed some 77 well recompletions and pay-adds, and conducted other operational enhancements in 2005. Energen Resources production from continuing operations totaled 91 Bcfe in 2005 and is estimated to total 92 Bcfe in 2006, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2005.
Risk Management: Energen Resources attempts to lower the risks associated with its oil and natural gas business. A key component of the companys efforts to manage risk is its acquisition versus exploration orientation and its preference for long-lived reserves. In pursuing an acquisition, Energen Resources primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge more than two fiscal years forward. In the case of an acquisition, Energen Resources may hedge further forward to protect targeted returns.
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended 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 effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured 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 derivatives 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 operating revenues in the period of change.
The Company from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, put options and swaps on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.
See the Forward-Looking Statements in Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.
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 anticipated environmental liabilities are minimal. To the extent that Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately.
During 2004, the State of New Mexico issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed above ground or with secondary containment and visual leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of this regulation, the Company expensed $1 million as lease operating expense during 2005. During 2004, the Company capitalized $0.5 million as part of its acquisition of properties in the San Juan Basin and expensed $1.6 million as lease operating expense under this regulation. The Company does not anticipate any further remediation charges on existing properties related to the new regulations.
| 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
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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.
Alagascos service territory is located in central and parts of north Alabama and includes 191 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2005, Alagasco served an average of 425,110 residential customers and 34,936 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,000 miles of main and more than 11,700 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 established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended RSE for a six-year period through January 1, 2008. Under the APSC order, Alagascos allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the returns on equity of all major energy utilities operating under a similar methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).
Under RSE, the APSC conducts quarterly reviews to determine, based on Alagascos projections and year-to-date performance, whether Alagascos return on average equity at the end of the rate 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 rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utilitys equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagascos 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.
The temperature adjustment rider to Alagascos rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco calculates a temperature adjustment to customers monthly bills to substantially remove the effect of departures from normal temperatures on Alagascos earnings. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. 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. Alagascos 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 October 1997, 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 rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagascos return on equity to fall below 13.15 percent. 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.
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Gas Supply: Alagascos distribution system is connected to two major interstate natural gas pipeline systems, Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Company (Transco). It is also connected to several intrastate natural gas pipeline systems and to Alagascos two liquified natural gas (LNG) facilities.
Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagascos system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the systems varying levels of demand. Alagascos LNG facilities can provide the system with up to 200,000 additional thousand cubic feet per day (Mcfd) of natural gas to meet peak day demand.
As of December 31, 2005, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:
December 31, 2005 (Mcfd) |
||
Southern firm transportation |
154,892 | |
Southern storage and no notice transportation |
251,679 | |
Transco firm transportation |
70,000 | |
Various intrastate transportation |
20,240 |
Competition and Rate Flexibility: The price of natural gas is a significant competitive factor in Alagascos 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 customer gas load in the marketplace. Rate flexibility remains critical as the utility faces competition for this 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; Alagascos 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 its small commercial and industrial customers. In 2005, approximately 300 of Alagascos transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.9 million.
The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagascos 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 Alagascos tariff allows the Company to recover a 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 systems fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagascos sales profit margin so that operating margins are unaffected. During 2005 substantially all of Alagascos large commercial and industrial customer deliveries were the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for more than 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 2005, 50 of the utilitys largest commercial and industrial transportation customers were under special contracts of varying lengths.
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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 to 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 2005, Alagascos average number of customers decreased slightly. Alagasco will continue to concentrate on maintaining its current penetration levels in the residential new construction market and generating additional revenue in the small and large commercial and industrial market segments.
Seasonality: Alagascos gas distribution business is highly seasonal since a material portion of the utilitys total sales and delivery volumes is to space heating customers. Alagascos 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 Alagascos 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 nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). 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, Alagascos share, if any, of such costs will not materially affect the Companys financial position, results of operations or cash flows.
Employees
The Company has approximately 1,500 employees, of which Alagasco employs 1,200 and Energen Resources employs 300. The Company believes that its relations with employees are good.
10
Third Party Facilities: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.
Energen Resources Production: 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 reserve 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.
Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Companys financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Companys financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources position.
Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagascos risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagascos actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagascos position.
Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagascos, Energen Resources and/or the Companys financial position, results of operations and cash flows.
11
Energen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Companys overall exposure to credit risk, either positively or negatively, in that the Companys oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers account for approximately 29 percent, 19 percent and 14 percent, respectively, of Energen Resources estimated 2006 production. Energen Resources other purchasers each bought less than 8 percent of production.
Alagasco Service Territory: Alagascos utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.
Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by rating agency evaluations of the Company and of Alagasco.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None
12
The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. Energen Resources maintains offices in Midland, Lehman, Seminole, Westbrook and Penwell, Texas, in Farmington, New Mexico, in Oak Grove, Vance and Tuscaloosa, Alabama 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 and reserves is summarized in the table below and included in Note 21, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements.
The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 10,000 miles of main and more than 11,700 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, four division commercial offices, three division business centers, two payment centers, four district offices, six service centers, and other related property and equipment, some of which are leased by Alagasco.
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 or other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.
Cochran County, Texas
In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judges order and expects to prevail. Under the Judges order, Energen Resources potential pre-tax charge to income would be approximately $3.3 million as of December 31, 2005, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition.
Jefferson County, Alabama
In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources
13
received notice of immediate lease termination from RGGS. As of December 31, 2005, Energens consolidated balance sheet included approximately $96 million in net oil and gas properties associated with the lease. During 2005, Energen Resources production associated with the lease was approximately 11 Bcf.
RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no accrual with respect to the litigation or purported lease termination.
Other
Various other pending or threatened legal proceedings are in progress currently and the Company has accrued a provision for the estimated liability.
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 2005.
14
EXECUTIVE OFFICERS OF THE REGISTRANTS
Energen Corporation
Name |
Age |
Position (1) |
||
Wm. Michael Warren, Jr. |
58 | Chairman of the Board and Chief Executive Officer (2) | ||
James T. McManus, II |
47 | President and Chief Operating Officer of Energen, President of Energen Resources (3) | ||
Geoffrey C. Ketcham |
55 | Executive Vice President, Chief Financial Officer and Treasurer (4) | ||
Dudley C. Reynolds |
53 | President and Chief Operating Officer of Alagasco (5) | ||
Grace B. Carr |
50 | Vice President and Controller (6) | ||
J. David Woodruff, Jr. |
49 | General Counsel and Secretary and Vice President-Corporate Development (7) |
Notes: | (1) |
All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the 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 also a Director of Protective Life Corporation. |
|||
(3) |
Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997. He was elected President and Chief Operating Officer of Energen effective January 1, 2006. |
|||
(4) |
Mr. Ketcham has been employed by the Company in various financial and strategic planning 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. |
|||
(5) |
Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003. |
|||
(6) |
Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from May 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001. |
|||
(7) |
Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991 and Vice President-Corporate Development of Energen in October 1995. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003. |
15
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Market Prices and Dividends Paid Per Share
Quarter ended (in dollars) |
High | Low | Close | Dividends Paid | ||||
March 31, 2003 |
16.03 | 14.04 | 16.03 | .09 | ||||
June 30, 2003 |
17.15 | 15.80 | 16.65 | .09 | ||||
September 30, 2003 |
18.55 | 15.68 | 18.09 | .0925 | ||||
December 31, 2003 |
21.00 | 18.07 | 20.52 | .0925 | ||||
March 31, 2004 |
22.36 | 19.94 | 20.63 | .0925 | ||||
June 30, 2004 |
24.28 | 20.06 | 24.00 | .0925 | ||||
September 30, 2004 |
25.98 | 22.93 | 25.78 | .09625 | ||||
December 31, 2004 |
30.04 | 25.44 | 29.48 | .09625 | ||||
March 31, 2005 |
34.09 | 27.06 | 33.30 | .10 | ||||
June 30, 2005 |
35.64 | 28.65 | 35.05 | .10 | ||||
September 30, 2005 |
43.56 | 33.85 | 43.26 | .10 | ||||
December 31, 2005 |
44.31 | 34.50 | 36.32 | .10 |
Energens common stock is listed on the New York Stock Exchange under the symbol EGN. On February 1, 2006, there were 7,662 holders of record of Energens common stock. At the date of this filing, Energen Corporation owns all the issued and outstanding common stock of Alabama Gas Corporation.
The following table summarizes information concerning securities authorized for issuance under equity compensation plans:
The following table summarizes information concerning purchases of equity securities by the issuer:
* |
Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans. |
** |
By resolution adopted May 24, 1994, and supplemented by a resolution adopted April 26, 2000, the Board of Directors authorized the Company to repurchase up to 3,564,400 shares of the Companys common stock. The resolutions do not have an expiration date. |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.
16
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data as set forth below should be read in
SELECTED FINANCIAL AND COMMON STOCK DATA
Energen Corporation
(dollars in thousands, except per share amounts) |
Year Ended December 31, 2005 |
Year Ended December 31, 2004 |
Year Ended December 31, 2003 |
Year Ended December 31, 2002 |
Three Months Ended
December 31,
|
Year Ended September 30, 2001 |
||||||||||||
INCOME STATEMENT |
||||||||||||||||||
Operating revenues |
$ | 1,128,394 | $ | 936,857 | $ | 841,631 | $ | 667,419 | $ | 143,553 | $ | 762,124 | ||||||
Income from continuing operations before cumulative effect of change in accounting principle |
$ | 172,886 | $ | 127,305 | $ | 110,104 | $ | 70,204 | $ | 2,261 | $ | 57,645 | ||||||
Net income |
$ | 173,012 | $ | 127,463 | $ | 110,654 | $ | 68,639 | $ | 3,658 | $ | 67,896 | ||||||
Diluted earnings per average common share from continuing operations before cumulative effect of change in accounting principle |
$ | 2.35 | $ | 1.74 | $ | 1.54 | $ | 1.04 | $ | 0.04 | $ | 0.93 | ||||||
Diluted earnings per average common share |
$ | 2.35 | $ | 1.74 | $ | 1.55 | $ | 1.01 | $ | 0.06 | $ | 1.09 | ||||||
BALANCE SHEET |
||||||||||||||||||
Total property, plant and equipment, net |
$ | 2,068,011 | $ | 1,783,059 | $ | 1,433,451 | $ | 1,351,554 | $ | 1,093,201 | $ | 1,084,052 | ||||||
Total assets |
$ | 2,618,226 | $ | 2,181,739 | $ | 1,778,232 | $ | 1,643,012 | $ | 1,342,346 | $ | 1,313,885 | ||||||
Long-term debt |
$ | 683,236 | $ | 612,891 | $ | 552,842 | $ | 512,954 | $ | 544,133 | $ | 544,110 | ||||||
Total shareholders equity |
$ | 892,678 | $ | 803,666 | $ | 699,032 | $ | 582,810 | $ | 474,205 | $ | 480,767 | ||||||
COMMON STOCK DATA |
||||||||||||||||||
Annual dividend rate at period-end |
$ | 0.40 | $ | 0.385 | $ | 0.37 | $ | 0.36 | $ | 0.35 | $ | 0.35 | ||||||
Cash dividends paid per common share |
$ | 0.40 | $ | 0.3775 | $ | 0.365 | $ | 0.355 | $ | 0.0875 | $ | 0.3425 | ||||||
Shares outstanding at period-end (000) |
73,493 | 73,166 | 72,447 | 69,491 | 62,497 | 62,250 | ||||||||||||
Price range: |
||||||||||||||||||
High |
$ | 44.31 | $ | 30.04 | $ | 21.00 | $ | 15.00 | $ | 12.60 | $ | 20.13 | ||||||
Low |
$ | 27.06 | $ | 19.94 | $ | 14.04 | $ | 10.83 | $ | 10.75 | $ | 10.75 | ||||||
Close |
$ | 36.32 | $ | 29.48 | $ | 20.52 | $ | 14.55 | $ | 12.33 | $ | 11.25 | ||||||
* |
On December 5, 2001, the Board of Directors of the Company approved a change in the Companys fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001. |
All information has been restated to reflect a 2-for-1 stock split effective June 1, 2005.
17
SELECTED BUSINESS SEGMENT DATA
Energen Corporation
(dollars in thousands) |
Year Ended December 31, 2005 |
Year Ended December 31, 2004 |
Year Ended December 31, 2003 |
Year Ended December 31, 2002 |
Three Months Ended
December 31,
|
Year Ended September 30, 2001 |
|||||||||||||
OIL AND GAS OPERATIONS |
|||||||||||||||||||
Operating revenues from continuing operations |
|||||||||||||||||||
Natural gas |
$ | 365,635 | $ | 276,482 | $ | 235,022 | $ | 145,443 | $ | 34,213 | $ | 131,875 | |||||||
Oil |
116,651 | 98,409 | 87,192 | 72,132 | 11,126 | 43,867 | |||||||||||||
Natural gas liquids |
38,455 | 30,902 | 25,938 | 21,843 | 4,282 | 24,540 | |||||||||||||
Other |
6,953 | 4,324 | 4,380 | 3,570 | (2,746 | ) | 7,980 | ||||||||||||
Total |
$ | 527,694 | $ | 410,117 | $ | 352,532 | $ | 242,988 | $ | 46,875 | $ | 208,262 | |||||||
Production volumes from continuing operations |
|||||||||||||||||||
Natural gas (MMcf) |
61,048 | 57,164 | 55,304 | 45,891 | 11,420 | 43,956 | |||||||||||||
Oil (MBbl) |
3,316 | 3,434 | 3,411 | 2,989 | 464 | 1,873 | |||||||||||||
Natural gas liquids (MMgal) |
70.5 | 68.2 | 66.6 | 71.9 | 18.0 | 58.6 | |||||||||||||
Production volumes from continuing operations (MMcfe) |
91,020 | 87,513 | 85,291 | 74,093 | 16,766 | 63,572 | |||||||||||||
Total production volumes (MMcfe) |
91,099 | 87,606 | 86,157 | 77,973 | 18,022 | 68,478 | |||||||||||||
Proved reserves |
|||||||||||||||||||
Natural gas (MMcf) |
1,080,161 | 1,019,436 | 886,307 | 803,748 | 714,395 | 627,051 | |||||||||||||
Oil (MBbl) |
74,962 | 54,500 | 52,528 | 49,833 | 19,128 | 20,878 | |||||||||||||
Natural gas liquids (MBbl) |
31,934 | 34,613 | 27,245 | 26,697 | 25,944 | 24,931 | |||||||||||||
Total (MMcfe) |
1,721,537 | 1,554,114 | 1,364,945 | 1,262,928 | 984,827 | 901,905 | |||||||||||||
Other data from continuing operations Lease operating expense (LOE) |
|||||||||||||||||||
LOE and other |
$ | 104,241 | $ | 79,191 | $ | 67,833 | $ | 56,932 | $ | 12,917 | $ | 53,451 | |||||||
Production taxes |
52,271 | 37,285 | 27,686 | 18,186 | 3,379 | 22,800 | |||||||||||||
Total |
$ | 156,512 | $ | 116,476 | $ | 95,519 | $ | 75,118 | $ | 16,296 | $ | 76,251 | |||||||
Depreciation, depletion and amortization |
$ | 89,340 | $ | 80,896 | $ | 79,495 | $ | 70,285 | $ | 15,266 | $ | 51,036 | |||||||
Capital expenditures |
$ | 353,712 | $ | 403,936 | $ | 163,338 | $ | 305,476 | $ | 25,052 | $ | 136,886 | |||||||
Operating income |
$ | 243,876 | $ | 180,379 | $ | 153,325 | $ | 78,680 | $ | 2,033 | $ | 61,364 | |||||||
NATURAL GAS DISTRIBUTION |
|||||||||||||||||||
Operating revenues |
|||||||||||||||||||
Residential |
$ | 384,753 | $ | 340,229 | $ | 320,938 | $ | 277,088 | $ | 63,724 | $ | 367,109 | |||||||
Commercial and industrial |
166,957 | 138,686 | 126,638 | 104,247 | 22,445 | 147,636 | |||||||||||||
Transportation |
43,291 | 40,221 | 38,250 | 38,395 | 9,765 | 33,972 | |||||||||||||
Other |
5,699 | 7,604 | 3,273 | 4,701 | 744 | 5,145 | |||||||||||||
Total |
$ | 600,700 | $ | 526,740 | $ | 489,099 | $ | 424,431 | $ | 96,678 | $ | 553,862 | |||||||
Gas delivery volumes (MMcf) |
|||||||||||||||||||
Residential |
24,601 | 25,383 | 27,248 | 26,358 | 5,128 | 31,064 | |||||||||||||
Commercial and industrial |
12,498 | 12,323 | 12,564 | 11,838 | 2,193 | 14,054 | |||||||||||||
Transportation |
49,850 | 54,385 | 55,623 | 59,644 | 12,973 | 53,989 | |||||||||||||
Total |
86,949 | 92,091 | 95,435 | 97,840 | 20,294 | 99,107 | |||||||||||||
Average number of customers |
|||||||||||||||||||
Residential |
425,110 | 425,673 | 427,413 | 425,630 | 422,461 | 428,663 | |||||||||||||
Commercial, industrial and transportation |
34,936 | 35,248 | 35,463 | 35,601 | 35,161 | 35,882 | |||||||||||||
Total |
460,046 | 460,921 | 462,876 | 461,231 | 457,622 | 464,545 | |||||||||||||
Other data |
|||||||||||||||||||
Depreciation and amortization |
$ | 42,351 | $ | 39,881 | $ | 37,171 | $ | 33,682 | $ | 8,151 | $ | 30,933 | |||||||
Capital expenditures |
$ | 73,276 | $ | 58,208 | $ | 57,906 | $ | 65,815 | $ | 12,873 | $ | 56,090 | |||||||
Operating income |
$ | 72,922 | $ | 66,199 | $ | 66,848 | $ | 59,370 | $ | 8,034 | $ | 50,288 | |||||||
* |
On December 5, 2001, the Board of Directors of the Company approved a change in the Companys fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001. |
18
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING POLICIES
The Companys consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company. The application of these accounting policies necessarily requires managements most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements:
Oil and Gas Operations
Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Under this accounting method, acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Companys net interests in oil and gas properties as of December 31, 2005. The independent reservoir engineers have issued reports covering approximately 91 percent of the Companys ending proved reserves and in their judgment these estimates are reasonable in the aggregate. The Companys production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.
Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the propertys book value if an impairment is warranted. The table below reflects the estimated increase in 2006 depreciation, depletion and amortization expense associated with assumed downward changes in oil and gas reserve quantities from the reported amounts at December 31, 2005.
Percentage Change in Oil & Gas Reserves
From Reported Reserves as of December 31, 2005 |
||||||
(dollars in thousands) |
-5% | -10% | ||||
Estimated change in depreciation expense for the year ended December 31, 2006, net of tax |
$ | 3,000 | $ | 6,300 |
Asset Impairments: Oil and gas developed properties periodically are assessed for possible impairment, generally on a field-by-field basis, using the estimated undiscounted future cash flows of each field. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. The Company monitors its oil and gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, substantial commodity price declines, unanticipated increased operating costs, and lower-than-expected production performance. If a material event occurs, Energens oil and gas subsidiary, Energen Resources Corporation, makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.
19
Cash flow and fair value estimates require Energen Resources to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on the Companys need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Companys original and ongoing assessments of potential impairment.
Energen Resources adheres to Statement of Financial Accounting Standards (SFAS) No.19, Financial Accounting and Reporting by Oil and Gas Producing Companies, for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relates to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. The Company considers a combination of geologic and engineering factors to evaluate the need for impairment of these costs.
Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Companys financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.
Natural Gas Distribution
Regulated Operations: Alabama Gas Corporation (Alagasco), Energens utility subsidiary, applies SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to its regulated operations. This standard requires a cost to be capitalized as a regulatory asset that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, SFAS No. 71 requires the cost to be recognized as a regulatory liability. The Company anticipates SFAS No. 71 will continue as the applicable accounting standard for its regulated operations. Alagascos rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983.
Consolidated
Employee Pension Plans: The Company calculates net periodic pension expense and liabilities on an actuarial basis under the provisions of SFAS No. 87, Employers Accounting for Pensions. The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements. Actuarial assumptions attempt to anticipate future events and are used in calculating the expenses and liabilities related to these plans. The calculation of the liability related to the Companys defined benefit pension plans requires assumptions regarding the appropriate weighted average discount rate, estimated weighted average rate of increase in the compensation level of its employee base and the expected long-term rate of return on the plans assets. The selection and use of such assumptions affects the amount of expense recorded in the Companys financial statements related to its defined benefit pension plans. In selecting the discount rate, consideration is given to Moodys Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments. The discount rate used for actuarial purposes covering a majority of employees was 5.75 percent for the year ended December 31, 2005. A
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hypothetical 25 basis point change in the discount rate would impact total pension expense by approximately $1,010,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The return on assets used for actuarial purposes was 8.5 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $320,000. The estimated weighted average rate of increase in the compensation level of the Companys employees was 4 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the estimated rate of increase in the compensation level of applicable employees would impact total pension expense by approximately $670,000. The discount rate, return on plan assets and estimated rate of compensation increase used in the actuarial assumptions for 2006 is 5.5 percent, 8.5 percent, and 3.5 percent, respectively.
Asset Retirement Obligation:
The Company
records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs
are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and the resulting gain or loss. Energen Resources has an obligation to remove
tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution
and transmission lines upon abandonment. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in
RESULTS OF OPERATIONS
Consolidated Net Income
Energen Corporations net income for the year ended December 31, 2005 totaled $173 million, or $2.35 per diluted share and compared favorably to the year ended December 31, 2004 net income of $127.5 million, or $1.74 per diluted share. This 35.1 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids as well as the impact of a 3.5 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources. For the year ended December 31, 2005, Energen Resources earned $135.3 million, as compared with $94.1 million in the previous year. Alagasco generated a 9.4 percent increase in net income, earning $37 million in the current year as compared with net income in the prior period of $33.8 million. For the year ended December 31, 2003, Energen reported earnings of $110.7 million, or $1.55 per diluted share.
2005 vs 2004: Energen Resources net income rose 43.8 percent to $135.3 million in 2005. Energen Resources income from continuing operations totaled $135.2 million in 2005 as compared with $93.9 million in 2004. Discontinued operations in 2005 generated income of $126,000 as compared with income of $158,000 in 2004. The primary factors positively influencing income from continuing operations included increased commodity prices of approximately $62 million after-tax along with the impact of increased production volumes of approximately $10 million after-tax. These increases were partially offset by higher lease operating expense of approximately $16 million after-tax, higher production taxes of approximately $9 million after-tax, increased depreciation, depletion and amortization (DD&A) expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax.
Alagasco earned net income of $37 million in 2005 as compared with net income of $33.8 million in 2004. This increase in earnings largely reflected the utilitys ability to earn on a higher level of equity. Alagascos return on average equity (ROE) was 13.5 percent in 2005 compared with 12.8 percent in 2004.
2004 vs 2003: For the year ended December 31, 2004, Energen Resources net income totaled $94.1 million as compared with $78.9 million for the 12 months ended December 31, 2003. Energen Resources income from continuing operations totaled $93.9 million in 2004 as compared with $78.4 million in 2003, primarily due to higher commodity prices of approximately $31 million after-tax along with the impact of increased production volumes of approximately $6 million after-tax. The primary negative influences on income from continuing operations were higher lease operating expense of approximately $7 million after-tax, higher production taxes of approximately $6 million after-tax and increased administrative expenses of approximately $4 million after-tax.
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Alagasco earnings increased to $33.8 million in 2004 from $33 million in 2003 largely as a result of the utility earning on a higher level of equity. Alagasco achieved a ROE of 12.8 percent in 2004 compared with 13.5 percent in 2003.
Operating Income
Consolidated operating income in 2005, 2004 and 2003 totaled $315.7 million, $244.8 million and $217.6 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energens diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return.
Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices and increased production volumes. Increases in production primarily related to the August 2004 purchase of San Juan Basin coalbed methane properties and increased drilling of wells in North Louisiana. Negatively affecting production was a normal production decline in excess of new production coming on-line primarily in the Permian Basin. Revenue per unit of production for natural gas production increased 23.8 percent to $5.99 per thousand cubic feet (Mcf), oil revenue per unit of production rose 22.8 percent to $35.18 per barrel and natural gas liquids revenue per unit of production increased 22.2 percent to an average price of $0.55 per gallon during 2005. Production from continuing operations increased 4 percent to 91 Bcfe during 2005. Natural gas production rose 6.8 percent to 61 billion cubic feet (Bcf) and oil volumes declined 3.4 percent to 3,316 thousand barrels (MBbl). Production of natural gas liquids increased 3.4 percent to 70.5 million gallons (MMgal).
In 2004, revenues from oil and gas operations increased primarily as a result of increased commodity prices, an increase in volumes related to the August 2004 acquisition of coalbed methane properties and additional drilling of coalbed methane wells in the San Juan and Black Warrior basins. Revenue per unit of production related to natural gas increased 13.9 percent to $4.84 per Mcf, oil revenues per unit of production rose 12.1 percent to $28.66 per barrel and natural gas liquids revenue per unit of production increased 15.4 percent to an average price of $0.45 per gallon during the year ended December 31, 2004. Production from continuing operations rose 2.6 percent to 87.5 Bcfe in 2004. Natural gas production increased 3.4 percent to 57.2 Bcf, oil volumes increased slightly to 3,434 MBbl and natural gas liquids production increased 2.4 percent to 68.2 MMgal.
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 $8.7 million, $6.6 million and $6.1 million in 2005, 2004 and 2003, respectively.
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Energen Resources may, in the ordinary course of business, be involved in the sale of developed or 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. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144,Accounting for Impairment or Disposal of Long-Lived Assets. During 2005, Energen Resources recorded a pre-tax gain of $213,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million.
Operations and maintenance (O&M) expense increased $31.1 million and $19 million in 2005 and 2004, respectively. Lease operating expense (excluding production taxes) in 2005 increased $25.1 million primarily due to increased workover and maintenance expenses, increased ad valorem taxes, higher transportation costs and other overall price increases related to higher commodity prices. Partially offsetting these increases were lower compliance costs related to prior year regulations for below-grade storage pits. In 2004, lease operating expense (excluding production taxes) increased by $11.4 million primarily due to increased workover and maintenance expense, costs associated with storage pit regulatory requirements and higher transportation costs. Administrative expense increased $7.5 million in 2005 largely due to labor-related costs. In 2004, administrative expense increased $6.6 million primarily due to labor-related costs as well as costs related to the San Juan Basin property acquisition. Exploration expense decreased $1.4 million in 2005 largely due to decreased exploratory efforts. In 2004, exploration expense increased $1 million.
DD&A expense increased $8.4 million in 2005 and $1.4 million in 2004. The average depletion rates were $0.96 per Mcfe in 2005, $0.90 per Mcfe in 2004 and $0.92 per Mcfe in 2003. The increase in the 2005 rate was largely due to a higher depletion rate on coalbed methane properties purchased in the prior year as well as to the current year production mix that reflects a higher percentage of the Companys shorter-lived North Louisiana/East Texas production. Increased production volumes also contributed to the increase in DD&A expense during 2005.
Energen Resources expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes of $52.3 million, $37.3 million and $27.7 million for 2005, 2004 and 2003, respectively. Increased severance taxes were the result of increased commodity prices and production.
Natural Gas Distribution: As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the utilitys rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission 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 Alagascos 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 temperature adjustment mechanism that requires Alagasco to adjust certain customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.
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Alagascos natural gas and transportation sales revenues totaled $600.7 million, $526.7 million and $489.1 million in 2005, 2004 and 2003, respectively. Sales revenue in 2005 and 2004 increased primarily due to an increase in commodity gas costs. In 2005, weather was 3.6 percent colder than in the prior year. Residential sales volumes declined 3.1 percent while commercial and industrial volumes increased 1.4 percent. Large transportation volumes decreased 8.3 percent primarily related to higher gas prices. During 2004, weather that was 6 percent warmer than in the prior year contributed to a 6.8 percent decline in residential sales volumes and a 1.9 percent decrease in commercial and industrial volumes. Large transportation volumes decreased 2.2 percent. In 2005, higher commodity gas costs along with increased gas purchase volumes contributed to a 21.6 percent increase in cost of gas. Higher commodity gas cost generated a 10.9 percent increase in cost of gas in 2004.
O&M expense at the utility increased 3.4 percent in 2005 largely due to higher bad debt expense and distribution maintenance expenses. These increases were partially offset by decreased labor-related expense, primarily as a result of additional labor costs capitalized in the current year. In 2004, O&M expense increased 6.9 percent primarily due to increased labor-related costs. The increase in O&M expense per customer for the rate years ended September 30, 2004 and 2003 were above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utilitys rate-setting mechanism; as a result, three quarters of the differences, or $1.2 million and $0.1 million pre-tax, respectively, were returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements). Alagascos O&M expense fell within the index range for the rate year ended September 30, 2005.
Depreciation expense rose 6.2 percent and 7.3 percent in 2005 and 2004, respectively, due to normal growth of the utilitys distribution and support systems. Alagascos 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: Interest expense in 2005 increased $4.1 million primarily due to the issuance of $100 million of Floating Rate Senior Notes by Energen in November 2004, Alagascos issuance of $80 million of long-term debt in January 2005 and Alagascos $80 million issuance of long-term debt in November 2005. Positively impacting interest expense was Alagascos redemption of $56.7 million, $18 million and $30 million of long-term debt in December 2005, August 2005 and April 2004, respectively. Interest expense in 2004 increased $0.5 million largely due to a full years interest on $50 million of long-term debt issued by Energen in October 2003 and increased short-term borrowings due to the acquisition of San Juan Basin coalbed methane properties in August 2004. The average daily outstanding balance under short-term credit facilities was $17.7 million in 2005. The average daily outstanding balance under short-term credit facilities was $92.6 million in 2004 as compared to $81.1 million in 2003.
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Income tax expense increased in the periods presented primarily due to higher pre-tax income. As of December 31, 2005, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $34.8 million.
Exposure to Natural Disaster
The Companys production properties and distribution system did not suffer significant damage from Hurricanes Katrina and Rita which occurred in the third quarter of 2005. Energen Resources experienced minimal loss of production and Alagasco had no significant supply disruptions as a result of these hurricanes. These events, however, highlight the potential for a period of production shut-in for Energen Resources resulting from a prolonged interruption of service in areas which have a concentration of fractionation plants and refineries through which a substantial portion of the Companys natural gas liquids and oil production flow. Alagascos customer base is geographically concentrated in central Alabama. Damage to Alagascos delivery infrastructure, Energen Resources production infrastructure or to third party facilities which serve Alagasco and/or Energen Resources due to a natural disaster or other event could result in significant adverse financial consequences to Alagasco and/or the Company.
FINANCIAL POSITION AND LIQUIDITY
The Companys net cash from operating activities totaled $335.1 million, $291.1 million and $243.1 million in 2005, 2004 and 2003, respectively. Operating cash flow in 2005, 2004 and 2003 benefited from higher realized commodity prices and production volumes at Energen Resources. During the periods presented, working capital needs at Alagasco were primarily affected by increased gas costs compared to the prior period and storage gas inventory. 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 2005, the Company made net investments of $400.7 million. Energen Resources invested $188.4 million in property acquisitions, $157.5 million for development costs including approximately $123 million to drill 294 gross development wells and $5.1 million for exploration. In December 2005, Energen Resources completed its purchase of oil properties located in the Permian Basin from a private company for a contract price of approximately $168 million. The acquisition added approximately 131 Bcfe of proved reserves and had an effective date of November 1, 2005. Energen Resources sold certain properties during 2005, resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $73.3 million and primarily represented system distribution expansion and support facilities. Cash used in investing activities totaled $453.4 million in 2004. Energen Resources invested $274.4 million in property acquisitions, $124.6 million for development costs including approximately $89 million to drill 288 gross development wells and $5 million for exploration. In August 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million adding approximately 245 Bcfe of proved reserves. Utility expenditures in 2004 totaled $58.2 million. During 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold certain properties during 2003, resulting in cash proceeds of $29.1 million. Utility expenditures in 2003 totaled $57.9 million.
During 2005, the Company added approximately 131 Bcfe of reserves from the Permian Basin acquisition. Energen Resources expects this acquisition to utilize approximately $9 million, net of development costs, of pretax cash flows in 2006. Over the five-year period ending December 31, 2010, the Company expects this acquisition to contribute approximately $14 million, net of development costs, to pretax cash flows. Also during 2005, Energen Resources added 90 Bcfe of reserves from discoveries and other additions, primarily the result of improved drilling technology that increased the number of available drilling locations for certain wells in the San Juan Basin as well as continued downspacing in the Permian Basin. Energen Resources added approximately 315 Bcfe and 236 Bcfe of reserves in 2004 and 2003, respectively.
In 2005, net cash provided from financing activities totaled $69.8 million. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Long-term debt was reduced by $84.8
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million including Alagascos redemption of $18 million in Medium-Term Notes maturing June 27,
2007 to July 5, 2022 in August 2005 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 in December 2005. The Company provided $164.6 million from financing activities in 2004. Energen issued $100 million of
Floating Rate Senior Notes in November 2004. Long-term debt was reduced by $40.1 million in 2004, including $30 million of Medium-Term Notes called by Alagasco in April 2004. In 2003, net cash used in financing activities totaled $55.4 million. In
July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration which generated net proceeds of $32.1 million. Energen issued $50 million of long-term debt in October
2003. Long-term debt was reduced by $23 million for current maturities in 2003. 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
Capital Expenditures
Oil and Gas Operations: Energen Resources spent a total of $924.3 million for capital projects during the years ended December 31, 2005, 2004 and 2003. Property acquisition expenditures totaled $503.3 million, development activities totaled $403.9 million, and exploratory expenditures totaled $10.5 million.
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | ||||||
Capital and exploration expenditures for: |
|||||||||
Property acquisitions |
$ | 188,403 | $ | 274,400 | $ | 40,486 | |||
Development |
157,458 | 124,588 | 121,889 | ||||||
Exploration |
5,065 | 5,036 | 397 | ||||||
Other |
3,037 | 1,988 | 1,548 | ||||||
Total |
353,963 | 406,012 | 164,320 | ||||||
Less exploration expenditures charged to income |
251 | 2,076 | 982 | ||||||
Net capital expenditures |
$ | 353,712 | $ | 403,936 | $ | 163,338 | |||
Natural Gas Distribution: During the years ended December 31, 2005, 2004 and 2003, Alagasco invested $189.4 million for capital projects: $134.1 million for normal expansion, replacements and support of its distribution system and $55.3 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems.
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 of producing properties with development potential while maintaining the strength of the Companys utility foundation. For the five calendar years ended December 31, 2005, Energens EPS grew at an average compound rate of 19.8 percent a year. Over the next five years, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year.
Over the five-year planning period ending December 31, 2010, Energen Resources plans to spend approximately $372 million for development of existing properties and $38 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $271 million on development of previously identified proved undeveloped reserves and incurring approximately $29 million in exploratory exposure. In 2006, Energen Resources plans to invest approximately $153 million in capital expenditures primarily for development and exploratory activities. Included in this $153 million is approximately $87 million for the development of previously identified proved undeveloped reserves. Approximately $6 million is estimated for
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exploratory exposure in 2006. Capital investment at Energen Resources in 2007 is expected to approximate $87 million for development and exploration. Of this $87 million, development of previously identified proved undeveloped reserves is estimated to be $71 million and exploratory exposure is estimated to be $6 million.
Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energens acquisition criteria which could result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years in addition to the estimates given above, for property acquisitions that meet Energens acquisition criteria. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering exploration activities which complement its core expertise and meet its investment requirements. To finance Energen Resources investment program, the Company expects primarily to utilize its short-term credit facilities to supplement internally generated cash flow. The Company may also periodically issue long-term debt and equity to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $320 million to help finance its growth plans and operating needs. Energen Resources continued ability to invest in property acquisitions is subject to market conditions and industry trends.
Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term.
For the 2005-2006 winter heating season, Alagasco has hedged or intends to use storage for its estimated, weather-normalized, core-market gas supply purchases. The Companys efforts to minimize commodity price volatility through hedging is reflected in Alagascos current rates. Alagascos rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Companys cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses. Sustained high prices may decrease Alagascos customer base and could result in a decline of per customer use and number of customers. The utility will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices. In December 2005, the APSC requested Alagasco and the other major natural gas utility under its jurisdiction to refrain from additional rate increases through the winter heating season ending March 31, 2006, citing concerns over the potential negative impact on customers from the high natural gas prices being experienced across the country following hurricanes Katrina and Rita. Alagasco agreed to comply with the APSCs request and subsequently reduced rates in response to moderating gas prices.
Alagasco maintains an investment in storage gas that is expected to average approximately $67 million in 2006 but may vary depending upon the price of natural gas. During 2006 and 2007, Alagasco plans to invest approximately $62 million and $65 million, respectively, in utility capital expenditures for normal distribution and support systems. Over the Companys five-year planning period ending December 31, 2010, Alagasco anticipates capital investments of approximately $322 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. In November 2005, Alagasco issued an additional $80 million of long-term debt largely to refinance $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively.
Access to capital is an integral part of the Companys business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets,
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continued access could be adversely affected by future economic and business conditions or credit rating downgrades. Energen and Alagascos corporate credit ratings are currently rated BBB+ with a stable outlook by Standard & Poors. Moodys Investors Service has currently rated Energen as Baa 2 senior unsecured and Alagasco as A1 senior unsecured.
Dividends
Energen expects to pay annual cash dividends of $0.44 per share on the Companys common stock in 2006. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.
On April 27, 2005, Energens shareholders approved a
2-for-1 split of the Companys common stock. The split was effected in the form of a 100 percent stock dividend and was effective on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital
Contractual Cash Obligations and Other Commitments
In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Companys significant contractual cash obligations, other than hedging contracts, as of December 31, 2005.
Payments Due before December 31, | |||||||||||||||
(in thousands) |
Total | 2006 | 2007-2008 | 2009-2010 |
2011 and Thereafter |
||||||||||
Short-term debt |
$ | 153,000 | $ | 153,000 | $ | | $ | | $ | | |||||
Long-term debt (1) |
699,654 | 15,000 | 110,000 | 150,000 | 424,654 | ||||||||||
Interest payments on debt (2) |
545,177 | 44,897 | 81,352 | 76,178 | 342,750 | ||||||||||
Purchase obligations (3) |
243,049 | 48,066 | 95,542 | 70,224 | 29,217 | ||||||||||
Capital lease obligations |
| | | | | ||||||||||
Operating leases |
49,685 | 3,839 | 6,817 | 6,313 | 32,716 | ||||||||||
Total contractual cash obligations |
$ | 1,690,565 | $ | 264,802 | $ | 293,711 | $ | 302,715 | $ | 829,337 | |||||
(1) |
Long-term cash obligations include $1.4 million of unamortized debt discounts as of December 31, 2005. |
(2) |
Includes interest on fixed rate debt and an estimate of adjustable rate debt. The adjustable rate interest is calculated based on the indexed rate in effect at December 31, 2005. |
(3) |
Certain of the Companys long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of $243 million through October 2015. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 166.1 Bcf through April 2015. |
Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.
The Company has two defined non-contributory pension plans and provides certain post-retirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2006 for the pension plans and does not currently plan to make discretionary contributions. The Company may reevaluate discretionary payments to its pension plans in the fourth quarter of 2006 based on the outcome of the September 30, 2006, measurement of pension obligations. Additionally, the Company expects to make discretionary payments of $1.4 million to post-retirement benefit program assets during 2006.
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OUTLOOK
Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2006 and 2007 as outlined above. Production in 2006 is estimated to reach approximately 92 Bcfe, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2005. In 2007, production is estimated to be approximately 89 Bcfe, including approximately 88 Bcfe produced from proved reserves currently owned. Production estimates above do not include amounts for potential future acquisitions.
In the event Energen Resources is unable to fully invest its 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, worldwide political developments and 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.
Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Companys overall exposure to credit risk, either positively or negatively, in that the Companys oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers account for approximately 29 percent, 19 percent and 14 percent, respectively, of Energen Resources estimated 2006 production. Energen Resources other purchasers each bought less than 8 percent of production.
Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may 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. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where these arrangements exist, the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Companys credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade. At December 31, 2005, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of December 31, 2005. The two largest counterparties represented approximately 48 percent and 22 percent of Energen Resources fair value of derivatives. The Company believes the creditworthiness of these counterparties is satisfactory. Energen Resources other counterparties each represented less than 14 percent of the fair value of derivatives. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge this production more than two years forward. Production may be hedged for a longer period immediately following an acquisition in order to protect targeted returns.
Energen Resources entered into the following transactions for 2006 and subsequent years:
Production Period |
Total Hedged Volumes |
Average Contract Price |
Description |
||||
Natural Gas |
|||||||
2006 |
16.3 Bcf | $ | 8.08 Mcf | NYMEX Swaps | |||
21.9 Bcf | $ | 6.48 Mcf | Basin Specific Swaps | ||||
2007 |
3.0 Bcf | $ | 9.72 Mcf | Basin Specific Swaps | |||
*9.0 Bcf | $ | 7.46 Mcf | Basin Specific Swaps | ||||
*5.0 Bcf | $ | 9.34 Mcf | NYMEX Swaps | ||||
Oil | |||||||
2006 |
2,844 MBbl | $ | 52.88 Bbl | NYMEX Swaps | |||
2007 |
600 MBbl | $ | 59.65 Bbl | NYMEX Swaps | |||
*600 MBbl | $ | 67.05 Bbl | NYMEX Swaps | ||||
2008 |
900 MBbl | $ | 57.71 Bbl | NYMEX Swaps | |||
2009 |
900 MBbl | $ | 56.25 Bbl | NYMEX Swaps | |||
Oil Basis Differential |
|||||||
2006 |
1,915 MBbl | ** | Basis Swaps | ||||
2007 |
*600 MBbl | ** | Basis Swaps | ||||
Natural Gas Liquids | |||||||
2006 |
30.2 MMGal | $ | 0.56 Gal | Liquids Swaps | |||
2007 |
*10.1 MMGal | $ | 0.80 Gal | Liquids Swaps |
* |
Contracts entered into subsequent to December 31, 2005 |
** |
Average contract prices not meaningful due to the varying nature of each contract |
29
The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids 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 December 31, 2005, the Company estimated that a 10 percent increase or decrease in the commodities prices would have resulted in a $73.2 million change 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. 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 impact of related taxes on actual cash prices.
Natural Gas Distribution: The extension of RSE in June 2002 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through January 1, 2008. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operations. Alagascos rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, Regulatory Matters, in the Notes to Financial Statements, the utilitys CCM is based in part on the number of customers and the rate of inflation. Continued low inflation, significantly higher gas prices resulting in increased bad debt expense and/or the lack of customer growth could impact the utilitys ability to manage its O&M expense per customer sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equity lower than the allowed range of return. 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. The utility continues to rely on rate flexibility to effectively prevent bypass of its distribution system.
As required by SFAS No. 133, Alagasco recognizes all derivatives at fair value 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 compliance with Alagascos APSC-approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71. At December 31, 2005, Alagasco recorded a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives. The gains or losses related to these derivative contracts, as adjusted for any changes in the fair value, will be recognized in the GSA during the first quarter of 2006.
Forward-Looking Statements: 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 Companys forward-looking statements do not reflect the impact of possible or pending acquisition, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.
30
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, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.
Third Party Facilities: The forward looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.
Energen Resources Production: 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 reserve 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.
Energen Resources Hedging: Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Companys financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Companys financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps and fixed price contracts. A substantial failure to meet sales volume targets whether caused by miscalculations, weather events, natural disaster, accident, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources position.
Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagascos risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagascos actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagascos position.
Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagascos, Energen Resources and/or the Companys financial position, results of operations and cash flows.
31
Alagasco Service Territory: Alagascos utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R), which requires a fair value base method of accounting using pricing models that reflect the specific economics of a companys transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. Although, the Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R, it does not anticipate that the adoption of SFAS No. 123R will have a material impact on the financial condition or results of operations of the Company. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant.
During April 2005, the FASB issued FSP No. 19-1, Accounting for Suspended Well Costs, which allows exploratory wells to be capitalized when the well has a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This interpretation was effective for the first reporting period beginning after April 4, 2005. The Company has adopted this standard and has no exploratory wells with capitalized costs that exceed more than one year.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 (Accounting Changes) and FASB Statement No. 3 (Reporting Accounting Changes in Interim Financial Statements). Opinion No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods financial statements of changes in accounting principle, unless it is impracticable. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item with respect to market risk is set forth in Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations under the heading Outlook and in Note 8, Financial Instruments and Risk Management, in the Notes to Financial Statements.
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.
33
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Energen Corporation:
We have completed an integrated audit of Energen Corporations 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 Companys 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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.
Internal control over financial reporting
Also, in our opinion, managements assessment, included in Managements Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Companys management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on managements assessment and on the effectiveness of the Companys internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating managements assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
34
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 15, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 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 Companys 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 the standards of the Public Company Oversight Board (United States). Those standards 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
March 15, 2006
35
CONSOLIDATED STATEMENTS OF INCOME
Energen Corporation
Years ended December 31, (in thousands, except share data) |
2005 | 2004 | 2003 | |||||||||
Operating Revenues |
||||||||||||
Oil and gas operations |
$ | 527,694 | $ | 410,117 | $ | 352,532 | ||||||
Natural gas distribution |
600,700 | 526,740 | 489,099 | |||||||||
Total operating revenues |
1,128,394 | 936,857 | 841,631 | |||||||||
Operating Expenses |
||||||||||||
Cost of gas |
315,622 | 259,889 | 233,823 | |||||||||
Operations and maintenance |
268,727 | 234,150 | 208,132 | |||||||||
Depreciation, depletion and amortization |
131,691 | 120,777 | 116,666 | |||||||||
Taxes, other than income taxes |
93,983 | 74,933 | 63,498 | |||||||||
Accretion expense |
2,647 | 2,265 | 1,890 | |||||||||
Total operating expenses |
812,670 | 692,014 | 624,009 | |||||||||
Operating Income |
315,724 | 244,843 | 217,622 | |||||||||
Other Income (Expense) |
||||||||||||
Interest expense |
(46,800 | ) | (42,743 | ) | (42,262 | ) | ||||||
Other income |
2,163 | 2,945 | 8,744 | |||||||||
Other expense |
(710 | ) | (2,215 | ) | (9,977 | ) | ||||||
Total other expense |
(45,347 | ) | (42,013 | ) | (43,495 | ) | ||||||
Income From Continuing Operations Before Income Taxes |
270,377 | 202,830 | 174,127 | |||||||||
Income tax expense |
97,491 | 75,525 | 64,023 | |||||||||
Income From Continuing Operations |
172,886 | 127,305 | 110,104 | |||||||||
Discontinued Operations, Net of Taxes |
||||||||||||
Income (loss) from discontinued operations |
(6 | ) | 163 | 1,134 | ||||||||
Gain (loss) on disposal of discontinued operations |
132 | (5 | ) | (584 | ) | |||||||
Income From Discontinued Operations |
126 | 158 | 550 | |||||||||
Net Income |
$ | 173,012 | $ | 127,463 | $ | 110,654 | ||||||
Diluted Earnings Per Average Common Share* |
||||||||||||
Continuing operations |
$ | 2.35 | $ | 1.74 | $ | 1.54 | ||||||
Discontinued operations |
| | 0.01 | |||||||||
Net Income |
$ | 2.35 | $ | 1.74 | $ | 1.55 | ||||||
Basic Earnings Per Average Common Share* |
||||||||||||
Continuing operations |
$ | 2.37 | $ | 1.75 | $ | 1.55 | ||||||
Discontinued operations |
| 0.01 | 0.01 | |||||||||
Net Income |
$ | 2.37 | $ | 1.76 | $ | 1.56 | ||||||
Diluted Average Common Shares Outstanding* |
73,714,602 | 73,117,253 | 71,433,752 | |||||||||
Basic Average Common Shares Outstanding* |
73,051,903 | 72,546,512 | 70,868,972 | |||||||||
* |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
The accompanying Notes to Financial Statements are an integral part of these statements.
36
Energen Corporation
(in thousands) |
December 31,
2005 |
December 31,
2004 |
||||
ASSETS |
||||||
Current Assets |
||||||
Cash and cash equivalents |
$ | 8,714 | $ | 4,489 | ||
Accounts receivable, net of allowance for doubtful accounts of $11,573 and $10,472 at December 31, 2005 and 2004, respectively |
285,765 | 217,360 | ||||
Inventories, at average cost |
||||||
Storage gas inventory |
71,179 | 51,093 | ||||
Materials and supplies |
7,926 | 7,843 | ||||
Liquified natural gas in storage |
3,795 | 3,688 | ||||
Regulatory asset |
6,633 | | ||||
Deferred income taxes |
72,113 | 36,285 | ||||
Prepayments and other |
22,366 | 29,150 | ||||
Total current assets |
478,491 | 349,908 | ||||
Property, Plant and Equipment |
||||||
Oil and gas properties, successful efforts method |
1,930,291 | 1,591,119 | ||||
Less accumulated depreciation, depletion and amortization |
466,643 | 381,734 | ||||
Oil and gas properties, net |
1,463,648 | 1,209,385 | ||||
Utility plant |
999,011 | 941,862 | ||||
Less accumulated depreciation |
401,232 | 373,589 | ||||
Utility plant, net |
597,779 | 568,273 | ||||
Other property, net |
6,584 | 5,401 | ||||
Total property, plant and equipment, net |
2,068,011 | 1,783,059 | ||||
Other Assets |
||||||
Regulatory asset |
33,436 | 19,650 | ||||
Deferred charges and other |
38,288 | 29,122 | ||||
Total other assets |
71,724 | 48,772 | ||||
TOTAL ASSETS |
$ | 2,618,226 | $ | 2,181,739 | ||
The accompanying Notes to Financial Statements are an integral part of these statements.
37
CONSOLIDATED BALANCE SHEETS
Energen Corporation
(in thousands, except share data) |
December 31,
2005 |
December 31,
2004 |
||||||
LIABILITIES AND SHAREHOLDERS EQUITY |
||||||||
Current Liabilities |
||||||||
Long-term debt due within one year |
$ | 15,000 | $ | 10,000 | ||||
Notes payable to banks |
153,000 | 135,000 | ||||||
Accounts payable |
306,618 | 159,871 | ||||||
Accrued taxes |
44,324 | 34,541 | ||||||
Customers deposits |
20,767 | 19,549 | ||||||
Amounts due customers |
6,181 | 10,363 | ||||||
Accrued wages and benefits |
33,634 | 31,610 | ||||||
Regulatory liability |
53,496 | 47,060 | ||||||
Other |
55,289 | 50,624 | ||||||
Total current liabilities |
688,309 | 498,618 | ||||||
Long-term debt |
683,236 | 612,891 | ||||||
Deferred Credits and Other Liabilities |
||||||||
Asset retirement obligation |
50,270 | 34,841 | ||||||
Accrued benefit liability |
15,739 | 14,216 | ||||||
Regulatory liability |
119,808 | 111,928 | ||||||
Deferred income taxes |
148,040 | 95,417 | ||||||
Other |
20,146 | 10,162 | ||||||
Total deferred credits and other liabilities |
354,003 | 266,564 | ||||||
Commitments and Contingencies |
||||||||
Shareholders Equity Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized |
| | ||||||
Common shareholders equity* |
||||||||
Common stock, $0.01 par value; 150,000,000 shares authorized, 73,493,337 shares outstanding at December 31, 2005, and 73,165,958 shares outstanding at December 31, 2004 |
735 | 732 | ||||||
Premium on capital stock |
394,861 | 380,965 | ||||||
Capital surplus |
2,802 | 2,802 | ||||||
Retained earnings |
603,314 | 459,626 | ||||||
Accumulated other comprehensive loss, net of tax |
||||||||
Unrealized loss on hedges |
(92,112 | ) | (25,466 | ) | ||||
Minimum pension liability |
(13,707 | ) | (11,864 | ) | ||||
Deferred compensation on restricted stock |
(2,123 | ) | (2,675 | ) | ||||
Deferred compensation plan |
11,907 | 28,919 | ||||||
Treasury stock, at cost*; 1,066,935 shares and 1,000,952 shares at December 31, 2005 and 2004, respectively |
(12,999 | ) | (29,373 | ) | ||||
Total shareholders equity |
892,678 | 803,666 | ||||||
TOTAL LIABILITIES AND SHAREHOLDERS EQUITY |
$ | 2,618,226 | $ | 2,181,739 | ||||
* |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
The accompanying Notes to Financial Statements are an integral part of these statements.
38
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
Energen Corporation
Common Stock |
Accumulated
Other
|
||||||||||||||||||||||||||||||||||
(in thousands, except share data) |
Number of
Shares |
Par Value |
Premium on
Capital Stock |
Capital
Surplus |
Retained
Earnings |
Deferred
Compensation Restricted Stock |
Deferred
Compensation Plan |
Treasury
Stock |
Total
Shareholders
|
||||||||||||||||||||||||||
BALANCE DECEMBER 31, 2002 |
69,490,954 | $ | 695 | $ | 320,078 | $ | 2,802 | $ | 274,900 | $ | (14,811 | ) | $ | (770 | ) | $ | 10,348 | $ | (10,432 | ) | $ | 582,810 | |||||||||||||
Net income |
110,654 | 110,654 | |||||||||||||||||||||||||||||||||
Other comprehensive income (loss): |
|||||||||||||||||||||||||||||||||||
Current period change in fair value of derivative instruments, net of tax of ($29,019) |
(45,388 | ) | (45,388 | ) | |||||||||||||||||||||||||||||||
Reclassification adjustment, net of tax of $21,830 |
34,145 | 34,145 | |||||||||||||||||||||||||||||||||
Minimum pension liability, net of tax of ($2,445) |
(4,541 | ) | (4,541 | ) | |||||||||||||||||||||||||||||||
Comprehensive income |
94,870 | ||||||||||||||||||||||||||||||||||
Purchase of treasury shares |
(1,046 | ) | (1,046 | ) | |||||||||||||||||||||||||||||||
Shares issued for: |
|||||||||||||||||||||||||||||||||||
Stock offerings |
2,000,000 | 20 | 32,111 | 32,131 | |||||||||||||||||||||||||||||||
Dividend reinvestment plan |
107,980 | 1 | 1,865 | 491 | 2,357 | ||||||||||||||||||||||||||||||
Employee benefit plans |
848,128 | 8 | 12,029 | 594 | 12,631 | ||||||||||||||||||||||||||||||
Deferred compensation obligation |
6,715 | (6,715 | ) | | |||||||||||||||||||||||||||||||
Issuance of restricted stock |
(1,564 | ) | (1,564 | ) | |||||||||||||||||||||||||||||||
Amortization of restricted stock |
1,076 | 1,076 | |||||||||||||||||||||||||||||||||
Stock based compensation |
270 | 270 | |||||||||||||||||||||||||||||||||
Tax benefit from employee stock plans |
1,416 | 1,416 | |||||||||||||||||||||||||||||||||
Cash dividends - $0.365 per share |
(25,919 | ) | (25,919 | ) | |||||||||||||||||||||||||||||||
BALANCE DECEMBER 31, 2003 |
72,447,062 | 724 | 367,769 | 2,802 | 359,635 | (30,595 | ) | (1,258 | ) | 17,063 | (17,108 | ) | 699,032 | ||||||||||||||||||||||
Net income |
127,463 | 127,463 | |||||||||||||||||||||||||||||||||
Other comprehensive income (loss): |
|||||||||||||||||||||||||||||||||||
Current period change in fair value of derivative instruments, net of tax of ($34,012) |
(56,430 | ) | (56,430 | ) | |||||||||||||||||||||||||||||||
Reclassification adjustment, net of tax of $32,286 |
52,678 | 52,678 | |||||||||||||||||||||||||||||||||
Minimum pension liability, net of tax of ($1,608) |
(2,983 | ) | (2,983 | ) | |||||||||||||||||||||||||||||||
Comprehensive income |
120,728 | ||||||||||||||||||||||||||||||||||
Purchase of treasury shares |
(836 | ) | (836 | ) | |||||||||||||||||||||||||||||||
Shares issued for: |
|||||||||||||||||||||||||||||||||||
Dividend reinvestment plan |
2,550 | | 53 | | 53 | ||||||||||||||||||||||||||||||
Employee benefit plans |
716,346 | 8 | 9,112 | 427 | 9,547 | ||||||||||||||||||||||||||||||
Deferred compensation obligation |
11,856 | (11,856 | ) | | |||||||||||||||||||||||||||||||
Issuance of restricted stock |
(2,807 | ) | (2,807 | ) | |||||||||||||||||||||||||||||||
Amortization of restricted stock |
1,390 | 1,390 | |||||||||||||||||||||||||||||||||
Stock based compensation |
465 | 465 | |||||||||||||||||||||||||||||||||
Tax benefit from employee stock plans |
1,275 | 1,275 | |||||||||||||||||||||||||||||||||
Long-range performance plan |
2,291 | 2,291 | |||||||||||||||||||||||||||||||||
Cash dividends - $0.3775 per share |
(27,472 | ) | (27,472 | ) | |||||||||||||||||||||||||||||||
BALANCE DECEMBER 31, 2004 |
73,165,958 | 732 | 380,965 | 2,802 | 459,626 | (37,330 | ) | (2,675 | ) | 28,919 | (29,373 | ) | 803,666 | ||||||||||||||||||||||
Net income |
173,012 | 173,012 | |||||||||||||||||||||||||||||||||
Other comprehensive income (loss): |
|||||||||||||||||||||||||||||||||||
Current period change in fair value of derivative instruments, net of tax of ($100,484) |
(163,947 | ) | (163,947 | ) | |||||||||||||||||||||||||||||||
Reclassification adjustment, net of tax of $59,636 |
97,301 | 97,301 | |||||||||||||||||||||||||||||||||
Minimum pension liability, net of tax of ($990) |
(1,843 | ) | (1,843 | ) | |||||||||||||||||||||||||||||||
Comprehensive income |
104,523 | ||||||||||||||||||||||||||||||||||
Purchase of treasury shares |
(2,459 | ) | (2,459 | ) | |||||||||||||||||||||||||||||||
Shares issued for: |
|||||||||||||||||||||||||||||||||||
Employee benefit plans |
327,379 | 3 | 8,958 | 1,821 | 10,782 | ||||||||||||||||||||||||||||||
Deferred compensation obligation |
(17,012 | ) | 17,012 | | |||||||||||||||||||||||||||||||
Issuance of restricted stock |
(1,249 | ) | (1,249 | ) | |||||||||||||||||||||||||||||||
Amortization of restricted stock |
1,801 | 1,801 | |||||||||||||||||||||||||||||||||
Stock based compensation |
465 | 465 | |||||||||||||||||||||||||||||||||
Tax benefit from employee stock plans |
2,487 | 2,487 | |||||||||||||||||||||||||||||||||
Long-range performance plan |
1,986 | 1,986 | |||||||||||||||||||||||||||||||||
Cash dividends - $0.40 per share |
(29,324 | ) | (29,324 | ) | |||||||||||||||||||||||||||||||
BALANCE DECEMBER 31, 2005 |
73,493,337 | $ | 735 | $ | 394,861 | $ | 2,802 | $ | 603,314 | $ | (105,819 | ) | $ | (2,123 | ) | $ | 11,907 | $ | (12,999 | ) | $ | 892,678 | |||||||||||||
* |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
The accompanying Notes to Financial Statements are an integral part of these statements.
39
CONSOLIDATED STATEMENTS OF CASH FLOWS
Energen Corporation
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | |||||||||
Operating Activities |
||||||||||||
Net income |
$ | 173,012 | $ | 127,463 | $ | 110,654 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
Depreciation, depletion and amortization |
131,719 | 120,960 | 117,785 | |||||||||
Deferred income taxes |
58,608 | 67,423 | 54,632 | |||||||||
Deferred investment tax credits |
| (308 | ) | (448 | ) | |||||||
Change in derivative fair value |
2,328 | 212 | 735 | |||||||||
Gain on sale of assets |
(1,928 | ) | (135 | ) | (9,987 | ) | ||||||
Loss on properties held for sale |
| | 10,404 | |||||||||
Other, net |
(5,912 | ) | (11,908 | ) | (11,084 | ) | ||||||
Net change in: |
||||||||||||
Accounts receivable, net |
(70,944 | ) | (39,645 | ) | (24,811 | ) | ||||||
Inventories |
(20,276 | ) | (10,818 | ) | (16,132 | ) | ||||||
Accounts payable |
39,330 | 19,536 | 12,860 | |||||||||
Amounts due customers |
12,890 | (1,166 | ) | 4,052 | ||||||||
Other current assets and liabilities |
16,297 | 19,518 | (5,533 | ) | ||||||||
Net cash provided by operating activities |
335,124 | 291,132 | 243,127 | |||||||||
Investing Activities |
||||||||||||
Additions to property, plant and equipment |
(230,715 | ) | (177,705 | ) | (179,107 | ) | ||||||
Acquisitions, net of cash acquired |
(179,268 | ) | (274,400 | ) | (40,486 | ) | ||||||
Proceeds from sale of assets |
10,832 | 461 | 29,149 | |||||||||
Other, net |
(1,573 | ) | (1,770 | ) | 30 | |||||||
Net cash used in investing activities |
(400,724 | ) | (453,414 | ) | (190,414 | ) | ||||||
Financing Activities |
||||||||||||
Payment of dividends on common stock |
(29,324 | ) | (27,472 | ) | (25,919 | ) | ||||||
Issuance of common stock |
10,782 | 9,600 | 47,119 | |||||||||
Purchase of treasury stock |
(2,459 | ) | (836 | ) | (1,046 | ) | ||||||
Reduction of long-term debt |
(84,796 | ) | (40,083 | ) | (23,000 | ) | ||||||
Proceeds from issuance of long-term debt |
160,000 | 100,000 | 49,778 | |||||||||
Debt issuance costs |
(2,378 | ) | (565 | ) | (322 | ) | ||||||
Net change in short-term debt |
18,000 | 124,000 | (102,000 | ) | ||||||||
Net cash provided by (used in) financing activities |
69,825 | 164,644 | (55,390 | ) | ||||||||
Net change in cash and cash equivalents |
4,225 | 2,362 | (2,677 | ) | ||||||||
Cash and cash equivalents at beginning of period |
4,489 | 2,127 | 4,804 | |||||||||
Cash and cash equivalents at end of period |
$ | 8,714 | $ | 4,489 | $ | 2,127 | ||||||
The accompanying Notes to Financial Statements are an integral part of these statements.
40
Alabama Gas Corporation
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | |||||||||
Operating Revenues |
$ | 600,700 | $ | 526,740 | $ | 489,099 | ||||||
Operating Expenses |
||||||||||||
Cost of gas |
318,269 | 261,800 | 236,037 | |||||||||
Operations and maintenance |
126,041 | 121,896 | 114,078 | |||||||||
Depreciation |
42,351 | 39,881 | 37,171 | |||||||||
Income taxes |
||||||||||||
Current |
20,556 | 9,690 | 6,577 | |||||||||
Deferred |
1,804 | 10,321 | 13,546 | |||||||||
Deferred investment tax credits |
| (308 | ) | (448 | ) | |||||||
Taxes, other than income taxes |
41,117 | 36,964 | 34,965 | |||||||||
Total operating expenses |
550,138 | 480,244 | 441,926 | |||||||||
Operating Income |
50,562 | 46,496 | 47,173 | |||||||||
Other Income (Expense) |
||||||||||||
Allowance for funds used during construction |
792 | 1,247 | 948 | |||||||||
Other income |
1,371 | 1,979 | 4,132 | |||||||||
Other expense |
(701 | ) | (2,195 | ) | (5,269 | ) | ||||||
Total other income (expense) |
1,462 | 1,031 | (189 | ) | ||||||||
Interest Charges |
||||||||||||
Interest on long-term debt |
13,752 | 10,672 | 12,815 | |||||||||
Other interest charges |
1,308 | 3,065 | 1,152 | |||||||||
Total interest charges |
15,060 | 13,737 | 13,967 | |||||||||
Net Income |
$ | 36,964 | $ | 33,790 | $ | 33,017 | ||||||
The accompanying Notes to Financial Statements are an integral part of these statements.
41
Alabama Gas Corporation
(in thousands) |
December 31,
2005 |
December 31,
2004 |
||||||
ASSETS |
||||||||
Property, Plant and Equipment |
||||||||
Utility plant |
$ | 999,011 | $ | 941,862 | ||||
Less accumulated depreciation |
401,232 | 373,589 | ||||||
Utility plant, net |
597,779 | 568,273 | ||||||
Other property, net |
169 | 325 | ||||||
Current Assets |
||||||||
Cash |
7,169 | 3,467 | ||||||
Accounts receivable |
||||||||
Gas |
194,447 | 142,736 | ||||||
Other |
7,524 | 11,952 | ||||||
Affiliated companies |
3,215 | 2,190 | ||||||
Allowance for doubtful accounts |
(10,800 | ) | (9,600 | ) | ||||
Inventories, at average cost |
||||||||
Storage gas inventory |
71,179 | 51,093 | ||||||
Materials and supplies |
4,144 | 4,281 | ||||||
Liquified natural gas in storage |
3,795 | 3,688 | ||||||
Regulatory asset |
6,633 | | ||||||
Deferred income taxes |
13,284 | 15,233 | ||||||
Prepayments and other |
11,203 | 21,901 | ||||||
Total current assets |
311,793 | 246,941 | ||||||
Other Assets |
||||||||
Regulatory asset |
33,436 | 19,650 | ||||||
Deferred charges and other |
6,857 | 4,558 | ||||||
Total other assets |
40,293 | 24,208 | ||||||
TOTAL ASSETS |
$ | 950,034 | $ | 839,747 | ||||
The accompanying Notes to Financial Statements are an integral part of these statements.
42
BALANCE SHEETS
Alabama Gas Corporation
(in thousands, except share data) |
December 31,
2005 |
December 31,
2004 |
||||
LIABILITIES AND CAPITALIZATION |
||||||
Capitalization |
||||||
Preferred stock, cumulative, $0.01 par value, 120,000 shares authorized |
$ | | $ | | ||
Common shareholders equity |
||||||
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares outstanding at December 31, 2005 and 2004, respectively |
20 | 20 | ||||
Premium on capital stock |
31,682 | 31,682 | ||||
Capital surplus |
2,802 | 2,802 | ||||
Retained earnings |
236,957 | 223,515 | ||||
Total common shareholders equity |
271,461 | 258,019 | ||||
Long-term debt |
209,654 | 129,450 | ||||
Total capitalization |
481,115 | 387,469 | ||||
Current Liabilities |
||||||
Long-term debt due within one year |
5,000 | 10,000 | ||||
Notes payable to banks |
55,000 | 82,000 | ||||
Accounts payable |
112,443 | 81,591 | ||||
Accrued taxes |
32,770 | 27,410 | ||||
Customers deposits |
20,767 | 19,549 | ||||
Amounts due customers |
6,181 | 10,363 | ||||
Accrued wages and benefits |
11,449 | 10,393 | ||||
Regulatory liability |
53,496 | 47,060 | ||||
Other |
8,694 | 9,237 | ||||
Total current liabilities |
305,800 | 297,603 | ||||
Deferred Credits and Other Liabilities |
||||||
Deferred income taxes |
39,949 | 40,070 | ||||
Regulatory liability |
119,808 | 111,928 | ||||
Customer advances for construction and other |
3,362 | 2,677 | ||||
Total deferred credits and other liabilities |
163,119 | 154,675 | ||||
Commitments and Contingencies |
||||||
TOTAL LIABILITIES AND CAPITALIZATION |
$ | 950,034 | $ | 839,747 | ||
The accompanying Notes to Financial Statements are an integral part of these statements.
43
STATEMENTS OF SHAREHOLDERS EQUITY
Alabama Gas Corporation
Common Stock |
Total
Shareholders
|
||||||||||||||||||
(in thousands, except share data) |
Number of Shares |
Par Value |
Premium on Capital Stock |
Capital Surplus |
Retained Earnings |
||||||||||||||
Balance December 31, 2002 |
1,972,052 | $ | 20 | $ | 31,682 | $ | 2,802 | $ | 182,852 | $ | 217,356 | ||||||||
Net income |
33,017 | 33,017 | |||||||||||||||||
Balance December 31, 2003 |
1,972,052 | 20 | 31,682 | 2,802 | 215,869 | 250,373 | |||||||||||||
Net income |
33,790 | 33,790 | |||||||||||||||||
Cash dividends |
(26,144 | ) | (26,144 | ) | |||||||||||||||
Balance December 31, 2004 |
1,972,052 | 20 | 31,682 | 2,802 | 223,515 | 258,019 | |||||||||||||
Net income |
36,964 | 36,964 | |||||||||||||||||
Cash dividends |
(23,522 | ) | (23,522 | ) | |||||||||||||||
Balance December 31, 2005 |
1,972,052 | $ | 20 | $ | 31,682 | $ | 2,802 | $ | 236,957 | $ | 271,461 | ||||||||
The accompanying Notes to Financial Statements are an integral part of these statements.
44
Alabama Gas Corporation
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | |||||||||
Operating Activities |
||||||||||||
Net income |
$ | 36,964 | $ | 33,790 | $ | 33,017 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
Depreciation and amortization |
42,351 | 39,881 | 37,171 | |||||||||
Deferred income taxes |
1,804 | 10,321 | 13,546 | |||||||||
Deferred investment tax credits |
| (308 | ) | (448 | ) | |||||||
Other, net |
(3,025 | ) | (8,968 | ) | (13,774 | ) | ||||||
Net change in: |
||||||||||||
Accounts receivable, net |
(48,623 | ) | (12,784 | ) | (15,923 | ) | ||||||
Inventories |
(20,056 | ) | (9,406 | ) | (17,268 | ) | ||||||
Accounts payable |
24,560 | 25,823 | 49 | |||||||||
Amounts due customers |
12,890 | (1,166 | ) | 4,052 | ||||||||
Other current assets and liabilities |
9,371 | 8,128 | (4,140 | ) | ||||||||
Net cash provided by operating activities |
56,236 | 85,311 | 36,282 | |||||||||
Investing Activities |
||||||||||||
Additions to property, plant and equipment |
(72,388 | ) | (56,922 | ) | (56,255 | ) | ||||||
Net advances to parent company |
(1,025 | ) | (39,480 | ) | 35,858 | |||||||
Other, net |
(1,551 | ) | (1,655 | ) | (263 | ) | ||||||
Net cash used in investing activities |
(74,964 | ) | (98,057 | ) | (20,660 | ) | ||||||
Financing Activities |
||||||||||||
Payment of dividends on common stock |
(23,522 | ) | (26,144 | ) | | |||||||
Reduction of long-term debt |
(84,796 | ) | (30,083 | ) | (15,000 | ) | ||||||
Proceeds from issuance of long-term debt |
160,000 | | | |||||||||
Debt issuance costs |
(2,252 | ) | | | ||||||||
Net change in short-term debt |
(27,000 | ) | 71,000 | (2,000 | ) | |||||||
Net cash provided (used) by financing activities |
22,430 | 14,773 | (17,000 | ) | ||||||||
Net change in cash and cash equivalents |
3,702 | 2,027 | (1,378 | ) | ||||||||
Cash and cash equivalents at beginning of period |
3,467 | 1,440 | 2,818 | |||||||||
Cash and cash equivalents at end of period |
$ | 7,169 | $ | 3,467 | $ | 1,440 | ||||||
The accompanying Notes to Financial Statements are an integral part of these statements.
45
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 Companys 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, gas and natural gas liquid 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. All development costs are capitalized. 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. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves. Gains and losses in the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for current and prior periods.
Operating Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a propertys over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2005 and 2004.
Derivative Commodity Instruments: Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may 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. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where these arrangements exist, the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Companys credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade.
46
Energen Resources applies Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended which 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 effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured 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 shareholders equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivatives change in fair value is recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 are recorded at fair value with gains or losses recognized in operating revenues in the period of change.
Additionally, the Company may also enter into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding NYMEX hedge, put options and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.
All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, 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 instruments effectiveness in hedging the exposure to the hedged transactions 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 has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.
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 is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets is charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. 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 the years ended December 31, 2005, 2004 and 2003.
Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost.
Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2005 and 2004.
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.
47
Derivative Commodity Instruments: On December 4, 2000, the APSC authorized Alagasco to engage in energy-risk management activities. Accordingly, Alagasco from time to time enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. 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 Gas Supply Adjustment (GSA) rider in accordance with Alagascos APSC approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71.
Taxes on revenues: Collections and payments of excise taxes are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | ||||||
Taxes on revenues |
$ | 30,899 | $ | 27,002 | $ | 25,218 | |||
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 between the financial statement basis and the tax basis of assets and liabilities 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. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.
E. | Accounts Receivable and Allowance for Doubtful Accounts |
Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Companys best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and reviews the allowance for doubtful accounts monthly. Account balances are charged off against the allowance when it is anticipated the receivable will not be recovered.
F. | Cash Equivalents |
The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents.
G. | Earnings Per Share |
The Companys 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 9).
H. | Stock-Based Compensation |
The Company adopted the fair value recognition provisions of SFAS No. 123 as amended, Accounting for Stock-Based Compensation, prospectively for all stock-based employee compensation effective January 1, 2003. Awards under the Companys plan vest over periods ranging from one to six years; therefore, the cost related to stock-based employee compensation included in the determination of net income is different than that which would have been recognized if the fair value method had been applied to all awards. The following table illustrates the effect on net income and diluted earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:
* |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
48
The Company used the Black-Scholes pricing model to calculate the fair values of the options awarded, which are included in the pro forma results above. Option awards are granted with an exercise price equal to the market price of the Companys stock on the date of grant. For purposes of this valuation the following assumptions were used to derive the fair values: a seven-year option life based on historical experience; an annualized volatility rate, based on historical volatility, of 32.72 percent and 34.67 percent for the years ended December 31, 2004 and 2003, respectively; a risk-free interest rate of 3.64 percent and 2.36 percent for the years ended December 31, 2004 and 2003, respectively; and a dividend yield of 1.81 percent on options without dividend equivalents for the year ended December 31, 2004. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted without dividend equivalents during the year ended December 31, 2004 was $7.11. The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $6.05. There were no options granted in the year ended December 31, 2005.
The 1997 Stock Incentive Plan provides for the grant of restricted stock and performance share awards. The Company values restricted stock grants based on the stock price at the date of grant. As of December 31, 2005, the performance share awards could be paid in cash or a combination of Company common stock or cash. The Company valued the performance awards to be paid in common stock based on the common stock price at the date of grant and the expected payout ratio at the end of each reporting period. The Company valued the performance awards to be paid in cash based on the Companys period-end stock price and the expected payout ratio at the end of each reporting period. Upon adoption of SFAS No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R), the Company will continue to value the restricted stock grants based on the stock price at the date of grant. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant.
The Company recognized all stock-based employee compensation expense over the stated vesting periods for each award. In the event of an employees retirement, the Company accelerated the recognition of expense for all eligible unvested awards. Upon the adoption of SFAS No. 123R, effective January 1, 2006, the Company will recognize the entire compensation expense for awards to retirement eligible employees in the period of grant. If this method of expense recognition had been applied during 2003 and 2004, the Company would have recognized approximately an additional $1.4 million and $1.2 million, respectively, of compensation expense related to the timing of recognition for retirement eligible employees. During 2005, compensation expense would have been reduced by approximately $0.8 million related to this timing of recognition for retirement eligible employees.
In the periods presented, the Company recognized forfeitures in the reporting period in which the forfeiture occurred. Upon the adoption of SFAS No. 123R, the Company will estimate forfeitures based on its historical experience. The forfeiture estimates will be updated periodically based on actual experience.
49
I. | Estimates |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. The major estimates and assumptions identified by management include, but are not limited to, estimates of physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that SFAS No. 71 will continue as the applicable accounting standard for the Companys regulated operations and estimates used in determining the Companys obligations under its employee pension plans and asset retirement obligations. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.
J. | Environmental Costs |
Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.
2. REGULATORY MATTERS
All of Alagascos utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagascos rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operations. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. Alagascos allowed range of return on equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. Under RSE the APSC conducts quarterly reviews to determine, based on Alagascos projections and year-to-date performance, whether Alagascos return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. As of September 30, 2005 and 2003, Alagasco had a $3.3 million and a $3 million, respectively, reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Alagasco did not have a reduction in rates related to the return on average equity for rate year ended 2004. A $15.8 million, $12.3 million and $11.2 million annual increase in revenues became effective December 1, 2005, 2004, and 2003, respectively. RSE limits the utilitys equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagascos 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. The increase in O&M expense per customer was above the index range for the rate years ended September 30, 2004 and 2003; as a result, the utility returned to customers $1.2 million pre-tax and $0.1 million pre-tax, respectively, through rate adjustments under the provisions of RSE. Alagascos O&M expense fell within the index range for the rate year ended September 30, 2005.
Alagasco calculates a temperature adjustment to customers monthly bills to substantially remove the effect of departures from normal temperatures on Alagascos earnings. Adjustments to customers bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential,
50
small commercial and small industrial customers. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Alagascos rate schedules for natural gas distribution charges contain a 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 rate year 1998 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 rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagascos return on average equity to fall below 13.15 percent. During the year ended December 31, 2004, Alagasco charged $0.3 million against the ESR related to extraordinary maintenance cost resulting from certain weather events within Alagascos service territory. 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. ESR balances of $3.7 million at December 31, 2005 and 2004, are 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 Alagascos rate-setting mechanism on a straight-line basis over approximately 23 years. At December 31, 2005 and 2004, the net acquisition adjustments were $10.4 million and $11.5 million,
3. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consisted of the following:
(in thousands) |
December 31, 2005 |
December 31, 2004 |
||||
Energen Corporation: |
||||||
Medium-term Notes, interest ranging from 6.95% to 8.09%, for notes redeemable September 25, 2006, to February 15, 2028 |
$ | 335,000 | $ | 335,000 | ||
5% Notes, redeemable October 1, 2013 |
50,000 | 50,000 | ||||
Floating Rate Senior Notes (4.69% at December 31, 2005), redeemable November 15, 2007 |
100,000 | 100,000 | ||||
Alabama Gas Corporation: |
||||||
Medium-term Notes, interest ranging from 7.34% to 7.97%, for notes redeemable September 20, 2006, to September 23, 2026 |
20,000 | 65,000 | ||||
6.25% Notes, redeemable September 1, 2016 |
| 39,725 | ||||
6.75% Notes, redeemable September 1, 2031 |
34,725 | 34,725 | ||||
5.20% Notes, redeemable January 15, 2020 |
40,000 | | ||||
5.70% Notes, redeemable January 15, 2035 |
39,929 | | ||||
5.368% Notes, redeemable December 1, 2015 |
80,000 | | ||||
Total |
699,654 | 624,450 | ||||
Less amounts due within one year |
15,000 | 10,000 | ||||
Less unamortized debt discount |
1,418 | 1,559 | ||||
Total |
$ | 683,236 | $ | 612,891 | ||
The aggregate maturities of Energens long-term debt for the next five years are as follows:
Years ending December 31, (in thousands) | |||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | |||||||
$ 15,000 | $ | 100,000 | $ | 10,000 | | $ | 150,000 |
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The aggregate maturities of Alagascos long-term debt for the next five years are as follows:
Years ending December 31, (in thousands) | ||||||||
2006 | 2007 | 2008 | 2009 | 2010 | ||||
$ 5,000 | | | | |
At December 31, 2005, the Company was not subject to restrictions on the payment of dividends. The Company is in compliance with the covenants under its various long-term debt agreements. Except as discussed below, debt covenants address routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Payments with respect to Alagascos 6.25 percent Notes and 6.75 percent Notes are insured by Ambac Assurance Corporation. Under the insurance agreement, Alagasco cannot dispose of distribution plant assets if, after such disposition, its distribution plant will be less than $200 million. Alagascos distribution plant exceeded $200 million at December 31, 2005. In addition, $300 million of the Companys outstanding debt is subject to a cross default provision under Energens Indenture dated September 1, 1996 with The Bank of New York as Trustee. In the event Alagasco or Energen Resources had a debt default of more than $10 million it would also be considered an event of default by Energen under the 1996 Indenture. All of the Companys debt is unsecured.
Energen and Alagasco had short-term credit lines and other credit facilities with various financial institutions totaling $320 million and $275 million, respectively, available as of December 31, 2005, for working capital needs. Alagasco has been authorized to borrow a maximum of $200 million of its available credit lines at any one time by the APSC. The Company is in compliance with the covenants under the various short-term loan agreements and except as discussed below, debt covenants address routine matters. One of the Companys credit facilities in the amount of $45 million includes a covenant that the ratio of consolidated debt to consolidated capitalization will not exceed 0.65:1. As of December 31, 2005, the Company was in compliance with this requirement. The following is a summary of information relating to notes payable to banks:
Energens total interest expense was $46,800,000, $42,743,000 and $42,262,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Total interest expense for Alagasco was $15,060,000, $13,737,000 and $13,967,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
4. INCOME TAXES
The components of Energens income taxes consisted of the following:
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | ||||||
Taxes estimated to be payable currently: |
|||||||||
Federal |
$ | 29,765 | $ | 7,261 | $ | 8,811 | |||
State |
6,078 | 1,149 | 1,282 | ||||||
Total current |
35,843 | 8,410 | 10,093 | ||||||
Taxes deferred: |
|||||||||
Federal |
59,685 | 58,956 | 47,805 | ||||||
State |
1,963 | 8,159 | 6,125 | ||||||
Total deferred |
61,648 | 67,115 | 53,930 | ||||||
Total income tax expense from continuing operations |
$ | 97,491 | $ | 75,525 | $ | 64,023 | |||
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For the year ended December 31, 2005, Energen recorded a current income tax expense of $3,117,000 and a deferred tax benefit of $3,040,000 related to income from discontinued operations. For the year ended December 31, 2004, Energen recorded a current income tax expense of $96,000 related to income from discontinued operations. For the year ended December 31, 2003, Energen recorded a current income tax expense of $100,000 and a deferred income tax expense of $254,000 related to income from discontinued operations.
The components of Alagascos income taxes consisted of the following:
Temporary differences and carryforwards which gave rise to Energens and Alagascos
Energen Corporation
(in thousands) |
December 31, 2005 |
December 31, 2004 |
|||||||||||||
Current | Noncurrent | Current | Noncurrent | ||||||||||||
Deferred tax assets: |
|||||||||||||||
Minimum tax credit |
$ | | $ | 34,786 | $ | | $ | 56,688 | |||||||
Pension and other costs |
| 8,693 | | 7,883 | |||||||||||
Unbilled and deferred revenue |
10,263 | | 10,017 | | |||||||||||
Enhanced stability reserve and other regulatory costs |
1,393 | | 1,888 | | |||||||||||
Allowance for doubtful accounts |
4,304 | | 3,880 | | |||||||||||
Insurance accruals |
3,552 | | 2,102 | | |||||||||||
Compensation accruals |
6,704 | | 6,408 | | |||||||||||
Inventories |
865 | | 775 | | |||||||||||
Other comprehensive income |
51,920 | 11,916 | 14,377 | 7,621 | |||||||||||
Other, net |
2,665 | 2,626 | 2,769 | 592 | |||||||||||
Total deferred tax assets |
81,666 | 58,021 | 42,216 | 72,784 | |||||||||||
Valuation allowance |
(1,596 | ) | (452 | ) | | | |||||||||
Total deferred tax assets |
80,070 | 57,569 | 42,216 | 72,784 | |||||||||||
Deferred tax liabilities: |
|||||||||||||||
Depreciation and basis differences |
| 196,916 | | 160,318 | |||||||||||
Pension and other costs |
7,164 | | 5,909 | | |||||||||||
Minimum pension liability |
| 8,693 | | 7,883 | |||||||||||
Other, net |
793 | | 22 | | |||||||||||
Total deferred tax liabilities |
7,957 | 205,609 | 5,931 | 168,201 | |||||||||||
Net deferred tax assets (liabilities) |
$ | 72,113 | $ | (148,040 | ) | $ | 36,285 | $ | (95,417 | ) | |||||
53
Alabama Gas Corporation
December 31, 2005 |
December 31, 2004 |
|||||||||||||
(in thousands) |
Current | Noncurrent | Current | Noncurrent | ||||||||||
Deferred tax assets: |
||||||||||||||
Pension and other costs |
$ | | $ | 8,693 | $ | | $ | 7,883 | ||||||
Unbilled and deferred revenue |
10,263 | | 10,017 | | ||||||||||
Enhanced stability reserve and other regulatory costs |
1,393 | | 1,888 | | ||||||||||
Allowance for doubtful accounts |
4,083 | | 3,630 | | ||||||||||
Insurance accruals |
2,305 | | 2,672 | | ||||||||||
Compensation accruals |
3,303 | | 3,779 | | ||||||||||
Inventories |
865 | | 775 | | ||||||||||
Other, net |
1,812 | 534 | 1,462 | 527 | ||||||||||
Total deferred tax assets |
24,024 | 9,227 | 24,223 | 8,410 | ||||||||||
Deferred tax liabilities: |
||||||||||||||
Depreciation and basis differences |
| 40,483 | | 40,597 | ||||||||||
Pension and other costs |
10,042 | | 8,970 | | ||||||||||
Minimum pension liability |
| 8,693 | | 7,883 | ||||||||||
Other, net |
698 | | 20 | | ||||||||||
Total deferred tax liabilities |
10,740 | 49,176 | 8,990 | 48,480 | ||||||||||
Net deferred tax assets (liabilities) |
$ | 13,284 | $ | (39,949 | ) | $ | 15,233 | $ | (40,070 | ) | ||||
The Company files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2005, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $34.8 million. The Company has a full valuation allowance recorded against a deferred tax asset of $2,048,000 arising from certain state net operating loss and charitable contribution carryforwards. The Company intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other 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 remaining deferred tax assets on the consolidated balance sheets.
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 percent to earnings before taxes from continuing operations 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 percent to earnings before taxes from continuing operations as illustrated below:
54
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 for Plan A. Plan B provides benefits based on years of service and flat dollar amounts. The Companys policy is to use the projected unit credit actuarial method for funding and financial reporting purposes. For its pension plans, Energen used a September 30 measurement date.
The status of the plans was as follows:
55
Weighted average rate assumptions used to determine the projected benefit obligations at the measurement date:
Plan A | ||||||
September 30, 2005 |
September 30, 2004 |
|||||
Discount rate |
5.50 | % | 5.75 | % | ||
Rate of compensation increase |
3.50 | % | 4.00 | % | ||
Plan B | ||||||
September 30, 2005 |
September 30, 2004 |
|||||
Discount rate |
5.50 | % | 5.75 | % | ||
The components of net pension expense were:
Net pension expense for Alagasco was $6,288,000, $5,175,000 and $4,370,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
56
Weighted average rate assumptions to determine net periodic benefit costs for the period ending:
Plan B | |||||||||
December 31,
2005 |
December 31,
2004 |
December 31, 2003 |
|||||||
Discount rate |
5.75 | % | 6.00 | % | 6.75 | % | |||
Expected long-term return on plan assets |
8.50 | % | 8.75 | % | 9.00 | % | |||
The Companys weighted-average pension plan asset allocations by asset category were as follows:
Plan A | |||||||||
Target |
December 31, 2005 |
December 31, 2004 |
|||||||
Asset category: |
|||||||||
Equity securities |
59 | % | 58 | % | 60 | % | |||
Debt securities |
31 | % | 29 | % | 30 | % | |||
Other |
10 | % | 13 | % | 10 | % | |||
Net periodic expense |
100 | % | 100 | % | 100 | % | |||
Plan B | |||||||||
Target |
December 31, 2005 |
December 31, 2004 |
|||||||
Asset category: |
|||||||||
Equity securities |
77 | % | 75 | % | 75 | % | |||
Debt securities |
23 | % | 22 | % | 21 | % | |||
Other |
| 3 | % | 4 | % | ||||
Net periodic expense |
100 | % | 100 | % | 100 | % | |||
Plan A and Plan B equity securities do not include the Companys common stock. The Company is not required to make pension contributions in 2006 and does not currently plan to make discretionary contributions to Plan A or Plan B assets. The Company may reevaluate discretionary contributions in the fourth quarter of 2006 based on the outcome of the September 30, 2006 measurement of pension obligations.
Pension plan benefit payments, which reflect expected future service, are anticipated to be paid as follows:
(in thousands) |
Plan A | Plan B | ||||
2006 |
$ | 9,429 | $ | 2,675 | ||
2007 |
$ | 9,021 | $ | 2,036 | ||
2008 |
$ | 9,786 | $ | 2,390 | ||
2009 |
$ | 10,084 | $ | 2,414 | ||
2010 |
$ | 12,168 | $ | 2,432 | ||
2011-2015 |
$ | 71,165 | $ | 11,913 | ||
Under SFAS No. 87, Employers Accounting for Pensions, Energen recognized an additional minimum pension liability for the accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004, of $31.5 million and $27.8 million, respectively, based on the Companys September 30 measurement date. Alagasco established a regulatory asset of $22.8 million and $19.7 million as of December 31, 2005 and 2004, respectively, for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with
57
SFAS No. 71. An intangible asset was recorded for the unrecognized prior service cost of $251,000 and $1.6 million at December 31, 2005 and 2004, respectively. The balance of $5.5 million and $4.3 million at December 31, 2005 and 2004, respectively, was recorded as a component of accumulated other comprehensive income, net of tax. The Company made discretionary contributions of $12.2 million in the fourth quarter of 2005 and $21.7 million in the fourth quarter of 2004.
The Company has supplemental retirement plans with certain key executives providing payments on retirement, termination, death or disability. Expense under these agreements for the years ended December 31, 2005, 2004 and 2003 was $2,899,000, $1,929,000, and $386,000, respectively. For its supplemental retirement plans, the Company used a September 30 measurement date. At September 30, 2005 and 2004, the accumulated post-retirement benefit obligation related to these agreements was $22 million and $18.3 million, respectively, and the projected benefit obligation was $28.5 million and $25.5 million, respectively. The Company recorded a minimum pension liability for supplemental retirement plans of $15.7 million and $14.2 million at December 31, 2005 and 2004, respectively. An intangible asset was recorded for the unrecognized prior service cost of $3.1 million and $2.5 million at December 31, 2005 and 2004, respectively, and the balance was recorded as a component of accumulated other comprehensive income, net of tax, of $8.2 million and $7.6 million at December 31, 2005 and 2004, respectively. An accrued post-retirement benefit liability of $6.2 million and $3.5 million was recorded at December 31, 2005 and 2004, respectively. The Company has established and funded a trust of $9 million and $6.1 million as of December 31, 2005 and December 31, 2004, respectively. While intended for payment of this benefit, the trusts assets remain subject to the claims of the Companys creditors. The Company is not required to make contributions to the supplemental retirement plans during 2006 but expects to fund approximately $1.5 million during 2006.
In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Companys 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. For its post-retirement benefit programs, the Company used a September 30 measurement date.
The status of the post-retirement benefit programs was as follows:
58
Weighted average rate assumptions used to determine post-retirement benefit obligations at the measurement date:
Salaried Employees | ||||||
September 30, 2005 |
September 30, 2004 |
|||||
Discount rate |
5.50 | % | 5.75 | % | ||
Rate of compensation increase |
3.50 | % | 4.00 | % | ||
Union Employees | ||||||
September 30, 2005 |
September 30, 2004 |
|||||
Discount rate |
5.50 | % | 5.75 | % | ||
Net periodic post-retirement benefit expense included the following:
59
Net periodic post-retirement benefit expense for Alagasco was $2,273,000, $2,573,000 and $2,902,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
Weighted average rate assumptions to determine net periodic benefit costs for the years ending:
Union Employees | |||||||||
December 31, 2005 |
December 31, 2004 |
December 31, 2003 |
|||||||
Discount rate |
5.75 | % | 5.94 | % | 6.75 | % | |||
Expected long-term return on plan assets |
8.50 | % | 8.75 | % | 9.00 | % | |||
Assumed post-65 health care cost trend rates used to determine the post-retirement benefit obligation at the measurement date:
Assumed health care cost trend rates used in determining the accumulated post-retirement benefit obligation have an effect on the amounts reported. For example, increasing the weighted average health care cost trend rate by 1 percentage point would have the following effects:
60
The Companys weighted-average post-retirement benefit program asset allocations by asset category were as follows:
Equity securities for the post-retirement benefit programs do not include the Companys common stock. The Company expects to make discretionary contributions of $1.4 million to post-retirement benefit program assets during 2006.
The following post-retirement benefit payments, which reflect expected future service, are anticipated to be paid:
(in thousands) |
Salaried
Employees |
Union
Employees |
||||
2006 |
$ | 1,984 | $ | 2,026 | ||
2007 |
$ | 2,056 | $ | 2,141 | ||
2008 |
$ | 2,119 | $ | 2,260 | ||
2009 |
$ | 2,164 | $ | 2,329 | ||
2010 |
$ | 2,214 | $ | 2,435 | ||
2011-2015 |
$ | 11,676 | $ | 13,050 |
The following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy beginning in 2006:
(in thousands) |
Salaried
Employees |
Union
Employees |
||||||
2006 |
$ | (157 | ) | $ | (213 | ) | ||
2007 |
$ | (167 | ) | $ | (229 | ) | ||
2008 |
$ | (174 | ) | $ | (241 | ) | ||
2009 |
$ | (178 | ) | $ | (249 | ) | ||
2010 |
$ | (178 | ) | $ | (251 | ) | ||
2011-2015 |
$ | (814 | ) | $ | (1,193 | ) |
For both defined benefit plans and other post-retirement plans, certain financial assumptions are used in determining the Companys 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 employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition, and market conditions.
61
The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets, and funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment mangers are performing satisfactorily.
The Company has a long-term disability plan covering most salaried employees. The Company had expense for the years ended December 31, 2005, 2004 and 2003 of $198,000, $938,000 and $265,000, respectively.
6. COMMON STOCK PLANS*
A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by electing to contribute a portion of their compensation to the ESP. The Company matches a percentage of the contributions and may make additional contributions of Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. Prior to January 1, 2004, employees were allowed to invest their elective contributions in Company stock. Company stock is no longer an investment option for new elective contributions. Vested employees may diversify 100 percent of their ESP Company stock account into other ESP investment options regardless of whether the Company stock was acquired through elective contribution, Company match, Company contribution or reinvestment of earnings. At December 31, 2005, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $4,650,000, $4,210,000 and $4,199,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
The 1997 Stock Incentive Plan adopted in October 2001 provided for the award of performance units, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Prior to the amendment, payment of performance awards could be made in cash or in a combination of Company common stock or cash. Under the 1997 Stock Incentive Plan, 117,540, 136,300 and 235,000 performance units were awarded in the years ended December 31, 2005, 2004 and 2003, respectively. The Company recorded expense of $9,338,000, $8,708,000 and $5,653,000 for the years ended December 31, 2005, 2004 and 2003, respectively, under the Plan.
The 1997 Stock Incentive Plan and the Energen Corporation 1988 Stock Option Plan provided 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 the 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 provided for the grant of restricted stock with 44,040, 131,520 and 106,950 shares awarded in the years ended December 31, 2005, 2004 and 2003, respectively. The sale or transfer of the shares is limited during certain periods. The Company recorded expense of $1,800,000, $1,390,000 and $1,076,000 for the years ended December 31, 2005, 2004 and 2003, respectively, related to restricted stock. Under the 1988 Stock Option Plan, 1,080,000 shares of Company common stock reserved for issuance have been granted. At December 31, 2005, the remaining shares reserved for issuance totaled 2,251,841 under the 1997 Stock Incentive Plan. 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:
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Total options granted under the 1997 Stock Option Plan during 2004 and 2003 included 82,760 shares and 133,560 shares which had a weighted average grant-date fair value of $7.11 and $6.05, respectively. The Company recorded expense of $465,000, $465,000 and $269,000 during the years ended December 31, 2005, 2004 and 2003, respectively, for these shares. The Company granted no options during 2005.
The following table summarizes information about options outstanding as of December 31, 2005:
Of the total shares granted during 2004 and 2003, 25,000 and 110,600, respectively, had stock appreciation rights. The 2004 grants were issued under the 2004 Stock Appreciation Rights Plan which provides for the payment of cash incentives measured by long-term appreciation in the Companys stock. The 2003 grants were issued under the 1997 Stock Incentive Plan as discussed above which provided for the issuance of stock appreciation rights. Expense associated with stock appreciation rights of $1,326,000, $916,000 and $209,000 was recorded for the years ended December 31, 2005, 2004 and 2003, respectively.
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, 12,116, 10,800 and 15,000 shares were awarded during the years ended December 31, 2005, 2004 and 2003, respectively, leaving 236,962 shares reserved for issuance as of December 31, 2005.
The Companys Dividend Reinvestment and Direct Stock Purchase Plan includes a direct stock purchase feature which allows purchases by non-shareholders. As of December 31, 2005, 1,098,292 common shares were reserved under this Plan.
By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000, the Board authorized the Company to repurchase up to 3,564,400 shares of the Companys common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2005 and 2004. For the year ended December 31, 2003, the Company repurchased 1,300 shares pursuant to its repurchase authorization. As of December 31, 2005, a total of 2,150,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Companys stock compensation plans. For the years ended December 31, 2005, 2004 and 2003, the Company acquired 67,957, 36,044 and 58,464 shares, respectively, in connection with its stock compensation plans.
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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 Companys 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 December 31, 2005, were convertible into 734,933 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 deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Companys common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trusts assets remain subject to the claims of the Companys creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the Consolidated Statements of Shareholders Equity.
During the quarter ended September 30, 2005, the Company reduced Treasury Stock and Deferred Compensation Plan, both reflected in shareholders equity, by approximately $25 million to correct the carrying value of the equity-based deferred compensation previously reported at market value to historical cost as prescribed by the Emerging Issues Task Force No. 97-14, Accounting for Deferred Compensation Arrangements Where Amounts Earned Are Held in a Rabbi Trust and Invested. This change had no impact on current or previously reported net income, cash flows or total shareholders equity.
* | Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
7. COMMITMENTS AND CONTINGENCIES
Commitments and Agreements: Certain of Alagascos long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $243 million through October 2015. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 166.1 Bcf through April 2015.
Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Companys financial position, results of operations or cash flows and is not expected to do so in the future; however, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.
During 2004, the State of New Mexico issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed above ground or with secondary containment and visual leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of this regulation, the Company expensed $1 million as lease operating expense during 2005. During 2004, the Company capitalized $0.5 million as part of its acquisition of properties in the San Juan Basin and expensed $1.6 million as lease operating expense under this regulation. The Company does not anticipate any further remediation charges on existing properties related to the new regulations.
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Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns), and five manufactured gas distribution sites (one of which it still owns). 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, Alagascos share, if any, of such costs will not materially affect the financial position, results of operations or cash flows of Alagasco.
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 and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.
Cochran County, Texas
In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judges order and expects to prevail. Under the Judges order, Energen Resources potential pre-tax charge to income would be approximately $3.3 million as of December 31, 2005, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition.
Jefferson County, Alabama
In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources received notice of immediate lease termination from RGGS. As of December 31, 2005, Energens consolidated balance sheet included approximately $96 million in net oil and gas properties associated with the lease. During 2005, Energen Resources production associated with the lease was approximately 11 Bcf.
RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no accrual with respect to the litigation or purported lease termination.
Other
Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.
Lease Obligations: Alagasco leases the Companys headquarters building over a 25-year term and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energens total lease payments related to leases included as operating lease expense were $13,628,000, $10,638,000 and $8,412,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Minimum future rental payments required after 2005 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
Years Ending December 31, (in thousands) | |||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2011 and thereafter | ||||||||||
$3,839 | $ | 3,598 | $ | 3,219 | $ | 3,216 | $ | 3,097 | $ | 32,716 |
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Alagascos total payments related to leases included as operating expense were $3,148,000, $2,728,000 and $2,602,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Minimum future rental payments required after 2005 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
Years Ending December 31, (in thousands) | |||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2011 and thereafter | ||||||||||
$3,141 | $ | 3,129 | $ | 3,069 | $ | 3,077 | $ | 3,097 | $ | 32,716 |
8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial Instruments: The stated 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 Energens long-term debt, including the current portion, with a carrying value of $699,654,000 would be $734,756,000 at December 31, 2005. The fair value of Alagascos fixed-rate long-term debt, including the current portion, with a carrying value of $214,654,000 would be $210,844,000 at December 31, 2005. The fair values were based on current market prices.
Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2005, the fixed price purchased under these guarantees had a maximum term outstanding through December 2006 with an aggregate purchase price of $4.7 million and a market value of $5.0 million.
Alagasco had an agreement with a financial institution whereby it could sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program. Effective February 1, 2004, Alagasco no longer sells its installment receivables. Alagasco sold installment receivables of $302,000 and $4,992,000 in the years ended December 31, 2004 and 2003, respectively. At December 31, 2005 and 2004, the balances of these installment receivables were $1,589,000 and $4,076,000, respectively. Receivables sold under this agreement were considered financial instruments with off-balance sheet risk. Alagascos exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The fair value of these guarantees is recorded as a non-current other liability.
Price Risk: The Company applies SFAS No. 133 as amended which 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 effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured 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 in operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivatives change in fair value is required to be recognized in operating revenues 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 operating revenues in the period of change.
Energen Resources periodically enters into cash flow derivative commodity instruments to hedge its price exposure on its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources or Alagasco collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where these arrangements exist,
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the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Companys or Alagascos credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company or Alagasco in the event credit ratings are below investment grade. At December 31, 2005, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of December 31, 2005. The Company believes the creditworthiness of these counterparties is satisfactory. The two largest counterparties represented approximately 48 percent and 22 percent of Energen Resources fair value of derivatives. Energen Resources other counterparties each represented less than 14 percent of the fair value of derivative.
As of December 31, 2005, $84.7 million of deferred net losses on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. Gains and losses on derivative instruments that are not accounted for as cash flow 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 $2.4 million after-tax loss in 2005 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, the Company recorded an after-tax loss of $14.1 million in 2005 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2005, all of the Companys hedges met the definition of a cash flow hedge. During 2005, the Company discontinued hedge accounting and reclassified losses of $0.8 million after-tax from OCI into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur.
The Company had $56.5 million and $15.6 million included in current and noncurrent deferred income taxes on the consolidated balance sheets related to items included in other comprehensive income as of December 31, 2005 and 2004, respectively. At December 31, 2005 and 2004, the Company had $145.9 million and $40.7 million, respectively, of current losses recorded in accounts payable and $11.9 million and $3.2 million, respectively, of non-current losses recorded in deferred credits and other liabilities related to derivative contracts.
As of December 31, 2005, Energen Resources entered into the following transactions for 2006 and subsequent years:
Production Period |
Total Hedged
Volumes |
Average Contract Price |
Description |
||||
Natural Gas | |||||||
2006 |
16.3 Bcf | $ | 8.08 Mcf | NYMEX Swaps | |||
21.9 Bcf | $ | 6.48 Mcf | Basin Specific Swaps | ||||
2007 |
3.0 Bcf | $ | 9.72 Mcf | Basin Specific Swaps | |||
Oil | |||||||
2006 |
2,844 MBbl | $ | 52.88 Bbl | NYMEX Swaps | |||
2007 |
600 MBbl | $ | 59.65 Bbl | NYMEX Swaps | |||
2008 |
900 MBbl | $ | 57.71 Bbl | NYMEX Swaps | |||
2009 |
900 MBbl | $ | 56.25 Bbl | NYMEX Swaps | |||
Oil Basis Differential | |||||||
2006 |
1,915 MBbl | ** | Basis Swaps | ||||
Natural Gas Liquids | |||||||
2006 |
30.2 MMGal | $ | 0.56 Gal | Liquids Swaps |
** | Average contract prices not meaningful due to the varying nature of each contract |
All hedge transactions are subject to the Companys 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 at the inception of the hedge, 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 instruments effectiveness in hedging the
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exposure to the hedged transactions variability in cash flows attributable to the hedged risk will be assessed and measured. 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 has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.
At December 31, 2005, Alagasco recognized a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives. At December 31, 2004, Alagasco recorded an $8.1 million gain as an asset in prepayments and other with a corresponding current regulatory liability of $8.1 million representing the fair value of derivatives.
Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Companys overall exposure to credit risk, either positively or negatively, in that the Companys oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers accounted for approximately 23 percent, 22 percent and 15 percent of Energen Resources accounts receivable for commodity sales as of December 31, 2005. Energen Resources other purchasers each accounted for less than 9 percent of this accounts receivable as December 31, 2005. During the year ended December 31, 2005, two purchases accounted for approximately 13 percent and 11 percent of the Companys total operating revenues.
Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and
transportation to approximately 460,000 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
9. RECONCILIATION OF EARNINGS PER SHARE*
Years ended December 31, (in thousands, except per share amounts) |
2005 | 2004 | 2003 | |||||||||||||||||||||
Net Income |
Shares |
Per Share
Amount |
Net Income |
Shares |
Per Share
Amount |
Net Income |
Shares |
Per Share
Amount |
||||||||||||||||
Basic EPS |
$ | 173,012 | 73,052 | $ | 2.37 | $ | 127,463 | 72,547 | $ | 1.76 | $ | 110,654 | 70,869 | $ | 1.56 | |||||||||
Effect of dilutive securities |
||||||||||||||||||||||||
Long-range performance shares |
208 | 212 | 146 | |||||||||||||||||||||
Stock options |
334 | 330 | 402 | |||||||||||||||||||||
Restricted stock |
121 | 28 | 17 | |||||||||||||||||||||
Diluted EPS |
$ | 173,012 | 73,715 | $ | 2.35 | $ | 127,463 | 73,117 | $ | 1.74 | $ | 110,654 | 71,434 | $ | 1.55 | |||||||||
* | Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
For the years ended December 31, 2005, 2004 and 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.
10. ASSET RETIREMENT OBLIGATIONS
The Company applies SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and will record the resulting gain or loss.
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In 2005, 2004 and 2003, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:
As of December 31, 2005, the Company adopted FIN 47, Accounting for Conditional Asset Retirement Obligations, which clarifies that if a legal obligation to perform an asset retirement activity exists but performance is conditional upon a future event, the liability is required to be recognized in accordance with SFAS 143 if the obligation can be reasonably measured. Alagasco recorded a conditional asset retirement obligations of $13.5 million to purge and cap its gas pipelines upon abandonment as a regulatory liability under SFAS No. 71 as of December 31, 2005. The costs associated with asset retirement obligations under FIN 47 are currently either being recovered in rates or are probable of recovery in future rates. Accordingly, the adoption of FIN 47 did not have an impact on the Companys income statements.
Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment
through depreciation expense in accordance with rates approved by the APSC. In accordance with SFAS No. 71, the accumulated asset removal costs of $105.4 million and $110.9 million for December 31, 2005 and 2004, respectively, are included
11. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning Energens cash flow activities was as follows:
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | ||||||
Interest paid, net of amount capitalized |
$ | 43,849 | $ | 40,557 | $ | 39,963 | |||
Income taxes paid |
$ | 32,879 | $ | 8,352 | $ | 10,929 | |||
Noncash investing activities: |
|||||||||
Capitalized depreciation |
$ | 96 | $ | 94 | $ | 123 | |||
Allowance for funds used during construction |
$ | 792 | $ | 1,247 | $ | 948 |
Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion expense of $2.6 million, $2.3 million and $1.9 million during 2005, 2004 and 2003, respectively.
Supplemental information concerning Alagascos cash flow activities was as follows:
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | ||||||
Interest paid, net of amount capitalized |
$ | 12,664 | $ | 11,248 | $ | 12,477 | |||
Income taxes paid |
$ | 22,456 | $ | 11,034 | $ | 12,754 | |||
Noncash investing activities: |
|||||||||
Capitalized depreciation |
$ | 96 | $ | 94 | $ | 123 | |||
Allowance for funds used during construction |
$ | 792 | $ | 1,247 | $ | 948 |
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12. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS
The Company applies SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which retains the previous asset impairment requirements of SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses in the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. During 2005, Energen Resources recorded a pre-tax gain of $213,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during 2004 or properties reclassified as held-for-sale as of December 31, 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million.
The following are the results of operations from discontinued operations:
* |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
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13. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)
The Companys business is seasonal in character. The following data summarizes quarterly operating results. The summarized quarterly information may differ from amounts previously reported due to changes in the classification of properties reported as discontinued operations as required by SFAS No. 144 (see Note 12).
Year Ended December 31, 2005 | ||||||||||||
(in thousands, except per share amounts) |
First | Second | Third | Fourth | ||||||||
Operating revenues |
$ | 361,008 | $ | 241,624 | $ | 190,681 | $ | 335,081 | ||||
Operating income |
$ | 105,130 | $ | 70,747 | $ | 41,071 | $ | 98,776 | ||||
Income from continuing operations |
$ | 58,942 | $ | 37,572 | $ | 19,073 | $ | 57,299 | ||||
Net income |
$ | 59,046 | $ | 37,573 | $ | 19,086 | $ | 57,307 | ||||
Diluted earnings per average common share* |
||||||||||||
Continuing operations |
$ | 0.80 | $ | 0.51 | $ | 0.26 | $ | 0.77 | ||||
Net income |
$ | 0.80 | $ | 0.51 | $ | 0.26 | $ | 0.78 | ||||
Basic earnings per average common share* |
||||||||||||
Continuing operations |
$ | 0.81 | $ | 0.51 | $ | 0.26 | $ | 0.78 | ||||
Net income |
$ | 0.81 | $ | 0.51 | $ | 0.26 | $ | 0.78 |
Year Ended December 31, 2004 | ||||||||||||
(in thousands, except per share amounts) |
First | Second | Third | Fourth | ||||||||
Operating revenues |
$ | 351,257 | $ | 188,046 | $ | 166,343 | $ | 231,211 | ||||
Operating income |
$ | 105,968 | $ | 46,065 | $ | 32,213 | $ | 60,597 | ||||
Income from continuing operations |
$ | 60,152 | $ | 22,224 | $ | 13,677 | $ | 31,252 | ||||
Net income |
$ | 60,185 | $ | 22,270 | $ | 13,740 | $ | 31,268 | ||||
Diluted earnings per average common share* |
||||||||||||
Continuing operations |
$ | 0.82 | $ | 0.30 | $ | 0.19 | $ | 0.43 | ||||
Net income |
$ | 0.82 | $ | 0.30 | $ | 0.19 | $ | 0.43 | ||||
Basic earnings per average common share* |
||||||||||||
Continuing operations |
$ | 0.83 | $ | 0.31 | $ | 0.19 | $ | 0.43 | ||||
Net income |
$ | 0.83 | $ | 0.31 | $ | 0.19 | $ | 0.43 |
* |
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
Alagascos business is seasonal in character and influenced by weather conditions. The following data summarizes Alagascos quarterly operating results.
Year Ended December 31, 2005 | |||||||||||||
(in thousands) |
First | Second | Third | Fourth | |||||||||
Operating revenues |
$ | 258,128 | $ | 107,197 | $ | 64,421 | $ | 170,954 | |||||
Operating income (loss) |
$ | 66,404 | $ | 5,630 | $ | (11,025 | ) | $ | 11,913 | ||||
Net income (loss) |
$ | 39,004 | $ | 1,073 | $ | (8,810 | ) | $ | 5,697 |
Year Ended December 31, 2004 | |||||||||||||
(in thousands) |
First | Second | Third | Fourth | |||||||||
Operating revenues |
$ | 255,202 | $ | 92,744 | $ | 62,162 | $ | 116,632 | |||||
Operating income (loss) |
$ | 62,014 | $ | 4,575 | $ | (10,130 | ) | $ | 9,740 | ||||
Net income (loss) |
$ | 36,319 | $ | 559 | $ | (7,745 | ) | $ | 4,657 |
14. ACQUISITION OF OIL AND GAS PROPERTIES
On December 15, 2005, Energen Resources completed a purchase of Permian Basin oil properties from a private company. The contract purchase price was approximately $168 million with an effective date of November 1, 2005. Approximately 80 percent of the 21.9 million barrels of proved oil reserves are undeveloped. More than 90 percent of the estimated proved reserves are oil. Energen used its available cash and existing lines of credit to finance the acquisition.
71
On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million. The effective date of the acquisition was August 1, 2004. Energen Resources acquired approximately 245 Bcfe of proved natural gas and natural gas liquids reserves. Approximately 51 percent of the proved reserves were estimated to be behind pipe and undeveloped. Approximately 80 percent of the acquisition reserves were gas with natural gas liquids comprising the balance. Energen used its short-term credit facilities and internally generated cash flows to finance the acquisition. A portion of the short-term debt incurred to finance the acquisition was repaid when Energen issued $100 million of Floating Rate Senior Notes in November 2004.
Summarized below are the consolidated results of operations for the years ended December 31, 2004 and 2003, on an unaudited pro forma basis as if the purchase of assets in the San Juan Basin had occurred at the beginning of 2003. The pro forma information is based on the Companys consolidated results of operations for the years ended December 31, 2004 and 2003, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.
Years ended December 31, (Unaudited) (in thousands, except per share data) |
2004 | 2003 | ||||
Operating revenues |
$ | 949,203 | $ | 860,404 | ||
Income from continuing operations |
$ | 128,109 | $ | 111,281 | ||
Net income |
$ | 128,267 | $ | 111,831 | ||
Diluted earnings per average common share* |
$ | 1.75 | $ | 1.57 | ||
Basic earnings per average common share* |
$ | 1.77 | $ | 1.58 |
* | Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005. |
15. REGULATORY ASSETS AND LIABILITIES
The following table details regulatory assets and liabilities on the consolidated balance sheets:
Energen Corporation
(in thousands) |
December 31, 2005 |
December 31, 2004 |
||||||||||
Current | Noncurrent | Current | Noncurrent | |||||||||
Regulatory assets: |
||||||||||||
Pension asset |
$ | | $ | 22,807 | $ | | $ | 19,650 | ||||
Accretion and depreciation for asset retirement obligation |
| 10,183 | | | ||||||||
Risk management activities |
6,291 | | | | ||||||||
Other |
342 | 446 | | | ||||||||
Total regulatory assets |
$ | 6,633 | $ | 33,436 | $ | | $ | 19,650 | ||||
Regulatory liabilities: |
||||||||||||
Enhanced stability reserve Gas supply adjustment Risk management activities RSE adjustment Unbilled service margin Asset removal costs, net Asset retirement obligation Other |
$
|
3,690
22,326 2,943 24,537 |
$
|
105,404 13,451 953 |
$
|
3,671
6,964 8,097 1,251 27,077 |
$
|
110,912 1,016 |
||||
Total regulatory liabilities |
$ | 53,496 | $ | 119,808 | $ | 47,060 | $ | 111,928 | ||||
As described in Note 2, Alagascos rates are established under the RSE rate-setting process and are based on average equity for the period. Alagascos rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.
72
16. STOCK DIVIDEND
On April 27, 2005, Energens shareholders approved a 2-for-1 split of the Companys common stock. The split was effected in the form of a 100 percent stock dividend and was payable on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split. Effective April 29, 2005, the Restated Certificate of Incorporation of Energen Corporation was amended to increase the Companys authorized common stock, par value $0.01 per share, from 75,000,000 shares to 150,000,000 shares.
17. EQUITY AND DEBT OFFERINGS
In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Alagasco used these long-term debt proceeds to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. Alagascos long-term debt proceeds were also used to refinance $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively.
In November 2004, Energen issued $100 million of Floating Rate Senior Notes (Senior Notes) due November 15, 2007. The interest rate is the three-month LIBOR Rate plus .35 percent, reset quarterly. At December 31, 2005, the interest rate was 4.69 percent on the Senior Notes. The Senior Note proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.
18. TRANSACTIONS WITH RELATED PARTIES
Alagasco purchased natural gas of $2,731,000, $2,112,000 and $3,195,000 from affiliates for the years ended December 31, 2005, 2004 and 2003, respectively. These amounts are included in gas purchased for resale. All transactions were at market based pricing.
The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors
including, but not limited to, total assets, earnings, or number of employees. The Companys cash management program matches short-term cash surpluses with the needs of its affiliates, to minimize borrowing from outside sources. Alagasco had
net receivables from affiliates of $3,215,000 and $2,190,000 at December 31, 2005 and 2004, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. The weighted
19. OTHER INCOME AND EXPENSE
The following table details Energens other income and expense amounts on the consolidated income statements:
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | ||||||
Allowance for funds used during construction |
$ | 792 | $ | 1,247 | $ | 948 | |||
Merchandise revenues |
| 671 | 7,696 | ||||||
Other |
1,371 | 1,027 | 100 | ||||||
Total other income |
$ | 2,163 | $ | 2,945 | $ | 8,744 | |||
Cost of goods sold |
$ | 268 | $ | 1,701 | $ | 8,549 | |||
Other merchandise expense |
442 | 514 | 1,428 | ||||||
Total other expense |
$ | 710 | $ | 2,215 | $ | 9,977 | |||
73
The following table details Alagascos other income and expense amounts on the income statements:
The sale of merchandise inventory items are reflected in other income and expense. Effective February 1, 2004, Alagasco no longer participates in direct sales of natural gas merchandise. Alagasco continues to work closely with various contractors and retail companies to meet the merchandise requirements of its customers.
20. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R), which requires a fair value base method of accounting using pricing models that reflect the specific economics of a companys transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. Although, the Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R, it does not anticipate that the adoption of SFAS No. 123R will have a material impact on the financial condition or results of operations of the Company. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant.
During April 2005, the FASB issued FSP No. 19-1, Accounting for Suspended Well Costs, which allows exploratory wells to be capitalized when the well has a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This interpretation was effective for the first reporting period beginning after April 4, 2005. The Company has adopted this standard and has no exploratory wells with capitalized costs that exceed more than one year.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 (Accounting Changes) and FASB Statement No. 3 (Reporting Accounting Changes in Interim Financial Statements). Opinion No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods financial statements of changes in accounting principle, unless it is impracticable. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
21. OIL AND GAS OPERATIONS (Unaudited)
The following schedules detail historical financial data of the Companys oil and gas operations. Certain reclassifications have been made to conform the prior years financial statements to the current-year presentation. Terms appearing in the schedules prescribed by the Securities and Exchange Commission (SEC) 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.
74
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 Continuing Operations From Producing Activities: The following table sets forth results of the Companys oil and gas continuing operations from producing activities:
75
Average Sales Price, Production Cost and Depreciation Rate From Continuing Operations
As of December 31, 2005, the Company was participating in the drilling of 4 gross development wells, with the Companys interest equivalent to 2.4 wells. In addition to the development wells drilled, the Company drilled 33, 45.9 and 41.6 net service wells during 2005, 2004 and 2003, respectively. As of December 31, 2005, the Company was participating in the drilling of 2 gross service wells, with the Companys interest equivalent to 1.1 wells.
Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2005, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
Gross | Net | |||
Gas wells |
3,869 | 2,102 | ||
Oil wells |
2,589 | 1,386 | ||
Developed acreage |
836,065 | 572,517 | ||
Undeveloped acreage |
146,876 | 124,472 | ||
There were 43 wells with multiple completions in 2005. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Alabama.
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 of America.
Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers, have
76
reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2005. Ryder Scott Company, L.P. reviewed the reserve estimates for coalbed methane in the Black Warrior and San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman and Associates, Inc. reviewed the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 91 percent of the Companys ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.
During 2005, Energen Resources sold approximately 1.1 Bcfe of proved reserves, recording a net pre-tax gain of $1.7 million on certain properties in the Permian and Black Warrior basins. Energen Resources had no property sales during 2004. During 2003, Energen Resources sold approximately 39 Bcfe of proved reserves, recording a net pre-tax loss of $1 million, which includes a $10.4 million writedown on assets held-for-sale and subsequently sold during the year partially offset by gains on property sales of $9.4 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 Companys 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 December 31, 2005, 2004 and 2003, the Company had a deferred hedging loss of $148.6 million, $41.1 million and $35.6 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.
77
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:
78
22. 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.
79
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Energen Corporation
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | |||||||||
ALLOWANCE FOR DOUBTFUL ACCOUNTS |
|
|||||||||||
Balance at beginning of year |
$ | 10,472 | $ | 9,852 | $ | 8,874 | ||||||
Additions: |
||||||||||||
Charged to income |
6,076 | 4,819 | 5,820 | |||||||||
Recoveries and adjustments |
(431 | ) | (290 | ) | (616 | ) | ||||||
Net additions |
5,645 | 4,529 | 5,204 | |||||||||
Less uncollectible accounts written off |
(4,544 | ) | (3,909 | ) | (4,226 | ) | ||||||
Balance at end of year |
$ | 11,573 | $ | 10,472 | $ | 9,852 | ||||||
Years ended December 31, (in thousands) |
2005 | 2004 | 2003 | |||||||||
ALLOWANCE FOR DOUBTFUL ACCOUNTS |
|
|||||||||||
Balance at beginning of year |
$ | 9,600 | $ | 9,100 | $ | 8,200 | ||||||
Additions: |
||||||||||||
Charged to income |
6,076 | 4,819 | 5,668 | |||||||||
Recoveries and adjustments |
(342 | ) | (403 | ) | (601 | ) | ||||||
Net additions |
5,734 | 4,416 | 5,067 | |||||||||
Less uncollectible accounts written off |
(4,534 | ) | (3,916 | ) | (4,167 | ) | ||||||
Balance at end of year |
$ | 10,800 | $ | 9,600 | $ | 9,100 | ||||||
80
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
a. Conclusion Regarding Disclosure Controls and Procedures
Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
b. Managements Report On Internal Control Over Financial Reporting
Management of Energen Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Energen Corporations internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:
i |
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Energen Corporation; |
ii |
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and |
iii |
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of Energen Corporations internal control over financial reporting as of December 31, 2005. Management based this assessment on criteria for effective internal control over financial reporting described in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Managements assessment included an evaluation of the design of Energen Corporations internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
Based on this assessment, management determined that, as of December 31, 2005, Energen Corporation maintained effective internal control over financial reporting. Managements assessment of the effectiveness of the Companys internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, our independent registered public accounting firm, as stated in their report which appears herein.
March 14, 2006
81
c. Changes in Internal Control Over Financial Reporting
Our chief executive officer and chief financial officer have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
82
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 Energens definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006. The definitive proxy statement will be filed on or about March 28, 2006.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is incorporated herein by reference from Energens definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
a. Security Ownership of Certain Beneficial Owners
The information regarding the security ownership of the beneficial owners of more than five percent of Energens common stock is incorporated herein by reference from Energens definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006.
b. Security Ownership of Management
The information regarding the security ownership of management is incorporated herein by reference from Energens definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006.
c. Securities Authorized for Issuance Under Equity Compensation Plans
The information regarding securities authorized for issuance under equity compensation plans is included in Part 2 under Item 5.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is incorporated herein by reference from Energens definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energens definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006.
83
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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
84
Energen Corporation
Alabama Gas Corporation
INDEX TO EXHIBITS
Item 14(a)(3)
Exhibit
Number |
Description |
|
*3(a) |
Restated Certificate of Incorporation of Energen Corporation (composite, as amended March 29, 2005) which was filed as Exhibit 3(a) to Energens Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005 |
|
*3(b) |
Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energens Post Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395) |
|
*3(c) |
Bylaws of Energen Corporation (as amended through October 30, 2002) which was filed as Exhibit 4(c) to Energens Registration Statement on Form S-8 (Registration No. 33-46641) |
|
*3(d) |
Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrants Annual Report on Form 10-K for the year ended September 30, 1995 |
|
*3(e) |
Bylaws of Alabama Gas Corporation (as amended through October 30, 2002) which was filed as Exhibit 3(e) to Energens Annual Report on Form 10-K for the year ended December 31, 2003 |
|
*4(a) |
Rights Agreement, dated as of July 27, 1998, between Energen Corporation and First Chicago Trust Company of New York, Rights Agent, which was filed as Exhibit 1 to Energens Registration Statement on Form 8-A, dated July 10, 1998 |
|
*4(b) |
Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the Energen 1996 Indenture), and which was filed as Exhibit 4(i) to the Registrants Registration Statement on Form S-3 (Registration No. 333-11239) |
|
*4(b)(i) |
Officers Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energens Annual Report on Form 10-K for the year ended September 30, 2001 |
|
*4(b)(ii) |
Officers Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energens Annual Report on Form 10-K for the year ended September 30, 2001 |
|
*4(b)(iii) |
Amended and Restated Officers Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energens Annual Report on Form 10-K for the year ended September 30, 2001 |
|
*4(b)(iv) |
Officers Certificate, dated October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5 percent Notes due October 1, 2013, which was filed as Exhibit 4 to Energens Current Report on Form 8-K, dated October 3, 2003 |
|
*4(b)(v) |
Officers Certificate, dated November 19, 2004, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Floating Rate Senior Notes due November 15, 2004, which was filed as Exhibit 4.2 to Energens Current Report on Form 8-K, dated November 19, 2004 |
85
86
*10(k) |
Energen Corporation 1992 Long-Range Performance Share Plan (as amended effective October 1, 1999) which was filed as Exhibit 10(f) to Energens Annual Report on Form 10-K for the year ended September 30, 1999 |
|
*10(l) |
Energen Corporation 1997 Stock Incentive Plan (as amended effective January 1, 2006) which was filed as Exhibit 99.3 to Energens Current Report on Form 8-K filed January 27,2006 |
|
*10(m) |
Form of Stock Option Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(a) to Energens Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 |
|
*10(n) |
Form of Restricted Stock Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(b) to Energens Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 |
|
*10(o) |
Form of Performance Share Award under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(c) to Energens Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 |
|
*10(p) |
Energen Corporation 1997 Deferred Compensation Plan (as amended effective January 1, 2001) which was filed as Exhibit 10(n) to Energens Annual Report Form 10K for the year ended December 31, 2005 |
|
*10(q) |
Amendment No. 1 to the Energen Corporation 1997 Deferred Compensation Plan (as amended January 1, 2001) which was filed as Exhibit 10(o) to Energens Annual Report Form 10K for the year ended December 31, 2005. |
|
*10(r) |
Energen Corporation 1992 Directors Stock Plan (as amended April 25, 1997) which was filed as Exhibit 10(i) to Energens Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810) |
|
*10(s) |
Energen Corporation Annual Incentive Compensation Plan, as amended effective October 1, 2001 which was filed as Exhibit 10(k) to Energens Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810) |
|
*10(t) |
Energen Corporation Officer Split Dollar Life Insurance Plan, effective October 1, 1999 which was filed as Exhibit 10(l) to Energens Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810) |
|
*10(u) |
Form of Split Dollar Life Insurance Plan Agreement under Energen Corporation Officer Split Dollar Life Insurance Plan which was filed as Exhibit 10(m) to Energens Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810) |
|
*10(v) |
Officer Split Dollar Tax Matters Agreement which was filed as Exhibit 10(n) to Energens Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810) |
|
*10(w) |
Energen Board of Directors resolution adopted as of May 14, 2004, terminating the Energen Corporation Officer Split Dollar Life Insurance Plan which was filed as Exhibit 10(u) to Energens Annual Report on Form 10K for the year ended December 31, 2005 |
|
21 |
Subsidiaries of Energen Corporation |
|
23(a) |
Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP) |
87
23(b) |
Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP) |
|
23(c) |
Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.) |
|
23(d) |
Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.) |
|
31(a) |
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) |
|
31(b) |
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) |
|
32 |
Certification pursuant to Section 1350 |
* | Incorporated by reference |
88
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)
March 14, 2006 |
By |
/s/ Wm. Michael Warren, Jr. |
||
Wm. Michael Warren, Jr. | ||||
Chairman and Chief Executive Officer of | ||||
Energen, Chairman and Chief Executive | ||||
Officer of Alabama Gas Corporation |
89
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:
March 14, 2006 |
By |
/s/ Wm. Michael Warren, Jr. |
||
Wm. Michael Warren, Jr. |
||||
Chairman and Chief Executive Officer of Energen, |
||||
Chairman and Chief Executive Officer of Alabama |
||||
Gas Corporation |
||||
March 14, 2006 |
By |
/s/ Geoffrey C. Ketcham |
||
Geoffrey C. Ketcham |
||||
Executive Vice President, Chief Financial Officer and |
||||
Treasurer of Energen and Alabama Gas Corporation |
||||
March 14, 2006 |
By |
/s/ Grace B. Carr |
||
Grace B. Carr |
||||
Vice President and Controller of Energen |
||||
March 14, 2006 |
By |
/s/ Paula H. Rushing |
||
Paula H. Rushing |
||||
Vice President-Finance of Alabama Gas |
||||
Corporation |
||||
March 14, 2006 |
By |
/s/ Julian W. Banton |
||
Julian W. Banton |
||||
Director |
||||
March 14, 2006 |
By |
/s/ James S. M. French |
||
James S. M. French |
||||
Director |
||||
March 14, 2006 |
By |
/s/ T. Michael Goodrich |
||
T. Michael Goodrich |
||||
Director |
||||
March 14, 2006 |
By |
/s/ Judy M. Merritt |
||
Judy M. Merritt |
||||
Director |
||||
March 14, 2006 |
By |
/s/ David W. Wilson |
||
David W. Wilson |
||||
Director |
90
Exhibit 10(a):
Service Agreement No. SSNG1
SERVICE AGREEMENT
UNDER RATE SCHEDULE CSS
THIS AGREEMENT, made and entered into as of this 1 st day of September, 2005, by and between Southern Natural Gas Company, a Delaware corporation, hereinafter referred to as Company, and Alabama Gas Corporation, an Alabama municipal corporation, hereinafter referred to as Shipper.
WITNESSETH
WHEREAS, Company has undertaken to provide a firm storage service under Part 284 of the Federal Energy Regulatory Commissions (Commission) Regulations and Companys Rate Schedule CSS of its FERC Gas Tariff; and
WHEREAS, Shipper has requested storage service on a firm basis pursuant to Rate Schedule CSS and has submitted to. Company a request for such storage service in compliance with Section 7 of Companys Rate Schedule CSS; and/or
WHEREAS, Shipper may acquire, from time to time, released firm storage capacity under Section 22 of the General Terms and Conditions of Companys FERC Gas Tariff, and
WHEREAS, Company is willing to render firm storage service to Shipper pursuant to the provisions of Rate Schedule CSS, this Agreement and Part 284 of the Commissions Regulations.
NOW, THEREFORE, the parties hereby agree as follows:
ARTICLE I
QUANTITY OF SERVICE
1.1 Subject to the terms and provisions of this Agreement and Companys Rate Schedule CSS and the General Terms and Conditions applicable thereto, Shipper has the right to maintain in Companys Storage fields under the terms of this Agreement an aggregate quantity of natural gas up to the Maximum Storage Quantity set forth on Exhibit A hereto or any effective Capacity Release Transaction. Companys obligation to accept gas at the Storage Point specified in Exhibit A hereto for injection into Storage on any day is limited to the available Maximum Daily Injection Quantity (MDIQ) specified on Exhibit A or any effective Capacity Release Transaction.
Service Agreement No. SSNG1
1.2 Company shall redeliver a thermally equivalent quantity of gas, less the applicable fuel charge as set forth in Rate Schedule CSS, to Shipper or a third party designated by Shipper at the Storage Point described on Exhibit A hereto. Companys obligation to withdraw gas from Storage for delivery at the Storage Point on any day is limited to the available Maximum Daily Withdrawal Quantity (MDWQ) specified on Exhibit A or any effective Capacity Release Transaction and Shippers Storage Inventory.
1.3 In the event Shipper is the successful bidder on released firm storage capacity under Section 22 of Companys General Terms and Conditions, Company will promptly finalize by means of SoNet Premier the Capacity Release Transaction. Upon the finalization of a Capacity Release Transaction, subject to the terms, conditions and limitations hereof and Companys Rate Schedule CSS, Company agrees to provide the released firm storage service to Shipper under Rate Schedule CSS, the General Terms and Conditions thereto, and this Agreement.
ARTICLE II
CONDITIONS OF SERVICE
2.1 It is recognized that the storage service hereunder is provided on a firm basis pursuant to, in accordance with and subject to the provisions of Companys Rate Schedule CSS, and the General Terms and Conditions thereto, which are contained in Companys FERC Gas Tariff, as in effect from time to time, and which are hereby incorporated by reference. In the event of any conflict between this Agreement and Rate Schedule CSS, the terms of Rate Schedule CSS shall govern as to the point of conflict. Any limitation of storage service hereunder shall be in accordance with the priorities set out in Rate Schedule CSS.
2.2 This Agreement shall be subject to all provisions of the General Terms and Conditions specifically made applicable to Companys Rate Schedule CSS, as such conditions may be revised from time to time. Unless Shipper requests otherwise, Company shall provide to Shipper the filings Company makes at the Commission of such provisions of the General Terms and Conditions or other matters relating to Rate Schedule CSS.
2.3 Company shall have the right to discontinue service under this Agreement in accordance with Section 15.3 of the General Terms and Conditions contained in Companys FERC Gas Tariff.
2
Service Agreement No. SSNG1
2.4 The parties hereto agree that neither party shall be liable to the other party for any special, indirect, or consequential damages (including, without limitation, loss of profits or business interruptions) arising out of or in any manner related to this Agreement.
2.5 This Agreement is subject to the provisions of Subpart G of Part 284 of the Commissions Regulations. Upon termination of this Agreement, Company and Shipper shall be relieved of further obligation to the other party except to complete the storage activities underway on the day of termination, to comply with the provisions of Section 7(f) of Rate Schedule CSS with respect to any of Shippers gas remaining in Storage upon termination of this Agreement, to render reports, and to make payment for storage services rendered.
ARTICLE III
NOTICES
3.1 Except as provided in Section 6.6 herein, notices hereunder shall be given pursuant to the provisions of Section 18 of the General Terms and Conditions to the respective party at the applicable address, telephone number, facsimile machine number or e-mail addresses provided by the parties on Appendix E to the General Terms and Conditions or such other addresses, telephone numbers, facsimile machine numbers, or e-mail addresses as the parties shall respectively hereafter designate in writing from time to time.
ARTICLE IV
TERM
4.1 Subject to the provisions hereof, this Agreement shall become effective as of the date first written above and shall be in full force and effect for the primary term(s) set forth on Exhibit A hereto, if applicable, and shall continue and remain in force and effect for successive evergreen terms specified on Exhibit A hereto unless canceled by either party giving the required amount of written notice specified on Exhibit A to the other party prior to the end of the primary term(s) or any extension thereof.
4.2 In the event Shipper has not contracted for a Maximum Storage Quantity under this Agreement directly with Company, as set forth on Exhibit A hereto, then the term of this Agreement shall be effective as of the date first hereinabove written and shall remain in full force and effect for a primary term through the end of the month and month to month thereafter unless canceled by either party giving at least five (5) days written notice to the other party prior to the end of the primary term or any extension thereof, provided however, this agreement will automatically terminate if no nominations are requested during a period of 12 consecutive months. It is provided, however that this Agreement shall not terminate prior to the expiration of the effective date of any Capacity Release Transaction.
3
Service Agreement No. SSNG1
ARTICLE V
REMUNERATION
5.1 Shipper shall pay Company monthly the charges specified in Rate Schedule CSS for the storage services rendered hereunder or under each effective Capacity Release Transaction, as applicable. For service requested from Company under Rate Schedule CSS, Company shall notify Shipper as soon as practical of the date service will commence hereunder, and if said date is not the first day of the month, the Deliverability Charge and Capacity Charge for the first month of service hereunder shall be adjusted to reflect only the actual number of days during said month that storage service is available. Company may agree from time to time to discount the rates charged Shipper for services provided hereunder in accordance with the provisions of Rate Schedule CSS. Said discounted rates or negotiated rates shall be set forth on Exhibit C or Exhibit D, respectively, hereto and shall take precedence over the charges set forth in Rate Schedule CSS during the period in which they are in effect.
5.2 The rates and charges provided for under Rate Schedule CSS shall be subject to increase or decrease pursuant to any order issued by the Commission in any proceeding initiated by Company or applicable to the services performed hereunder. Shipper agrees that Company shall, without any further agreement by Shipper have the right to change from time to time, all or any part of Rate Schedule CSS or the General Terms and Conditions applicable thereto, including without limitation the right to change the rates and charges in effect hereunder, pursuant to Section 4(d) of the Natural Gas Act as may be deemed necessary by Company, in its reasonable judgment, to assure just and reasonable terms of service and rates under the Natural Gas Act. It is recognized, however, that once a Capacity Release Transaction has been awarded, Company cannot increase the Deliverability Charge or Capacity Charge to be paid by Shipper under that Capacity Release Transaction, unless in its bid the Acquiring Shipper has agreed to pay a percentage of the maximum tariff rate in effect and the maximum tariff rate increases during the term of the Capacity Release Transaction. Nothing contained herein shall prejudice the rights of Shipper to contest at any time the changes made pursuant to this Section 5.2, including the right to contest the rates or charges for the services provided under this Agreement, from time to time, in any rate proceedings by Company under Section 4 of the Natural Gas Act or to file a complaint under Section 5 of the Natural Gas Act with respect to such rates or charges.
4
Service Agreement No. SSNG1
ARTICLE VI
MISCELLANEOUS
6.1 This Agreement constitutes the entire Agreement between the parties and no waiver by Company or Shipper of any default of either party under this Agreement shall operate as a waiver of any subsequent default whether of a like or different character.
6.2 The laws of the State of Alabama shall govern the validity, construction, interpretation, and effect of this Agreement, without giving effect to any conflict of laws doctrine that would apply the laws of another jurisdiction.
6.3 No modification of or supplement to the terms and provisions hereof shall be or become effective except by execution of a supplementary written agreement between the parties.
6.4 This Agreement shall bind and benefit the successors and assigns of the respective parties hereto. Subject to the provisions of Section 22 of the General Terms and Conditions applicable hereto, either party may assign this Agreement to an affiliated company without the prior written consent of the other party, provided that the affiliated company is creditworthy pursuant to Section 2.1(d) of the General Terms and Conditions, but neither party may assign this Agreement to a nonaffiliated company without the prior written consent of the other party, which consent shall not be unreasonably withheld; provided, however, that either party may assign or pledge this Agreement under the provisions of any mortgage, deed of trust, indenture or similar instrument.
6.5 Exhibits A and/or other exhibits, from time to time, attached to this Agreement constitute a part of this Agreement and are incorporated herein.
6.6 This Agreement is subject to all present and future valid laws and orders, rules, and regulations of any regulatory body of the federal or state government having or asserting jurisdiction herein. After the execution of this Agreement for firm storage capacity from Company, each party shall make and diligently prosecute, all necessary filings with federal or other governmental bodies, or both, as may be required for the initiation and continuation of the storage service which is the subject of this Agreement. Each party shall have the right to seek such governmental authorizations, as it deems necessary, including the right to prosecute its requests or applications for such authorization in the manner it deems appropriate. Upon either partys request, the other party shall timely provide or cause to be provided to the requesting party such information and material not within the requesting partys control and/or possession that may be required for such filings. Each party shall promptly inform the other party of any changes in the representations made by such party
5
Service Agreement No. SSNG1
herein and/or in the information provided pursuant to this paragraph. Each party shall promptly provide the other party with a copy of all filings, notices, approvals, and authorizations in the course of the prosecution of its filings. In the event all such necessary regulatory approvals have not been issued or have not been issued on terms and conditions acceptable to Company or Shipper within twelve (12) months from the date of the initial FERC application therefore, then Company or Shipper may terminate this Service Agreement No. SSNG1
Agreement without further liability or obligation to the other party by giving written notice thereof at any time subsequent to the end of such twelve-month period, but prior to the receipt of all such acceptable approvals. Company or Shipper may waive their rights to terminate this Agreement under this Section upon mutual agreement in writing. Such notice will be effective as of the date it is delivered to the U.S. mail for delivery by certified mail, return receipt requested.
6.7 This Agreement supersedes and cancels the Service Agreement No. S 10710 dated November 1, 1993, as amended April 17, 2002, between the parties hereto.
IN WITNESS WHEREOF, this Agreement has been executed by the parties as of the date first written above by their respective duly authorized officers.
Attest/Witness: |
SOUTHERN NATURAL GAS COMPANY |
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By |
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Its |
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Attest/Witness: |
ALABAMA GAS CORPORATION |
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By |
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Its |
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6
Exhibit 10(b):
Service Agreement No. FSNG1
FIRM TRANSPORTATION SERVICE AGREEMENT
UNDER RATE SCHEDULE FT AND/OR RATE SCHEDULE FT-NN
THIS AGREEMENT, made and entered into as of this 1st day of September, 2005, by and between Southern Natural Gas Company, a Delaware corporation, hereinafter referred to as Company, and Alabama Gas Corporation, an Alabama corporation, hereinafter referred to as Shipper.
WITNESSETH
WHEREAS, Company is an interstate pipeline, as defined in Section 2(15) of the Natural Gas Policy Act of 1978 (NGPA); and
WHEREAS, Shipper has requested firm transportation pursuant to Rate Schedule FT and/or FT-NN of various supplies of gas for redelivery for Shippers account and has submitted to Company a request for such transportation service in compliance with Section 2 of the General Terms and Conditions applicable to such Rate Schedules; and/or
WHEREAS, Shipper may acquire, from time to time, released firm transportation capacity under Section 22 of the General Terms and Conditions of Companys FERC Gas Tariff; and
WHEREAS, Company has agreed to provide Shipper with transportation service of such gas supplies or through such acquired capacity release in accordance with the terms and conditions of this Agreement.
NOW, THEREFORE, the parties hereto agree as follows:
ARTICLE I
TRANSPORTATION QUANTITY
1.1 Subject to the terms and provisions of this Agreement, Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto, Shipper agrees to deliver or cause to be delivered to Company at the Receipt Point(s) described in Exhibit A and Exhibit A-1 to this Agreement, and Company agrees to accept at such point(s) for transportation under this Agreement, an aggregate quantity of natural gas per day up to the total Transportation Demand set forth on Exhibit B hereto. Companys obligation to accept gas on a firm basis at any Receipt Point is limited to the Receipt Points set out on Exhibit A and to the Maximum Daily Receipt Quantity (MDRQ) stated for each such Receipt Point. The sum of the MDRQs for the Receipt Points on Exhibit A shall not exceed the Transportation Demand.
Transportation Demand Service Agreement No. FSNG1
1.2 Subject to the terms and provisions of this Agreement, Rate Schedule FT and/or FT-NN, as a applicable, and the General Terms and Conditions thereto, Company shall deliver a thermally equivalent quantity of gas, less the applicable fuel charge as set forth in the applicable FT or FT-NN Rate Schedule, to Shipper at the Delivery Point(s) described in Exhibit B and Exhibit B-1 hereto. Companys obligation to redeliver gas at any Delivery Point on a firm basis is limited to the Delivery Points specified on Exhibit B and to the Maximum Daily Delivery Quantity (MDDQ) stated for each such Delivery Point and in no event shall Shipper be entitled to deliveries in excess of the MDDQ such that if Shipper elects to take gas at an Exhibit B-1 Delivery Point then the MDDQ at its Exhibit B Delivery Points will be reduced proportionately. The sum of the MDDQs for the Delivery Points on Exhibit B shall equal the Transportation Demand.
1.3 In the event Shipper is the successful bidder on released firm transportation capacity under Section 22 of the Companys General Terms and Conditions, Company will promptly email to Shipper the terms of the Capacity Release Transaction. Upon the issuance of the email, subject to the terms, conditions and limitations hereof and of Companys Rate Schedules FT and FT-NN, Company agrees to provide the released firm transportation service to Shipper under Rate Schedule FT or FT-NN, the General Terms and Conditions thereto, and this Agreement.
ARTICLE II
CONDITIONS OF SERVICE
2.1 It is recognized that the transportation service hereunder is provided on a firm basis pursuant to, in accordance with and subject to the provisions of Companys Rate Schedule FT and/or FT-NN, and the General Terms and Conditions thereto, which are contained in Companys FERC Gas Tariff, as in effect from time to time, and which are hereby incorporated by reference. In the event of any conflict between this Agreement and the terms of the applicable Rate Schedule, the terms of the Rate Schedule shall govern as to the point of conflict. Any limitation of transportation service hereunder shall be in accordance with the priorities set out in Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto.
2.2 This Agreement shall be subject to all provisions of the General Terms and Conditions applicable to Companys Rate Schedule FT and/or FT-NN as such conditions may be revised from time to time. Unless Shipper requests otherwise, Company shall provide to Shipper the filings Company makes at the Federal Energy Regulatory Commission (Commission) of such provisions of the General Terms and Conditions or other matters relating to Rate Schedule FT or FT-NN.
2.3 Company shall have the right to discontinue service under this Agreement in accordance with Section 15.3 of the General Terms and Conditions hereto.
2.4 The parties hereto agree that neither party shall be liable to the other party for any special, indirect, or consequential damages (including, without limitation, loss of profits or business interruptions) arising out of or in any manner related to this Agreement.
2
Service Agreement No. FSNG1
2.5 This Agreement is subject to the provisions of Subpart G of Part 284 of the Commissions Regulations under the NGPA and the Natural Gas Act. Upon termination of this Agreement, Company and Shipper shall be relieved of further obligation to the other party except to complete the transportation of gas underway on the day of termination, to comply with the provisions of Section 14 of the General Terms and Conditions with respect to any imbalances accrued prior to termination of this Agreement, to render reports, and to make payment for all obligations accruing prior to the date of termination.
ARTICLE III
NOTICES
3.1 Except as provided in Section 8.6 herein, notices hereunder shall be given pursuant to the provisions of Section 18 of the General Terms and Conditions to the respective party at the applicable address, telephone number, facsimile machine number or e-mail addresses :provided by the parties on Appendix E to the General Terms and Conditions or such other addresses, telephone numbers, facsimile machine numbers or e-mail addresses as the parties shall respectively hereafter designate in writing from time to time.
ARTICLE IV
TERM
4.1 Subject to the provisions hereof, this Agreement shall become effective as of the date first hereinabove written and shall be in full force and effect for the primary term(s) set forth on Exhibit B hereto, if applicable, and shall continue and remain in force and effect for successive evergreen terms specified on Exhibit B hereto unless canceled by either party giving the required amount of written notice specified on Exhibit B to the other party prior to the end of the primary term(s) or any extension thereof. The primary term of the Agreement may be calculated from the date service commences hereunder rather than the effective date as provided above, if construction of facilities is necessary.
4.2 In the Event Shipper has not contracted for firm Transportation Demand under this Agreement directly with Company, as set forth on Exhibit B hereto, then the term of this Agreement shall be effective as of the date first hereinabove written and shall remain in full force and effect for a primary term through the end of the month and month to month thereafter unless canceled by either party giving at least five (5) days written notice to the other party prior to the end of the primary term or any extension thereof, provided however, this agreement will automatically terminate if no nominations are requested during a period of 12 consecutive months. It is provided, however that this Agreement shall not terminate prior to the expiration of the effective date of any Capacity Release Transaction.
3
Service Agreement No. FSNG1
ARTICLE V
CONDITIONS PRECEDENT
5.1 Unless otherwise agreed to by the parties, the terms of Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto, shall apply to the acquisition or construction of any facilities necessary to effectuate this Agreement. Other provisions of this Agreement notwithstanding, Company shall be under no obligation to construct the facilities or commence service hereunder unless and until (1) Company has received and accepted the necessary regulatory approvals and permits to construct the facilities in a form and substance satisfactory to Company; (2) all facilities, of whatever nature, as are required to permit the receipt, measurement, transportation, and delivery of natural gas hereunder have been authorized, installed, and are in operating condition; (3) (If applicable) Company has obtained the approval of the appropriate management or management committee and/or board of directors of Company and/or its parent company to spend the capital necessary to construct the additional facilities; and (4) SHIPPER completes the construction and places into operation, using diligent efforts, its upstream or downstream production or end use facilities required to receive or deliver gas hereunder. (If applicable) In the event construction of facilities by COMPANY is necessary to provide service under the Agreement, Company agrees to use its reasonable efforts to meet an in-service date of .
ARTICLE VI
REMUNERATION
6.1 Shipper shall pay Company monthly for the transportation services rendered hereunder the charges specified in Rate Schedule FT, Rate Schedule FT-NN, and under each effective Capacity Release Transaction, as applicable, including any penalty and other authorized charges assessed under the applicable FT or FT-NN Rate Schedule and the General Terms and Conditions. For service requested from Company under Rate Schedule FT or FT-NN, Company shall notify Shipper as soon as practicable of the date services will commence hereunder, and if said date is not the first day of the month, the Reservation Charge for the first month of service hereunder shall be adjusted to reflect only the actual number of days during said month that transportation service is available. Company may agree from time to time to discount the rates charged Shipper for services provided hereunder in accordance with the provisions of Rate Schedule FT and/or FT-NN, as applicable. Said discounted charges shall be set forth on Exhibit E hereto or the parties may agree to a Negotiated Rate for such services in accordance with the provisions of Rate Schedule FT or FT-NN. Said discounted or Negotiated Rates shall be set forth on Exhibit E or Exhibit F, respectively, hereto and shall take precedence over the charges set forth in Rate Schedules FT or FT-NN during the period in which they are in effect.
4
Service Agreement No. FSNG1
6.2 The rates and charges provided for under Rate Schedule FT shall be subject to increase or decrease pursuant to any order issued by the Commission in any proceeding initiated by Company or applicable to the services performed hereunder. Shipper agrees that Company shall, without any further agreement by Shipper, have the right to change from time to time, all or any part of its Proforma Service Agreement, as well as all or any part of Rate Schedule FT or FT-NN, as applicable, or the General Terms and Conditions thereto, including without limitation the right to change the rates and charges in effect hereunder, pursuant to Section 4(d) of the Natural Gas Act as may be deemed necessary by Company, in its reasonable judgment, to assure just and reasonable service and rates under the Natural Gas Act. It is recognized, however, that once a Capacity Release Transaction has been awarded, Company cannot increase the Reservation Charge to be paid by Shipper under that Capacity Release Transaction, unless in its bid the Acquiring Shipper has agreed to pay a percentage of the maximum tariff rate in effect and the maximum tariff rate increases during the term of the Capacity Release Transaction. Nothing contained herein shall prejudice the rights of Shipper to contest at any time the changes made pursuant to this Section 6.2, including the right to contest the transportation rates or charges for the services provided under this Agreement, from time to time, in any subsequent rate proceedings by Company under Section 4 of the Natural Gas Act or to file a complaint under Section 5 of the Natural Gas Act with respect to such transportation rates or charges, the Rate Schedules, or the General Terms and Conditions thereto.
ARTICLE VII
SPECIAL PROVISIONS
7.1 If Shipper is a seller of gas under more than one Service Agreement and requests that company allow it to aggregate nominations for certain Receipt Points for such Agreements, Company will allow such an arrangement under the terms and conditions set forth in this Article VII. To be eligible to aggregate gas, Shipper must comply with the provisions of Section 2.2 of the General Terms and Conditions and the terms and conditions of the Supply Pool Balancing Agreement executed by Shipper and Company pursuant thereto.
7.2 If Shipper is a purchaser of gas from a seller that is selling from an aggregate of Receipt Points, and Shipper wishes to nominate to receive gas from such sellers aggregate supplies of gas, Company will allow such a nomination, provided that the seller (i) has entered into a Supply Pool Balancing Agreement with Company and (ii) submits a corresponding nomination to deliver gas to Shipper from its aggregate supply pool.
5
Service Agreement No. FSNG1
ARTICLE VIII
MISCELLANEOUS
8.1 This Agreement constitutes the entire Agreement between the parties and no waiver by Company or Shipper of any default of either party under this Agreement shall operate as a waiver of any subsequent default whether of a like or different character.
8.2 The laws of the State of Alabama shall govern the validity, construction, interpretation, and effect of this agreement, without giving effect to any conflict of laws doctrine that would apply the laws of another jurisdiction.
8.3 No modification of or supplement to the terms and provisions hereof shall be or become effective except by execution of a supplementary written agreement between the parties except that (i) a Capacity Release Transaction may be issued, and (ii) in accordance with the provisions of Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto, Receipt Points may be added to or deleted from Exhibit A and the Maximum Daily Receipt Quantity for any Receipt Point on Exhibit A may be changed upon execution by Company and Shipper of a Revised Exhibit A to reflect said change(s), and (iii) Delivery Points may be added to or deleted from Exhibit B and the Maximum Daily Delivery Quantity for any Delivery Point may be changed upon execution by Company and Shipper of a Revised Exhibit B to reflect said change(s). It is provided, however, that any such change to Exhibit A or Exhibit B must include corresponding changes to the existing Maximum Daily Receipt Quantities or Maximum Daily Delivery Quantities, respectively, such that the sum of the changed Maximum Daily Receipt Quantities shall not exceed the Transportation Demand and the sum of the Maximum Daily Delivery Quantities equals the Transportation Demand.
8.4 This Agreement shall bind and benefit the successors and assigns of the respective parties hereto. Subject to the provisions of Section 22 of the General Terms and Conditions applicable hereto, either party may assign this Agreement to an affiliated company without the prior written consent of the other party, provided that the affiliated company is creditworthy pursuant to Section 2.1(d) of the General Terms and Conditions, but neither party may assign this Agreement to a nonaffiliated company without the prior written consent of the other party, which consent shall not be unreasonably withheld; provided, however, that either party may assign or pledge this Agreement under the provisions of any mortgage, deed of trust, indenture or similar instrument.
8.5 Exhibits A, A-1, B, B-1, and/or other exhibits, from time to time, attached to this Agreement constitute a part of this Agreement and are incorporated herein.
8.6 This Agreement is subject to all present and future valid laws and orders, rules, and regulations of any regulatory body of the federal or state government having or asserting jurisdiction herein. After the execution of this Agreement for firm transportation capacity from Company, each party shall make and diligently prosecute all
6
Service Agreement No. FSNG1
necessary filings with federal or other governmental bodies, or both, as may be required for the initiation and continuation of the transportation service which is the subject of this Agreement and to construct and operate any facilities necessary therefore. Each party shall have the right to seek such governmental authorizations as it deems necessary, including the right to prosecute its requests or applications for such authorization in the manner it deems appropriate. Upon either partys request, the other party shall timely provide or cause to be provided to the requesting party such information and material not within the requesting partys control and/or possession that may be required for such filings. Each party shall promptly inform the other party of any changes in the representations made by such party herein and/or in the information provided pursuant to this paragraph. Each party shall promptly provide the party with a copy of all filings, notices, approvals, and authorizations in the course of the prosecution of its filings. In the event all such necessary regulatory approvals have not been issued or have not been issued on terms and conditions acceptable to Company or Shipper within twelve (12) months from the date of the initial FERC application therefore, then Company or Shipper may terminate this Agreement without further liability or obligation to the other party by giving written notice thereof at any time subsequent to the end of such twelve-month period, but prior to the receipt of all such acceptable approvals. Company or Shipper may waive their rights to terminate this Agreement under this Section upon mutual agreement in writing. Such notice will be effective as of the date it is delivered to the U.S. Mail, for delivery by certified mail, return receipt requested.
8.7 If Shipper experiences the loss of any load by direct connection of such load to the Companys system, Shipper may reduce its Transportation Demand under this Service Agreement or any other Service Agreement for firm transportation service between Shipper and Company by giving Company 30 days prior written notice of such reduction within six (6) months of the date Company initiates direct service to the industrial customer; provided, however, that any such reduction shall be applied first to the Transportation Demand under the Service Agreement with the shortest remaining contract term.
In order to qualify for a reduction in its Transportation Demand, Shipper must certify and provide supporting data that:
(i) |
The load was actually being served by Shipper with gas transported by Company prior to November 1, 1993. |
(ii) |
If the load lost by Shipper was served under a firm contract, the daily contract quantity shall be provided. |
(iii) |
If the load lost by Shipper was served under an interruptible contract, the average daily volumes during the latest twelve months of service shall be provided. |
Shipper may reduce its aggregate Transportation Demand under all its Service Agreements by an amount up to the daily contract quantity in the case of the loss of a
7
Service Agreement No. FSNG1
firm customer and/or up to the average daily deliveries during the latest twelve month period in the case of the loss of an interruptible customer. Such reduction shall become effective thirty days after the date of Shippers notice that it desires to reduce its Transportation Demand.
8.8 This Agreement supersedes and cancels the Service Agreement Nos. 866940 dated November 1, 1993, and 866941 dated November 1, 1993, as amended April 17, 2002, between the parties hereto.
IN WITNESS WHEREOF, this Agreement has been executed by the parties as of the date first written above by their respective duly authorized officers.
Attest/Witness: |
SOUTHERN NATURAL GAS COMPANY |
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By |
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Its |
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ALABAMA GAS CORPORATION |
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Its |
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Exhibit 10(e):
AMENDMENT TO SERVICE AGREEMENT
THIS AMENDMENT (Amendment) is entered into this 2nd day of December, 2005, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as Seller, first party, and ALABAMA GAS CORPORATION, hereinafter referred to as Buyer, second party.
WITNESSETH
WHEREAS, Seller and Buyer are parties to that certain Service Agreement, dated August 1, 1991, (Sellers Contract Number 1001983), under Sellers Rate Schedule FT (Service Agreement), pursuant to which Seller provides firm transportation service for Buyer up to a Transportation Contract Quantity (TCQ) of 103,500 dt of natural gas per day; and
WHEREAS, Buyer and Seller have mutually agreed to an extension of the primary term of the Service Agreement to be effective November 1, 2005;
WHEREAS, as part of the negotiation to extend the primary term of the Service Agreement, Buyer and Seller negotiated a reduction in the total contract quantity under the Service Agreement to be effective November 1, 2005;
NOW THEREFORE, Seller and Buyer hereby agree to amend the Service Agreement as follows to be effective November 1, 2005:
1. Article I of the Service Agreement is hereby deleted in its entirety and replaced by the following:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Sellers Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to a Transportation Contract Quantity (TCQ) of 73,500 dt per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 and, if applicable, Section 42 of the General Terms and Conditions of Sellers FERC Gas Tariff.
2. Article IV of the Service Agreement is hereby deleted in its entirety and replaced by the following:
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of August 1, 1991 and shall remain in force and effect until 9:00 a.m. Central Clock Time October 31, 2015 and thereafter until terminated by Seller or Buyer upon at least three (3) years written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Sellers reasonable judgment fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 32 of the General Terms and Conditions of Sellers Volume No. 1 Tariff. As set forth in Section 8 of Article II of Sellers August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et al., (a) pregranted abandonment under Section 284.221(d) of the Commissions Regulations shall not apply to any long term conversions from firm sales service to transportation service under Sellers Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service
AMENDMENT TO SERVICE AGREEMENT
(CONTINUED)
resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service.
3. Exhibit A to the Service Agreement is deleted in its entirety and replaced with Exhibit A attached hereto.
4. Except as herein amended, the Service Agreement shall remain in full force and effect pursuant to the terms thereof..
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be signed by their respective officers or representative thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE |
ALABAMA GAS CORPORATION |
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CORPORATION (SELLER) |
(BUYER) |
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By |
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By |
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Name: |
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Title: |
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Exhibit 10(f):
OCCLUDED GAS LEASE
by and between
UNITED STATES STEEL CORPORATION,
Lessor
And
TAURUS EXPLORATION, INC.,
Lessee
January 1, 1986
TABLE OF CONTENTS
ARTICLE |
PAGE | |||
1. |
DEFINITIONS |
3 | ||
2. |
GRANTING CLAUSE |
7 | ||
3. |
TERM |
9 | ||
4. |
ROYALTIES |
9 | ||
5. |
DEVELOPMENT OF LEASED PREMISES; DELAY RENTAL; MINIMUM ROYALTY |
10 | ||
6. |
PAYMENTS |
11 | ||
7. |
MEASUREMENT OF OCCLUDED GAS |
12 | ||
8. |
TAXES |
14 | ||
9. |
WATER |
14 | ||
10. |
DRAINAGE |
14 | ||
11. |
POOLING |
14 | ||
12. |
OPERATIONS; COORDINATION OF ACTIVITIES |
16 | ||
13. |
PRESERVATIN OF THE LEASED PREMISES |
20 | ||
14. |
PLUGGING AND RESTORATION |
20 | ||
15. |
INFORMATION, INSPECTION AND AUDIT, REPORTS |
21 | ||
16. |
FORCE MAJEURE |
22 | ||
17. |
INDEMNIFICATION, INSURANCE |
23 | ||
18. |
DEFAULT |
24 | ||
19. |
WARRANTY OF TITLE |
24 | ||
20. |
RECORDATION |
24 | ||
21. |
ASSIGNMENT |
25 | ||
22. |
NOTICES |
25 | ||
23. |
GENERAL PROVISIONS |
26 | ||
EXHIBITS |
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A-1 |
LIST OF SECTIONS OF THE USA RECTANGULAR SURVEY WITHIN WHICH THE LEASED PREMISES IS LOCATED |
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A-2 |
REPRESENTATIVE PLATS OF SECTIONS OF THE USA RECTANGULAR SURVEY DEPICTING THE LEASED PREMISES |
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B-1 |
MAP OF LEASED PREMISES DELINEATING THE OAK GROVE MINE AREA |
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B-2 |
MAP OF LEASED PREMISES--RESTRICTED AREAS AS OF JANUARY 1, 1985 |
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C |
ACCOUNTING PROCEDURE |
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D |
GAMMA RAY AND NEUTRON POROSITY LOG OF DRILL HOLE M-844 LOCATED IN THE SW 1/4 OF THE SW 1/4 OF SECTION 18, TOWNSHIP 18 SOUTH, RANGE 5 WEST |
2
OCCLUDED GAS LEASE
This Occluded Gas Lease (Lease) is made and entered into as of the 1st day of January, 1986, by and between UNITED STATES STEEL CORPORATION, a Delaware corporation (Lessor), and TAURUS EXPLORATION, INC., a Delaware corporation, (Lessee).
WITNESSETH:
ARTICLE 1
DEFINITIONS
As used in this Lease, the following terms shall have the meanings ascribed thereto:
1.1 Btu: one British Thermal Unit..
1.2 MMBtu: one million British Thermal Units
1.3 Developed Acreage: those portions of the Leased Premises that have been identified from time to time pursuant to Article 12.8.
1.4 Development Commitment Price: with respect to any year, the amount of the Wellhead Price that would be in effect on July 1 of said year if calculated pursuant to Article 1.22(a), substituting July 1 for January 1 in said Article each time it appears. For purposes of this calculation, the OCD-2 Rate in effect as of the date of the adjustment shall be the OCD-2 Rate in effect on such date without regard to any retroactive adjustments
3
1.5 Gross Heating Value: the number of Btus contained in one cubic foot of Occluded Gas saturated with water vapor and adjusted on a dry basis to 14.73 psia.
1.6 Initial Unit Investment: with respect to each Payout Unit, all reasonable costs incurred by Lessee in order to bring into production the wells included in the relevant Payout Unit, including (a) title work, drillsite location and preparation, (b) the drilling, testing, coring, coal analysis, logging, hydraulic fracturing, and equipping each well for production; and (c) a fair and reasonable allocation (not to exceed 90%) of the cost of building access roads. Other common utilities such as power lines will be allocated based on planned useage requirements. Costs chargeable to the Initial Unit Investment shall cease to accrue for each well within a Payout Unit as of the time the well commences production. In the case of a well judged not economical and abandoned before being brought into production, the cost of plugging will also be included in the Initial Unit Investment. All costs of the gathering, compression, treatment, and distribution systems are specifically excluded from the Initial Unit Investment.
1.7 Lease: this contract between Lessor and Lessee.
1.8 Leased Premises: all those certain lands situated in Jefferson and Tuscaloosa Counties, Alabama, containing a total of 124,000 acres, more or less, described in Exhibit A-l, and further identified on Exhibit A-2, both attached hereto and incorporated herein, limited to a depth of 80 feet below the base of the Black Creek Group Coal Seams as formed in and under such lands, which seams are more specifically identified on Exhibit D attached hereto and incorporated herein. The Leased Premises are contained within the area generally described on the map attached as Exhibit B-1.
1.9 Net Profits: with respect to each Payout Unit, an amount equal to the Average Wellhead Price multiplied by the quantity of Occluded Gas produced less applicable Operating Costs, royalties and those severance taxes paid by Lessee with respect to which no deduction is made against Lessors royalties pursuant to Article 8.
1.10 Oak Grove Mine Area: that portion of the Leased Premises designated Oak Grove Mine Area on Exhibit B-1, attached hereto and incorporated herein.
1.11 Occluded Gas: occluded natural gas produced from coal seams as referred to in Section 107(c)(3) of the Natural Gas Policy Act of 1978 and the Regulations promulgated by the Federal Energy Regulatory Commission (FERC) pursuant thereto as such Regulations may be amended from time to time, provided however, that gob gas shall not be deemed to be Occluded Gas for purposes of this Lease.
1.12 OCD-2 Rate: the total commodity rate from time to time in effect for gas delivered under rate schedule OCD-2 or its successor rate schedule, as published in the FERC Gas Tariff of the Southern Natural Gas Company. Except as expressly provided herein to the contrary, all payments, accounts or determinations based upon the OCD-2 Rate as of a specific date shall, in the
4
case of a retroactive adjustment to the OCD-2 Rate, be likewise adjusted to account for such retroactive adjustment. Should Southern Natural Gas Company discontinue the publication of the OCD-2 rate and its successor rate schedules, Lessor and Lessee shall meet to agree on an appropriate method by which the Wellhead Price then in effect and Treatment Factor then in effect will thereafter be adjusted.
1.13 Operating Costs: with respect to each Payout Unit, all reasonable costs incurred in operating and maintaining the relevant Payout Unit, including (a) the costs of complying with applicable local, state, and federal statutes, ordinances, rules, and regulations pertaining to the well operations; (b) all costs of lifting and producing Occluded Gas; (c) all costs incurred in connection with the workover or other remedial servicing of all wells drilled on the relevant Payout Unit; (d) all utility costs and ad valorem and production taxes directly associated with the well operations; (e) a fair and reasonable allocation (not to exceed 90%) of maintenance costs for access roads with such costs for other common utilities being based on actual usage; and (f) the costs of plugging and abandoning uneconomical wells to the extent not included in the Initial Unit Investment. Operating costs for each well within a Payout Unit will start when the well commences production. All costs of the gathering, compression, treatment, and distribution systems are specifically excluded from the Operating Costs. Also specifically excluded are all costs of interest, depletion, depreciation, and income taxes.
1.14 Operations: as defined in Section I.1. of Exhibit C.
1.15 Payout: that point in the production life of a Payout Unit when cumulative Net Profits equal 165% of the Initial Unit Investment.
1.16 Payout Unit: all wells spudded within a single calendar year.
1.17 Pooled Unit: as defined in Article 11.
1.18 Primary Term: the initial eight years of this Lease (January 1, 1986 through December 31, 1993).
1.19 psia: pounds per square inch, absolute.
1.20 Treatment Factor: the amount of $0.78 per MMBtu or such other amount that is in effect from time to time, adjusted: (a) as of January 1 of each year beginning January 1, 1987 upward by 20% of the difference between (1) 95% (to read 100% until the expiration of the first 5 years of this Lease or until Article 1.22(a)(i)[2] comes into effect, whichever comes first) of the OCD-2 Rate in effect as of said date and (2) the sum of the Wellhead Price under Article 1.22(a) and the Treatment Factor, both as in effect on the day prior to the adjustment; provided however, that the cumulative amount of all such increases shall not exceed $.01 per MMBtu times the number of years elapsed between the commencement of this Lease and date of the adjustment; and (b) as of the first day of each
5
month shall be adjusted by 5.5% of any increase or decrease in the Average Wellhead Price in effect for production from the immediately preceding month as compared to the Average Wellhead Price in effect for production from the second preceding month; in no case, however, shall the Treatment Factor be reduced other than as a result of this 1.20(b).
1.21 Undeveloped Acreage: that portion of the Leased Premises that is not Developed Acreage.
1.22 Wellhead Price:
(a) |
For Occluded Gas sold or transferred to an entity that is within the Energen group of related companies or that is a parent, subsidiary or affiliate of the Lessee, for Occluded Gas that is produced but not sold or transferred, and for Occluded Gas that is sold or transferred other than under conditions described in Article 1.22(b) below: |
(i) |
From the commencement of this Lease through December 31, 1990: |
[1] |
The Wellhead Price shall be $2.60 per MMBtu, or such other amount that is in effect from time to time, adjusted as of January 1 of each year beginning January 1, 1987, upward by 80% of the difference between (A) the OCD-2 Rate in effect as of said date and (B) the sum of the Wellhead Price under Article 1.22(a) and the Treatment Factor, both as in effect on the day prior to the adjustment; provided however, that the cumulative amount of all such increases shall not exceed $.04 per MMBtu times the number of years elapsed between January 1, 1986 and the date of the adjustment, and further provided that, if the Wellhead Price under this Article 1.22(a)(i)[1] is above $2.45 per MMBtu, it shall not exceed the OCD-2 Rate less Treatment Factor at the dates of adjustment, but in any case it shall not be less than $2.45 per MMBtu. |
[2] |
Notwithstanding the preceding Section [1], if at any time the OCD-2 Rate less Treatment Factor equals or exceeds 150% of the Wellhead Price defined in Article 1.22(a)(i)[1], the Wellhead Price shall thereupon become and thereafter be calculated as (A) 95% of the OCD-2 Rate less (B) the Treatment Factor, using said amounts that are from time to time in effect. |
6
(ii) |
After December 31, 1990: The Wellhead Price shall be calculated as (A) 95% of the OCD-2 Rate less (B) the Treatment Factor, using said amounts that are from time to time in effect. |
(b) |
For Occluded Gas sold or transferred to a bona fide third-party purchaser not affiliated with Lessee, pursuant to a sales contract arrived at through good faith, arms length negotiations and through which no entity is intending to take unfair advantage of the Lessor: |
The Wellhead Price shall be the price required to be paid under said sales contract, provided however that if the price stated in said sales contract includes transportation of the Occluded Gas beyond the wellhead, the Wellhead Price shall be the price required to be paid under said sales contract less the lesser of (i) the amount included in the sales contract that is intended to be compensation for the transportation services or (ii) the Treatment Factor then in effect.
1.23 Average Wellhead Price: the average of the Wellhead Prices for Occluded Gas calculated according to Articles 1.22(a) and 1.22(b), weighted according to the volumes of Occluded Gas produced subject to each of said Wellhead Prices during the month in question.
1.24 Restricted Areas: that portion of the Leased Premises from time to time designated by Lessor as Restricted Areas pursuant to Article 12.11.
ARTICLE 2
GRANTING CLAUSE
2.1 Subject to the further terms hereof and subject to the limitations herein contained, and in consideration of the royalties herein provided and the agreements of Lessee herein contained, Lessor hereby grants, leases and lets unto Lessee the Leased Premises for the sole purpose of investigating, exploring, prospecting, drilling for, and producing Occluded Gas, together with the right to make surveys on said land, establish and utilize facilities for the disposal of water in accordance with applicable laws and regulations, to install, build, operate and maintain roads, pipelines, power lines, telephone lines, compressor facilities and other structures thereon as may be necessary to produce, take care of, treat, transport, and own said Occluded Gas.
(a) Unless expressly stated to the contrary, the rights granted by this Lease shall extend only as necessary for the production and marketing of Occluded Gas occurring within the Leased Premises, and only to the extent of Lessors right to grant said rights.
7
(b) As to any tracts within the Leased Premises on which Lessor does not own the surface, Lessee shall be responsible for making any arrangements with the owners of the surface rights at Lessees sole expense. Lessee shall hold Lessor harmless against losses of any nature arising out of suits or claims by owners or alleged owners of surface rights which suits or claims are based on Lessees actions under said arrangements or this Lease.
2.2 Lessor excludes from this Lease all oil, gas (the word gas, as used herein, shall mean and include any gaseous substance except Occluded Gas, whether combustible or noncombustible, including by way of illustration but not by way of limitation, hydrogen sulfide) gob gas, condensate, distillate and sulfur found above, below, or within coal seams occurring within the Leased Premises.
2.3 Except for the rights granted to Lessee hereunder to commercially develop and produce Occluded Gas, which rights are exclusive except as to:
(a) gas produced from wells that are subject to the gas sales agreement between Southern Natural Gas Company and Lessor dated July 6, 1981, as amended;
(b) rights granted under, and operations and activities conducted pursuant to, that certain agreement between the Gas Research Institute (GRI) and Lessor dated March 1, 1984, as amended, the land subject to which is shown as Restricted Area on Exhibit B-2; and
(c) gas produced pursuant to the Coal Seam Gas Drainage Agreement between Methane Drainage Ventures and Lessor dated February 25, 1985, as amended; Lessor expressly reserves all rights with respect to the surface and subsurface of the Leased Premises for any and all purposes, including without limitation: ingress and egress; mining coal, whether or not said coal has been developed for the production of Occluded Gas; venting Occluded Gas from coal, whether by drilling or otherwise, for purposes other than the commercial production of same; conducting geological and other surveys; selling, leasing, or otherwise transferring interests in the Leased Premises; harvesting, storing, transporting and replanting timber; and exploring for, drilling, mining, producing, treating, storing and transporting any and all minerals, coal, oil and gas and surface materials other than those Leased hereunder, whether or not said activities involve the disturbance or destruction of coal seams.
2.4 The rights of Lessee hereunder shall be subject to all other rights, uses and easements affecting the Leased Premises, whether now existing or hereafter granted, and Lessees use of the Leased Premises shall not unreasonably interfere with such other rights, uses and easements.
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2.5 If Lessee discovers gas other than Occluded Gas in the Leased Premises as a result of its bona fide operations under this Lease to develop and produce Occluded Gas, the parties shall enter into good faith negotiations to grant Lessee a lease that would provide Lessee the right to develop, operate and produce the reserve of gas so discovered.
ARTICLE 3
TERM
3.1 Unless sooner terminated or longer kept in force under other provisions hereof, this Lease shall be in effect for a Primary Term of eight (8) years from the date hereof and thereafter (a) with respect to the Developed Acreage, for as long as Occluded Gas is produced in paying quantities, and (b) with respect to the Undeveloped Acreage, for as long as royalties are paid in accordance with Article 5.2.
3.2 Except as provided in Article 11 regarding Pooled Units, Lessee may, at any time, release all or any portion of the Undeveloped Acreage from the terms of this Lease by giving Lessor written notice of said action.
ARTICLE 4
ROYALTIES
4.1 Lessee covenants and agrees to pay to Lessor a royalty on all Occluded Gas produced from each Payout Unit on the Leased Premises as follows:
(a) |
Prior to Payout: |
one-tenth (1/10) of the Average Wellhead Price;
(b) |
After Payout: |
(i) |
Lessor shall have the option of continuing to receive the royalty provided in Article 4.1(a) above or four-tenths (4/10) of the Net Profits. |
(ii) |
Lessor shall evidence its election whether to exercise such option as to each Payout Unit by written notice to Lessee during the thirty-day period immediately following receipt from Lessor of a notice of Payout. The failure of Lessor to provide Lessee with written notice of its election during the thirty-day period shall constitute an election by Lessor to retain its one-tenth (1/10) royalty interest in the relevant Payout Unit. If Lessor elects to convert its royalty for any Payout Unit to four-tenths (4/10) of the Net Profits, the royalty provided in Article 4.1(a) above shall cease and terminate, as to such Payout Unit and such conversion shall become effective, as of the first day of the month following the month in which Payout occurred. |
9
(iii) |
If the calculation of Net Profits results in a negative number (Net Losses) during any royalty period for any Payout Unit as to which Lessor has elected a royalty of four-tenths (4/10) of Net Profits, royalty for said Payout Unit shall be zero for said royalty period. Net Losses shall not be netted with royalties or Net Profits from other Payout Units and Lessor shall not be required to share said Net Losses in any way except that Lessor may accumulate said Net Losses with Net Profits from the same Payout Unit for subsequent royalty periods for the purpose of calculating royalties payable with respect to said subsequent royalty periods. |
4.2 Notwithstanding the provisions of Article 4.1 (Royalties) and Article 7 (Measurement of Occluded Gas), royalty shall not accrue upon and Lessee need not measure any Occluded Gas that must be vented or flared. Lessee shall vent or flare Occluded Gas rather than shutting in any wells in areas that Lessor may from time to time designate, for purposes of degasifying coal that is mineable. Lessee may vent or flare Occluded Gas in any of its operations hereunder as it deems appropriate, consistent with good operating practice.
ARTICLE 5
DEVELOPMENT OF LEASED PREMISES;
DELAY RENTAL; MINIMUM ROYALTY
5.1 During the Primary Term, Lessee shall develop the Leased Premises as follows:
(a) |
During any year in which the Development Commitment Price is $2.60 or more per MMBtu, Lessee will drill, complete (including hydro-fracturing) and test (including attempted de-watering) a minimum of thirty wells. |
(b) |
During any year in which the Development Commitment Price is $2.45 or higher but less than $2.60 per MMBtu, Lessee will drill, complete (including hydro-fracturing) and test (including attempted de-watering) a minimum of twenty wells. |
(c) |
During any year in which the Development Commitment Price is less than $2.45 per MMBtu, Lessee will not be obligated to develop the Leased Premises. If under the provision of this Article 5.1(c) Lessee does not drill, complete (including hydro-fracturing) and test (including attempted de-watering) at least |
10
twenty wells, Lessee shall pay Lessor for each such year, as delay rental, $1.00 per Undeveloped Acre held under this Lease at the end of such year. Lessee at its option may however expend up to fifty (50%) percent of said delay rental on an exploration drilling program that is mutually agreed upon by the parties and conducted during the year in question, in lieu of paying said portion of the delay rental to Lessor.
(d) |
As to any year in which the Development Commitment Price is less than $2.45 per MMBtu, Lessor shall have the option of reinstating the development commitment specified in Article 5.1(b) by decreasing its royalty for the period July 1 through June 30 during which said Development Commitment Price is in effect by an amount equal to the difference between $2.45 per MMBtu and said Development Commitment Price. |
(e) |
Lessee shall notify Lessor of the Development Commitment Price not later than July 15 of each year, and Lessor shall have 15 days thereafter to exercise the option contained in Article 5.1(d). Failure of Lessor to timely exercise such option shall be deemed an election against exercising such option for the year in question. |
5.2 After the Primary Term, Lessee shall continue to abide by the obligations set forth in Article 5.1 or pay an annual minimum royalty equivalent to the royalty that would be paid on annual production volume of 4 million cubic feet per day at the royalty rate in effect pursuant to Article 1.22(a) as though all of said annual production volume had been produced on December 31 of the year in question. Said annual minimum royalty shall not be reduced by reason of release of less than 100% of any Undeveloped Acreage being held under the Lease. Any part of such payment not attributable to current production shall be considered advance royalty and shall be recoverable in the two years following, dollar-for-dollar against royalties due Lessor in either of said years over and above any minimum royalty obligation applicable to said years.
ARTICLE 6
PAYMENTS
All royalty payments shall be made on a monthly basis and delay rental and minimum royalty payments on an annual basis by Lessee to Lessor in accordance with the following:
6.1 Each payment shall be made by check payable to Lessor.
6.2 Each payment shall be received by Lessor on or before the appropriate due date:
(a) |
Due date for royalty payments shall be the last day of the month following the calendar month in which the Occluded Gas is produced. |
11
(b) |
Due date for delay rental and minimum royalty payments shall be the 30th day following the end of the the calendar year for which payment is made. |
6.3 Each payment shall be accompanied by a report referring to this Lease, specifying the Payout Unit and wells for which payment is made, and detailing the calculation used to determine the amount of the payment.
6.4 Each payment shall be made to Lessor at the following address or at such other address as Lessor may from time to time specify in writing for such purpose:
Manager-Southern Lands & Minerals
United States Steel Corporation
P. O. Box 599, B-100
Fairfield, AL 35064
Lessor shall give Lessee at least thirty (30) days written notice of any change in the address at which payments shall be made to Lessor.
6.5 Late payments shall bear interest compounded daily at the annual prime rate of interest in effect at Chase Manhattan Bank, N.A. on the due date of the delinquent payment.
ARTICLE 7
MEASUREMENT OF OCCLUDED GAS
7.1 The unit of volume for measurement of the Occluded Gas produced hereunder shall be one (1) cubic foot of gas at a base temperature of sixty (60) degrees Fahrenheit and at an absolute pressure of fourteen and seventy-three hundredths (14.73) psia. All fundamental constants, observations, records and procedures involved in determining and/or verifying the quantity and other characteristics of gas delivered hereunder, unless otherwise specified herein, shall be in accordance with the standards prescribed in Report No. 3 of the American Gas Association (AGA) as now and from time to time amended or supplemented. All measurements of Occluded Gas shall be determined by calculations in the terms of such unit. All quantities given herein, unless expressly stated, are in terms of such unit.
7.2 Lessee shall maintain and operate at its sole expense measuring stations located at each wellhead. Said measuring stations shall be equipped with turbine or rotary meters or other types of meters with totalizer as agreed to by Lessor and Lessee so as to accomplish the accurate measurement of volumes of Occluded Gas produced hereunder.
7.3 Lessor may at its option and expense install check meters for checking Lessees metering equipment and same shall be so installed as to not interfere with the operation of Lessees facilities.
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7.4 The specific gravity of the Occluded Gas flowing through the meter or meters shall be determined monthly by use of an AGA accepted gravitometer or by computing from fractional analysis of samples of the Occluded Gas taken at as many points as necessary to permit the calculation of an average specific gravity representative of all Occluded Gas produced hereunder. Specific gravity so determined will be used in calculating gas production for the month in which the tests are made.
7.5 The Gross Heating Value of the Occluded Gas shall be determined by taking continuous samples at as many points as necessary to permit the calculation of an average Gross Heating Value representative of all Occluded Gas produced hereunder. The sample may be run on a calorimeter or Gross Heating Value may be computed from fractional analysis of such sample. The result shall be applied to Occluded Gas produced during the month in which samples are taken.
7.6 Each party shall have the right to be present at the time of any installation, reading, cleaning, changing, repairing, inspecting, calibrating or adjusting done in connection with the others measuring equipment used in measuring deliveries hereunder. The records for such measuring equipment shall remain the property of the Lessee and shall be kept on file for a period of two (2) years, but upon request, each will submit to the others its records and charts, together with calculations therefrom subject to return within fifteen (15) days after receipt thereof. At least once each year Lessee shall calibrate the meters and instruments or cause same to be calibrated. Said meters shall be calibrated more frequently at any times inaccuracy is suspected. Lessee shall give Lessor sufficient notice in advance of such tests so that Lessor may, at its election, be present in person or by its representative to observe adjustments, if any, which are made. For the purpose of measurement and meter calibration, the atmosphere pressure shall be assumed to be fourteen and four-tenths (14.4) psia, irrespective of variations in natural atmospheric pressure from time to time.
7.7 If upon any test the metering equipment in the aggregate is found to be inaccurate by two percent (2%) or more, registration thereof or any payment based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy which is definitely known or agreed upon, or if not known or agreed upon, then for a period extending back one-half of the time elapsed since the previous calibration. Following any test, any metering equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately. If for any reason any meter is out of service or out of repair so that the quantity of Occluded Gas delivered through such meter cannot be ascertained or computed from the readings thereof, the quantity of Occluded Gas so delivered during such period the same is out of service or out of repair shall be estimated and agreed upon by the parties hereto upon the basis of the best available data, using the
13
first of the following methods which is feasible.
(a) |
By using the registration of any check measuring equipment of Lessor if installed and registering accurately. |
(b) |
By correcting the error if the percentage of error is ascertained by calibration tests or mathematical calculation. |
(c) |
By estimating the quantity of deliveries by deliveries during preceding periods under similar conditions when the meter was registering accurately. |
7.8 The measurement hereunder shall be corrected for deviation from Boyles Law at the pressure and temperatures under which Occluded Gas is delivered hereunder.
ARTICLE 8
TAXES
Lessee shall pay all taxes levied on the production, use, or sale of Occluded Gas produced from the Leased Premises, severance taxes and all taxes on the receipts therefrom or taxes due by reason of Lessees activities on the Leased Premises of whatever nature or kind, either Federal or State, or any subdivision thereof. Lessee shall pay ad valorem taxes levied upon its interest in the Leased Premises and on all of its improvements, fixtures and equipment. Lessor shall pay the ad valorem taxes levied upon its interest in the Leased Premises and one-tenth (1/10) of the severance taxes may be deducted by Lessee from royalties paid to Lessor for that Occluded Gas as to which royalties are paid on the basis of one-tenth (1/10) of the Average Wellhead Price.
ARTICLE 9
WATER
Lessee may with prior written consent of Lessor and at no additional cost to Lessor use non-potable water for its operations hereunder from any well, tank, reservoir or other watering place owned by Lessor. Such consent shall not be unreasonably withheld; fear of adverse labor consequences, in the sole opinion of Lessor, shall be deemed just cause for withholding such consent.
ARTICLE 10
DRAINAGE
Lessee agrees to drill such well or wells as would a reasonably prudent operator under the circumstances in order to protect the Leased Premises from drainage.
ARTICLE 11
POOLING
11.1 Lessee, with Lessors prior written consent, may pool or combine the Leased Premises with any other land, leased or owned by Lessee, which is contiguous or in the same block with
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the Leased Premises to establish drilling units for the production of Occluded Gas. If expansion of the drilling unit is required or permitted under any governmental rule or order for operations in connection with the production of Occluded Gas, or for obtaining the maximum allowable, any such drilling unit may, on Lessors prior written consent, be reformed to conform to the size so required or permitted. Lessee shall exercise the privilege to pool or combine land as to each drilling unit by executing the appropriate permit application forms and sending copies of same to Lessor with a request that the drilling so designed be approved within 15 days of receipt and, thereafter, Lessee shall file said application with the appropriate regulatory authority. Lessee, with Lessors prior written consent, may unitize one or more drilling units in accordance with the terms and conditions of Section 9-17-80 et seq., Code of Alabama (1975), pertaining to Unit Operations. Notwithstanding any other provision herein contained, after the expiration of the Primary Term hereof, operations on or production from a drilling unit or a unitized area or areas established under this Article 11 shall maintain this Lease in force only as to the land included in such drilling unit or unitized area or areas. Upon the pooling and/or unitization of less than all of the Leased Premises, this Lease shall be severed and considered as separate and distinct Leases. The Lease term and all the rights and obligations of the Lessee under this instrument shall apply separately to the pooled and unpooled acreage. A Pooled Unit established hereunder shall be unitized acreage as compared to the non-pooled and non-unitized acreage.
11.2 Any operations conducted on any part of such a drilling unit or unitized area shall be considered, for all purposes, to be operations conducted upon the Leased Premises. There shall be allocated to the Leased Premises within each drilling unit that proportion of the total production of Occluded Gas from the relevant drilling unit, that the number of surface acres in the portion of the Leased Premises included within such drilling unit bears to the total number of surface acres in such drilling unit or unitized area, and the production so allocated shall be considered for all purposes, including payment of royalty to be production of Occluded Gas from the land to which allocated in the same manner as though produced therefrom under the terms of this Lease. The same proportionate share shall be applied to determine:
(a) |
that portion of the development costs for the drilling unit that are deemed to be part of the Initial Unit Investment; |
(b) |
that portion of the Operating Costs for the drilling unit that are attributable to the Payout Units; and |
(c) |
that portion of each well on the drilling unit that will be counted toward satisfaction of the development obligation set forth in Article 5. |
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11.3 The formation of any drilling unit or unitized area hereunder which includes lands other than the Leased Premises shall not have the effect of exchanging or transferring any interest under this Lease between parties owning interests in the Leased Premises and parties owning interests in lands other than the Leased Premises. Neither shall it impair the right of a party to release or terminate this Lease as to all or any portion of the Leased Premises, except that Lessee may not so release as to any portion of the Leased Premises included within a drilling unit or unitized area while there are operations thereon for, or production of Occluded Gas therefrom unless all pooled and/or unitized leases are released as to all lands within the relevant drilling unit or unitized area. At any time while this Lease is in force, Lessee may dissolve any drilling unit or unitized area established hereunder by given written notice to Lessor, if at that time there is no production of Occluded Gas from the relevant drilling unit or unitized area and operations are not being conducted thereon for Occluded Gas. Subject to the provisions of this Article 11, a drilling unit or unitized area once established hereunder shall remain in force so long as any lease subject thereto shall remain in force.
11.4 If this Lease now or hereafter covers separate tracts, no pooling or unitization of royalty interests as between any such separate tracts is intended or shall be implied or result merely from the inclusion of such separate tracts within this Lease, but Lessee shall nevertheless have the right to pool or unitize as provided in this Article 11 with the consequent allocation of production as herein provided. As used in this Article 11.4, the term separate tract means any tract with royalty ownership differing, now or hereafter, either as to parties or amounts, from that as to any other part of the Leased Premises.
ARTICLE 12
OPERATIONS; COORDINATION OF ACTIVITIES
12.1 Lessor and Lessee shall from, time to time, meet to discuss their planned activities for the Leased Premises, and shall use their best efforts to coordinate their operations and activities in such a manner that neither party shall unreasonably interfere with other operations and activities which may then or in the future be conducted on the Leased Premises. In any case, however, the rights reserved hereunder to Lessor on the Leased Premises shall take precedence over the rights of Lessee hereunder, except to the extent otherwise expressly provided herein.
12.2 Lessee shall conduct recovery operations, including hydro-fracturing to recover Occluded Gas from all horizons and coal seams within each Payout Unit from which Occluded Gas can be economically recovered in Lessees sole judgment and shall develop the Leased Premises in an orderly manner to effectuate complete recovery of the Occluded Gas that can be economically recovered; provided however, that Lessee shall not produce from
16
horizons below the Mary Lee-Blue Creek group within the Oak Grove Mine Area without the express, prior written consent of Lessor. Lessee shall endeavor to fully develop the Oak Grove Mine Area prior to concentrating its efforts on developing other portions of the Leased Premises.
12.3 On or before September 1 of each year during the term of this Lease, Lessee shall furnish Lessor with a map showing the approximate geographic areas in which activities or operations are planned for the following year.
12.4 (a) At least forty-five (45) days prior to the commencement of the drilling of any well or wells on the Leased Premises, Lessee shall notify Lessor in writing of the proposed well location or locations. If Lessor objects to the proposed location of any wells, Lessor shall notify Lessee within thirty (30) days. The two parties shall then consult and determine suitable locations for the well or wells.
(b) Lessee shall not construct or install wells, roads, pipelines, surface equipment or surface installations on the Leased Premises without obtaining Lessors prior written approval as to location and timing of construction and installation, which approval shall not be unreasonably withheld. At any time, Lessor may require Lessee to relocate any pipelines and surface facilities installed hereunder, all at Lessors expense.
(c) Lessee shall bury all permanent pipelines below the surface of the ground if they would otherwise interfere with Lessors use of the surface. Such pipelines shall be buried at least thirty (30) inches below the surface of the ground or at such greater depth as may reasonably be required by Lessor to accommodate the specific use of the surface contemplated by Lessor.
12.5 No well shall be drilled by Lessee within two hundred (200) feet of any residence, barn, building, or similar structure now or hereafter owned or used by Lessor, or Lessors tenants or others permitted by Lessor to be on the Leased Premises.
12.6 Each year during February, Lessee shall furnish Lessor with an updated survey and reproducible Mylar-type map(s) showing the location on the Leased Premises as established by a registered surveyor of all wells drilled and of all pipe lines, tanks, roads, and other facilities placed or constructed thereon by Lessee or under Lessees direction during the preceding calendar year.
12.7 (a) Upon Lessors request, Lessee shall provide to Lessor information about the stimulation techniques used on the Leased Premises. If Lessor determines that such stimulation is detrimental to Lessors interest in the coal seam, Lessor shall notify Lessee. Lessor and Lessee shall then consult and determine an appropriate stimulation technique or practice sufficient to protect the coal seam. For the Mary Lee and the Blue Creek seams within the Oak Grove Mine Area and for such other seams within the Leased Premises as may be designated by
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Lessor as being mineable, it shall be deemed an acceptable practice to hydraulically fracture said seams simultaneously using a total fluid volume up to 150,000 gallons per well and any volume above 150,000 gallons per well shall not be used without the prior written consent of Lessor. For simultaneous fracturing of said seams, fluid pumping rates shall not exceed thirty (30) barrels per minute and bottom-hole pressure shall not exceed 2500 psi except with the prior written consent of Lessor.
(b) If, in its good faith judgment as a prudent coal operator, Lessor determines that any operations pursuant to this Lease are detrimental to the present or future mineability of any mineable coal seams, whether such harm is physical or due to regulatory considerations, Lessor may require that no further operations of Lessee be conducted in the seams and areas affected without the prior written consent of Lessor.
12.8 Each year during February, Lessee shall furnish Lessor a map identifying with respect to each well spudded within the preceding calendar year the acreage associated therewith which, by virtue of such identification, shall be deemed to be Developed Acreage under this Lease. The acreage so identified shall include the acreage actually developed by said well, to the best knowledge of the parties, and other lands contiguous therewith, whether actually developed or not, that will equal a total of 80 acres per well (a) unless Lessee can demonstrate that a greater number of acres is actually developed, in which case the acreage actually developed will be so identified, or (b) unless contiguous acreage is less than 80 acres, in which case only the contiguous acreage shall be so identified. Acreage so identified with respect to wells on a pooled unit shall be within the pooled unit only.
12.9 Based on information obtained pursuant to this Article 12, Lessor shall attempt to harvest timber from the Leased Premises in advance of Lessees operations. If Lessor is not able to harvest timber that must be cut to permit operations hereunder to proceed, Lessee shall have the right to cut such timber and proceed with its operations. If, however, Lessor had been provided with less than four (4) months notice of the exact location of the operations which require the cutting or destruction of timber by Lessee, Lessee shall reimburse Lessor for all such timber, provided however that as to any instance in which an aggregate of not more than one acre of timber is destroyed and as to any instance in which Lessee shall have given the requisite notice prior to destroying the timber, Lessee shall have no reimbursement obligation.
12.10 When Lessee is required by the terms of this Agreement to pay Lessor for damage to or loss of timber, both parties hereto will carry out a joint cruise to determine the volume and type of damaged or destroyed timber. Payment shall be made promptly to Lessor at the following rates:
(a) |
For mature timber not on plantations, the average price for Standing Timber of the type damaged |
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or destroyed in Area 2 of Alabama as published in Timber Mart South for the month in which the Timber is cut or destroyed shall be used to determine the amount owed for the Timber hereunder. In the event the publication of said average price shall be discontinued or the basis for its computation be so materially changed as to substantially misrepresent the condition of the market for timber of the type sold hereunder to the detriment of either party, the parties agree to negotiate in good faith to establish a substitute basis for computation of reimbursement in cases where said average price would otherwise be applicable. Should no such average price be published in a given month due to the lack of reported sales during said period, the most recently published average price at said time shall be used.
(b) |
For plantation timber of less than fifteen (15) years maturity, the amount shall be the cost of reforestation plus interest at the rate specified in Article 6.5. For plantation timber of fifteen (15) or more years maturity, the amount shall be the present value of the future harvest, based on prices in Timber Mart South as specified in Article 12.10(a) and discounted at a rate of ten percent (10%) per annum. |
12.11 Lessee agrees that it shall not conduct its operations upon portions of the Leased Premises where mining or other operations are active or planned and that are so designated by Lessor from time to time as Restricted Areas, which operations of Lessee would interfere with such mining or other operations, except as Lessor may approve in writing. Upon completion of such conflicting mining or other operations, the affected portions of the Leased Premises shall be made available for Lessees operations. Portions of the Leased Premises that are Restricted Areas at the commencement of this Lease are depicted on Exhibit B-2, attached hereto and incorporated herein. Lessee shall not be obligated to pay delay rental with respect to acreage that is designated a Restricted Area for any year during any portion of which said acreage is designated a Restricted Area.
12.12 Lessor shall provide Lessee annually on or before August 1 a copy of its then current mine plan(s) that project two (2) years. into the future for any mining activity to be conducted outside of any Restricted Areas. Should any of said plans be changed after Lessee has drilled a well hereunder in such a manner that Lessor must mine through Lessees well prior to Payout and prior to the planned date of mining at time the well was spudded, Lessor shall reimburse Lessee for 165% of that portion of the Initial Unit Investment that was attributable to said well, less the portion of said sum theretofore recovered
19
from Net Profits. Wells drilled in the path of the mine plan that are mined through without changes in the mine plan after the date the well was spudded shall not be the subject of reimbursement hereunder regardless of whether Payout has been achieved. Following notice from Lessor, Lessee shall in a timely fashion plug any wells that must be plugged to permit mining to proceed.
12.13 Lessor shall exercise its reserved right to develop the oil and gas estate in such a way that no oil and gas wells shall be drilled within five hundred (500) feet of any active wells drilled hereunder, unless otherwise agreed.
ARTICLE 13
PRESERVATION OF THE LEASED PREMISES
13.1 Lessee shall conduct all operations on the Leased Premises in compliance with all applicable laws and regulations, using good practices generally accepted in the industry and in such a manner as to do no unnecessary damage to the surface of the Leased Premises.
13.2 In the event any operations of Lessee under this Lease result in (i) any break in any lake, pond, canal, lateral or levee that results in a loss of water therefrom and any resulting damage to or destruction of any real or personal property of Lessor or of other tenants on the Leased Premises, (ii) any contamination of surface or subsurface water, (iii) any wear and tear on roads, culverts, bridges, canals, gates or other improvements, or (iv) damage to timber growing crops or livestock, Lessee shall promptly repair such damage that is repairable and shall promptly pay Lessor for all such other damage, regardless of whether Lessee acted negligently. If Lessee fails to repair in a timely fashion any damages that are repairable, Lessor may undertake such repairs at the expense of Lessee.
ARTICLE 14
PLUGGING AND RESTORATION
14.1 Lessee shall comply with all present and future laws, rules and regulations concerning the plugging and abandonment of coal seam degasification wells and shall, as a minimum requirement, unless waived by Lessor, cement each bore from bottom to top.
14.2 Lessee shall notify Lessor at least seven (7) working days prior to the beginning of any well plugging operation.
14.3 Lessee agrees, within three months of abandonment of each well drilled by it on the Leased Premises, to restore the surface of the Leased Premises affected by such well to as near the same condition as it was prior to the drilling of said well as is practicable and in accordance with applicable laws, regulations, and permits.
14.4 Lessee shall have the right, exercisable at any time during a period of one hundred eighty (180) days after the expiration of this Lease to remove all personal property and
20
fixtures placed by Lessee on the Leased Premises if Lessee is not in default under any of the provisions of this Lease. If Lessee fails to remove any such property with the time allowed, Lessor may remove and dispose of same at Lessees expense or, at Lessors option, the same shall become property of Lessor.
ARTICLE 15
INFORMATION, INSPECTION AND AUDIT, REPORTS
15.1 Lessee shall promptly furnish to Lessor any information reasonably requested by Lessor or Lessors agents or representatives with respect to operations on the Leased Premises. Lessor and Lessors agents or representatives shall at all times have full and free ingress and egress to and from all of Lessees operations on the Leased Premises for the purposes of inspecting Lessees installations and operations. Lessee shall not be liable for injury to Lessors agents engaged in such activities except for any of the same caused by negligence of Lessee or its agents, servants or employees. Lessor and Lessors authorized representatives shall also have the right, at all reasonable times and at Lessors sole cost and expense, to inspect and examine the books and records of Lessee, its subcontractors, successors and assigns, that relate to the Leased Premises, operations thereon, production of Occluded Gas therefrom, and the accounting for royalties and other sums or determinations under this Lease.
15.2 Lessee shall furnish Lessor with the following reports at the stated intervals:
(a) A production report detailing the quantity of Occluded Gas produced from the Leased Premises and from each well, the quantity of Occluded Gas flared or vented, the quantity of Occluded Gas sold and/or used from the Leased Premises, the sales price of such Occluded Gas and the calculation of the royalty rate shall accompany royalty payments.
(b) Within 5 days following the payment of royalties each month, Lessee shall prepare and mail a Payout Statement detailing the progress toward Payout for each Payout Unit through the production month for which royalties were paid. When Payout occurs on any Payout Unit, an appropriate Notice of Conversion Option will accompany each statement.
(c) Whenever Lessee submits or files a report, application, notice or other document with the State Oil and Gas Board of Alabama, a legible copy thereof.
15.3 Upon completion of any well or wells on the Leased premises, Lessee shall furnish to Lessor a full, true and complete copy of all logs performed in the relevant well. Lessor shall have the right to request Lessee to run additional logs at a time convenient to Lessee and at Lessors sole expense. Lessee shall not deny nor unduly delay the granting of said request; provided, however, that Lessee shall have the right to deny any such request if Lessee, in its sole judgment, determines that such requested additional logging would unduly jeopardize the relevant well or the horizon into which it has been drilled.
15.4 If Lessee takes samples of cores and cuttings, Lessor shall be permitted to inspect and sample same.
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ARTICLE 16
FORCE MAJEURE
16.1 This Lease shall not be terminated or subject to cancellation in whole or in part, nor shall Lessee be held liable in damages for failure of Lessee to carry out its obligations under this Lease, if such compliance is prevented by, or such failure is the direct result of an act of God, fire, storm, flood, insurrection, rebellion, riot, or rule or order of any governmental authority having jurisdiction in the premises. Such occurrences shall be considered to be events of force majeure hereunder. Loss of market shall not be considered to be an event of force majeure hereunder and no event of force majeure shall relieve Lessee of its obligations to make timely payments of royalty, delay rental and minimum royalty.
16.2 In the event of a condition of force majeure, Lessee shall give Lessor immediate written notice of the force majeure, which notice shall set forth the full particulars of the cause relied upon and an estimate of time required for the event to abate. While Lessee is prevented from complying with its obligations hereunder as the result of such cause, such obligations shall be suspended, but such cause shall, so far as possible, be remedied by due diligence on the part of the Lessee. Once the cause is eliminated, Lessee shall promptly recommence operations.
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16.3 Either party on prior written notice to the other may terminate this Agreement if an event of force majeure lasts longer than 360 consecutive days.
ARTICLE 17
INDEMNIFICATION, INSURANCE
17.1 (a) Lessee is an independent contractor under this Lease and this Lease shall not be construed to create any other relationship between Lessee and Lessor, including but not limited to, agency, partnership or joint venture, except as expressly provided.
(b) Except as otherwise specifically provided in the Lease, Lessee assumes all risk of bodily injury, death, and property damage from any cause whatsoever. Lessee shall indemnify, hold harmless and defend Lessor from and against any and all suits, actions, legal proceedings, claims, demands, court costs, litigation and reasonable attorneys fees in any manner caused by, arising from, incident to, connected with or growing out of Lessees obligations, activities and operations hereunder, except to the extent that such claims, demands, actions, damages, liabilities or expenses are occasioned by the neglect, acts or omissions of Lessor. This covenant and obligation shall survive the termination of this Lease as to occurrences arising during the term of this Lease or any extension thereof.
17.2 Lessee shall at all times during the term of this Lease and any extension thereof, maintain in effect comprehensive general liability insurance for bodily injury, including death, and property damage in the amount of $500,000 per occurrence. This policy shall cover, among other risks, the contractual liability of Lessee assumed under the indemnification provision of this Lease. Furthermore, Lessee shall have automobile liability insurance including owned, non-owned and hired vehicle coverage with limits of liability not less than $500,000 combined single limit for bodily injury and property damage claims. In addition, Lessee shall maintain excess (umbrella) liability insurance over the comprehensive general liability and automobile liability insurance coverage afforded by the primary policies described above, with minimum limits of $5,000,000 excess of the specific limits. If Lessee self-insures comprehensive general liability and/or automobile liability through the use of deductibles or self-insured retentions and does not maintain primary liability policies, Lessee shall maintain $5,000,000 of umbrella liability coverage in excess of its self-insured retentions for comprehensive general and automobile liability. Lessee shall furnish Lessor with an appropriate certificate of insurance within thirty (30) days of the execution hereof. The requirement for insurance hereunder does not in any way release Lessee of its indemnification obligations under this Lease and does not diminish or limit said obligations.
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ARTICLE 18
DEFAULT
18.1 In the event of failure of Lessee to pay any sum of money due Lessor under this Lease when the same becomes due, and upon the further failure of Lessee to pay all such sums, except to the extent they are the subject of a good faith dispute between Lessee and Lessor, within ten (10) days after receipt from Lessor of written notice of non-payment, this Lease may be terminated immediately upon notice of same given by Lessor to Lessee.
18.2 In the event Lessor considers that Lessee has failed to comply with any obligations hereunder other than the payment of money to Lessor, Lessor shall notify Lessee in writing, setting out specifically in what respects Lessee is alleged to have breached this Lease. If Lessee fails to either cure said breach or commence the curing of same within thirty (30) days after receipt of said notice and diligently to complete such curative measures, this Lease may be terminated immediately upon notice of same given by Lessor to Lessee.
18.3 The service of a notice of non-payment or a notice of non-compliance shall be precedent to the bringing of any action by Lessor on this Lease for such causes, and no action other than an action for injunctive relief may be brought until the lapse of the appropriate period of time following Lessees receipt of such a notice.
ARTICLE 19
WARRANTY OF TITLE
19.1 Lessor hereby disclaims representations and/or warranties of title, express or implied, in relation to the Leased Premises, the Occluded Gas and any other matters regarding this Lease. Depiction of ownership of the Leased Premises herein and on exhibits hereto are advisory only and shall not constitute a warranty of title. For purposes of ascertaining title, Lessee shall have access, at reasonable times and at no expense to Lessor, to conveyance documents, abstracts and other pertinent property records in the possession of Lessor.
19.2 If Lessor owns an interest in any part or all of the Occluded Gas or other substance leased hereunder that is less than the full interest therein, royalties due hereunder with respect to such Occluded Gas or other substance shall be reduced proportionately.
ARTICLE 20
RECORDATION
At or promptly following the execution of this Lease, Lessor and Lessee shall execute recordable instruments that will serve as notice of the existence of this Lease. Any recording of such documents shall be accomplished by and at the expense of Lessee. Upon the termination of this Lease or the release of any portion of the Leased Premises from the terms of this Lease, Lessee shall at its sole cost and expense execute and file of record a proper
24
release indicating which portions of the Leased Premises are so affected and shall execute any other documents in evidence thereof that are reasonably requested by Lessor. Upon filing of record any documents pertaining to the Leased Premises, Lessee shall supply Lessor a copy of same, complete with recording data.
ARTICLE 21
ASSIGNMENT
21.1 The Lessee shall not transfer, delegate or assign its rights or obligations hereunder or any part hereof without the prior written consent of Lessor and Energen Corporation, which consents shall not be unreasonably withheld; and if written consents are given, no subsequent transfer, delegation or assignment shall be made without similar written consents. A default on any transferred, delegated or assigned portion of the Lease shall be considered a default on the entire Lease that shall be governed by Article 18.
21.2 In the event of an assignment, transfer, delegation or sublease hereunder, Lessee shall remain directly liable to Lessor for the faithful performance of this Lease and for the acts and omissions of all transferees, assignees, delegatees, sublessees and other entities granted rights hereunder by Lessee.
21.3 Lessor, on written notice to Lessee, may freely sell, transfer, assign or delegate its rights and obligations hereunder, subject to Lessees rights and obligations hereunder.
ARTICLE 22
NOTICES
22.1 All notices, consents, approvals, requests, demands, and other communications required or permitted to be given pursuant to this Lease or in connection with the operations contemplated hereunder shall be in writing and shall be mailed postage prepaid, registered or certified mail with return receipt requested (primary addressee only), to Lessor and Lessee at the following addresses:
If to Lessee:
(a) |
primary addressee: |
President
Taurus Exploration, Inc.
Suite 400, 1918 First Ave. N.
Birmingham, AL 35203
(b) |
with copy to: |
R. J. Patzke
Executive Vice President Energen
Corporation
2101 Sixth Ave. N.
Birmingham, AL 35203
If to Lessor:
(a) |
primary addressee: |
Director Resource Management and
Geological Investigations
United States Steel Corporation 600 Grant Street
Pittsburgh, Pennsylvania 15230
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(b) |
with copies to: |
(1) |
Manager-Southern Lands & Minerals |
United States Steel Corporation
P. O. Box 599, B-100
Fairfield, AL 35064
(2) |
General Manager-Southern Division |
U. S. Steel Mining Co., Inc.
P. O. Box 599, B-100
Fairfield, AL 35064
Any notices given in accordance with the provisions of this Section 22.1 shall be effective upon receipt by the primary addressee to whom such notice is directed.
22.2 Either party may change its primary and copy addresses by providing written notice of same to the other party in the manner provided in Section 22.1.
ARTICLE 23
GENERAL PROVISIONS
23.1 This Lease shall be governed by the laws of the State of Alabama and shall be subject to all applicable State and Federal laws and all valid orders, rules and regulations of public bodies having jurisdiction over this Lease. In the event any provision of this Lease is, or the operations contemplated hereby are found to be, inconsistent with or contrary to any such laws, rules, or regulations, the latter shall be deemed to control. Thereafter, this Lease shall be regarded as modified to the extent required to make it inoffensive to said laws, rules or regulations, and as so modified, shall continue in full force and effect.
23.2 All accounting computations performed in connection with the calculation of Payout, Net Profits, Initial Unit Investment, and Operating Costs shall be performed on an accrual accounting basis in accordance with Exhibit C, attached hereto and incorporated herein, in accordance with generally accepted accounting principles of the oil and gas industry.
23.3 No failure of a party to enforce a right or obligation contained in this Lease shall be deemed a waiver of subsequent breaches, whether similar or dissimilar.
23.4 Lessors remedies provided for hereunder are cumulative, not exclusive, and shall not affect the availability to Lessor of other remedies in equity or law.
23.5 This Lease constitutes the entire agreement between the parties and supersedes any and all other written or oral agreements or understandings between the parties concerning the subject matter hereof. No modification or amendment of the terms and provisions of this Lease shall be effective unless in writing and signed by Lessor, Lessee and Energen Corporation.
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23.6 The article headings contained herein are inserted for convenience only and shall not control or affect the meaning or construction of any provision hereof. Article numbers used herein refer to Articles of this Lease unless otherwise specifically identified.
23.7 The parties hereto agree to execute such additional instruments, agreements, or documents as may be necessary to effectuate the intentions of this Lease.
23.8 This Lease may be executed in multiple counterparts, each of which shall constitute an original hereof for all purposes, and all of which when taken together shall constitute a single agreement.
IN WITNESS WHEREOF, this Lease is executed and sealed by Lessor and Lessee in duplicate originals as of the day and year first above written.
ATTEST: |
UNITED STATES STEEL CORPORATION |
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By: |
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Assistant Secretary |
G. Colombari |
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Senior Vice President- |
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Steel Related Resources |
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ATTEST: |
TAURUS EXPLORATION, INC. |
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By: |
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Asst. Secretary |
E. Duncan Hamilton |
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President |
FIRST AMENDMENT
TO
OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into as of the 30th day of April , 1987, by and between USX CORPORATION, a Delaware corporation which was formerly known as United States Steel Corporation (Lessor) and TAURUS EXPLORATION, INC., a Delaware corporation (Lessee).
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WITNESSETH:
WHEREAS, Lessor and Lessee entered into an Occluded Gas Lease dated January 1, 1986, pertaining to lands in Jefferson and Tuscaloosa Counties, Alabama; and
WHEREAS, Lessor and Lessee desire to amend the Occluded Gas Lease as hereinafter set forth.
NOW THEREFORE, Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
1. Section 1.4 of the Occluded Gas Lease shall be amended to read in its entirety as follows:
1.4 Development Commitment Price: With respect to any year, the amount of the Wellhead Price that would have been in effect on September 1 of the preceding year if it had been calculated pursuant to Article 1.22(a), substituting September 1 for January 1 in said Article each time it appears. For purposes of this calculation, the OCD-2 Rate in effect as of said September 1 shall be the OCD-2 Rate in effect on such date without regard to any retroactive adjustments.
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2. Section 1.22(a)(i)[l1 of the Occluded Gas Lease shall be amended to read in its-entirety as follows:
[1] |
The Wellhead Price shall be $2.60 per MMBtu during 1986 for purposes of determining the Lessees royalty Obligation to Lessor. Thereafter, through December 31, 1990, subject however to the paramount provisions of paragraph [2] below, the Wellhead Price shall be the amount of the OCD-2 Rate less Treatment Factor as said amounts are in effect from time to time, subject however to said Wellhead Price being a minimum of $2.45 per MMStu and subject further to said Wellhead Price being a maximum of $2.60 plus the product of $.04 times the number of full years that have expired between the effective date of this Lease and the date in question. Lessor and Lessee agree that $2.45 shall constitute a floor only for purposes of determining Lessees royalty obligation to Lessor through December 31, 1990, and shall not constitute a minimum floor for purposes of establishing Lessees Development Commitment Price. |
3. Section 1.22(a) of the Occluded Gas Lease shall be amended to add thereto a new Section 1.22(a)(iii), which shall read as follows:
(iii) |
For each month during the term of this Lease beginning January 1987, the Wellhead Price shall be determined under this Section 1.22(a) using the OCD-2 Rate in effect for the first day of said month and shall be adjusted retroactively when necessary to reflect any retroactive changes to the OCD-2 Rate. The Treatment Factor used in said calculations shall likewise be the Treatment Factor determined as of the first day of said month, as set forth in Section 1.20. |
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4. Section 5.1(e) of the Occluded Gas Lease shall be amended to read in its entirety as follows:
(e) Lessee shall notify Lessor not later than September 15 of each year of the Development Commitment Price that will be in effect with respect to the ensuing year, and Lessor shall have 15 days thereafter to exercise the option contained in Article 5.1(d). Failure of Lessor to timely exercise such option shall be deemed an election against exercising such option for the year in question.
5. Article 5 of the Occluded Gas Lease shall be amended to add thereto a new Section 5.3, which shall read as follows:
5.3 In any of the years 1987,1988, 1989 or 1990, should Lessee drill, complete (including hydro-fracturing), and test (including attempted de-watering) any wells in excess of the number of wells that are required pursuant to this Article 5 to be so drilled, completed and tested (considering for this purpose only those wells which are operated and produce in paying quantities for not less than thirty {30) days, whether or not said thirty days occur during the year in question), Lessee may credit said number of wells in excess of the required number against the number of wells required to be drilled, completed and tested in any subsequent year during the Primary Term. Lessee shall notify Lessor in writing of the application of any of said credits at the time it chooses to apply the credits. Lessor and Lessee agree that Lessees drilling commitment obligation for calendar years 1986 and 1987 shall be a total of sixty (60) wells.
6. The Leased Premises of the Occluded Gas Lease as defined in Section 1.8 is amended to include therein certain lands in Sections I and 2 of Township 19 South, Range 6 West, as more fully described in Attachments 1, 2 and 3 to this First Amendment to Occluded Gas Lease, as though said lands were part of the Leased Premises as of January 1, 1986. Exhibit A-1 shall be amended to add thereto the information appearing on said Attachment 1 and Exhibit A-2 shall be amended to include therein said Attachments 2 and 3.
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7. Article 2 of the Occluded Gas Lease shall be amended to add thereto a new Section 2.6 which shall read as follows:
2.6 Anything in this Lease to the contrary notwithstanding, the rights of Lessee under this Lease to commercially develop and produce Occluded Gas shall be deemed non-exclusive with regard to the following lands to the extent they are contained within the Oak Grove Mine Area:
Township 18 South, Range 5 West
Section 31
Township 18 South, Range 6 West
Section 36
Township 19 South, Range 5 West
Section 6
Township 19 South, Range 6 West
Sections 1, 2, 3, 4, 9 and 10
Lessor, its contractors, successors and assigns, shall have the full right, concurrent with Lessee, to do any or all things within said lands as Lessee is empowered to do under this Lease.
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IN WITNESS WHEREOF the undersigned have hereunto set their hands and seals as of the year and date first above written.
USX CORPORATION Attest: |
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By |
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Assistant Secretary |
C. A. Corry, |
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President |
U.S. Diversified Group |
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TAURUS EXPLORATION, INC. Attest: |
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By |
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By |
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Secretary |
E. Duncan Hamilton, President |
SECOND AMENDMENT TO OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into as of the 1st day Of January , 1989 , by and between USX CORPORATION, a Delaware corporation, formerly known as United States Steel Corporation (Lessor) and TAURUS EXPLORATION, INC., a Delaware corporation (Lessee).
W I T N E S S E T H:
WHEREAS, Lessor and Lessee entered into an Occluded Gas Lease dated January 1, 1986, pertaining to lands in Jefferson and Tuscaloosa Counties, Alabama; and
WHEREAS, Lessor and Lessee amended said Occluded Gas Lease on April 30, 1987; and WHEREAS, Lessor and Lessee desire to further amend the Occluded Gas Lease as hereinafter set forth.
NOW THEREFORE, Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
1. The Leased Premises of the Occluded Gas Lease, as defined in Section 1.8 as amended, is further amended to include therein certain lands in Section 12 of Township 18 South, Range 8 West, containing a total of 155.30 acres, more or less, as more fully described in Attachments 1 and 2 to this Second Amendment to Occluded Gas Lease, as though said lands were part of the Leased Premises as of January 1, 1986. Exhibit A-1 shall be amended to add thereto the information appearing on said Attachment 1 and Exhibit A-2 shall be amended to include therein the map marked Attachment 2.
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2. The Leased Premises of the Occluded Gas Lease, as amended, as defined in Section 1.8 is further amended to delete therefrom certain lands in Section 31, Township 19 South, Range 6 West, containing a total of 120 acres, more or less, south and west of fault, and Attachments 3 and 4 to this Second Amendment to Occluded Gas Lease show the correct lands covered in said Section 31. Exhibit A-1, marked Attachment 3, shall be amended to correct the description of the lands covered in said Occluded Gas Lease, and Exhibit A-2 shall be amended to correct the information appearing on the map marked Attachment 4.
3. The Leased Premises of the Occluded Gas Lease, as amended, as defined in Section 1.8 is further amended to delete the Pratt Seam coal and Coal Seam Gas in parts of Sections 7, 17 and 18, Township 17 South, Range 4 West, and Attachments 5 and 6 to this Second Amendment to Occluded Gas Lease show the correct lands covered in said Sections 7, 17 and 18. Exhibit A-1 shall be amended to correct the description of the lands appearing on said Attachment 5 and Exhibit A-2 shall be amended to correct the information appearing on the map marked Attachment 6.
4. All other terms and conditions of said Occluded Gas Lease dated January 1, 1986, as amended, except as hereby further amended, shall remain unchanged and in full force and effect.
5. This Second Amendment to Occluded Gas Lease shall become effective upon the date of execution hereof and shall continue in effect until the termination or expiration of said Occluded Gas Lease, as amended, dated January 1, 1986.
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IN WITNESS WHEREOF, the parties hereto have executed this Second Amendment to Occluded Gas Lease, in duplicate, on the day and year first above written.
ATTEST: |
USX CORPORATION |
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By |
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Assistant Secretary |
Its |
General Manager-Administration |
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and Group Comptroller |
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ATTEST: |
TAURUS EXPLORATION, INC. |
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By |
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Assistant Secretary |
Its |
Vice President-Methane Operations |
THIRD AMENDMENT
TO
OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into as of the 1 st day of June , 1990, by and between USX CORPORATION , a Delware corporation which was formerly known as United States Steel Corporation (Lessor) and TAURUS EXPLORATION, INC. , an Alabama corporation (Lessee).
WITNESSETH:
WHEREAS , Lessor and Lessee entered into an Occluded Gas Lease dated January 1, 1986, pertaining to lands in Jefferson and Tuscaloosa Counties, Alabama; and
WHEREAS , Lessor and Lessee have previously amended the Lease by amendments dated April 30, 1987 and January 1, 1989; and
WHEREAS , Lessor and Lessee desire to make a third amendment to the Occluded Gas Lease as hereinafter set forth.
NOW THEREFORE , Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
1. Paragraph 1.25 is hereby added to Article 1 of the Occluded Gas Lease as follows:
1.25 Gob Gas: That gas which is liberated and accumulates within the highly fractured collapse zone as a result of second mining of cola seams. Gob gas does not include coal removed or disposed of for reasons of safety of the mining operations nor does it include coal seam gas leased
34
to Taurus Exploration, Inc. (Taurus). Coal Seam Gas (as defined for purposes of this Lease) is occluded natural gas located in the coal seams prior to underground mining and as defined in Paragraph 1.11. For the purposes of this definition Gob Gas will be considered only that gas produced from a well after second mining has passed directly beneath the well. The term second mining includes all kinds of underground mining, including technologies not yet developed, which result in the collapse of strata overlying the coal beds and includes, but is not limited to full or partial pillar mining, short and longwall mining,
2. Paragraph 2.2 of Article 2 of the Occluded Gas Lease is amended in its entirety as follows:
2.2 Lessor excludes from this lease all oil, gas (the word gas as used herein, shall mean and included any gaseous substance except Occluded Gas, whether combustible or noncombustible, including by way of illustration but not by way of limitation, hydrogen sulfide) gob gas, condensate, distillate, and sulfur found above, below, or within underground mine works for the purpose of degasifying coal seams prior to underground mining operations.
3. Paragraph 2.3 of Article 2 of the Occluded Gas Leas shall be amended in its entirety as follows:
2.3 Except for the rights granted to Lessee hereunder to commercially develop and produce Occluded Gas, which rights are exclusive except as to:
(a) |
gas produced from wells that are subject to the gas sales agreement between Southern Natural Gas Company and Lessor dated July 6, 1981, as amended; |
(b) |
rights granted under and operations and activities conducted pursuant to, that certain agreement between the Gas Research Institute (GRI) and Lessor dated March 1, 1984, as amended, the land subject to which is shown as Restricted Area on Exhibit B-2; and |
(c) |
gas produced pursuant to the Coal Seam Gas Drainage Agreement between Methane Drainage Ventures and Lessor dated February 25, 1985, as amended; |
Lessor expressly reserves all rights with respect to the surface and subsurface of Leased Premises for any and all purposes, including without limitation: ingress and egress; mining coal, whether or not said coal has been developed for the production of Occluded Gas; production of gas from horizontal boreholes as described in Paragraph 2.2 hereinabove, venting Occluded Gas from coal, whether by drilling or otherwise, for purposes other than commercial production of same; conducting geological and other surveys; selling, leasing, or otherwise transferring
35
interests in the Leased Premises; harvesting, storing, transporting and replanting timber; and exploring for, drilling, mining, producing, treating, storing and transporting any and all minerals, coal oil and gas and surface materials other than those Leased hereunder, whether or not said activities involve the disturbance of destruction of coal seams.
The parties hereto further agree that the foregoing amendment to the Occluded Gas Lease shall be effective on the year and date first above written and shall not have retroactive effect.
IN WITNESS WHEREOF the undersigned have hereunto set their hands and seals as of the year and date first above written.
ATTEST: |
USX CORPORATION |
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By: |
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Its: |
General Manager |
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Administration and Group Comptroller |
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U.S. Diversified Group |
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TAURUS EXPLORATION, INC. |
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ATTEST: |
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By: |
|
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John S. Wallace |
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Its: |
Vice President Methane Operations |
FOURTH AMENDMENT
TO
OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into as of the 11 th day of December , 1990, by and between USX CORPORATION , a Delaware corporation which was formerly known as United States Steel Corporation (Lessor ) and TAURUS EXPLORATION, INC., an Alabama corporation ( Lessee ).
WITNESSETH:
WHEREAS, Lessor and Lessee entered into an Occluded Gas Lease dated January 1, 1986, pertaining to lands in Jefferson and Tuscaloosa Counties, Alabama; and
WHEREAS, Lessor and Lessee have previously amended the Lease by amendments dated April 30, 1987, January I, 1989, and June 1, 1990; and
WHEREAS, Lessor and Lessee desire to make a fourth amendment to the Occluded Gas Lease as hereinafter set forth.
36
NOW THEREFORE, Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
Paragraph 1.6 of Article 1 of the Occluded Gas Lease shall be amended to read as follows:
1.6 Initial Unit Investment: With respect to each Payout Unit, all reasonable costs incurred by Lessee in order to bring into production the wells included in the relevant Payout Unit, including (a) title work, drill site location and preparation, (b) the drilling, testing, coring, coal analysis, logging, hydraulic fracturing, and equipping each well for production; and (c) a fair and reasonable allocation (not to exceed 90%) of cost of building access roads. Other common utilities such as power lines will be allocated based on planned usage requirements. The Initial Unit Investment shall include capital well costs booked in accordance with generally accepted accounting principles (GAAP). Under GAAP, capital well costs are defined as investments (expenditures) in wells (facilities) expected to provide continuing value over a period of more than one year. All expenditures required to drill, complete (fracture), equip , and pump a well prior to first commercial production are considered to be capital . Expenditures after first commercial production for equipment expected to provide value over a period of longer than one year or for completion of additional pay zones are considered to be capital costs under G.AAP. However , after initial production, replacement or repair of previously installed capital equipment and/or recompletion of a previously completed pay zone would be considered to be operating expense. In accordance with GAA.P , capital well costs incurred after initial production such as winterization and water disposal equipment are chargeable to the initial unit investment. Also in accordance with GAAP, items such as workover costs and pump replacements shall cease to accrue to the initial unit investment at the point in time in which gas sales begin from each well. In the case of a well judged non-economical and abandoned before being brought into production, the cost of plugging will also be included in the Initial Unit Investment. All costs of the gathering, compression, treatment, and distribution systems are specifically excluded from the Initial Unit Investment.
Once a given Payout Unit has reached payout , any additions to the capital investment for any well within said Payout Unit will be treated as operating expenses for the net profits calculations .
Paragraph 1.8 of Article 1 of the Occluded Gas Lease shall be amended to read as follows:
1.8 Leased Premises: All those certain lands situated in Jefferson and Tuscaloosa Counties, Alabama, containing a total of 124,000 acres, more or less, described in Exhibit A-1, and further identified on Exhibit A-2, both attached hereto and incorporated herein, limited to a depth of 80 feet below the base of the Black Creek Group Coal Seams more specifically identified on Exhibit D attached hereto and incorporated herein, The Leased Premises are contained within the area generally described on the map attached as Exhibit B-1. Notwithstanding the above, Lessee shall have the right to drill up to three hundred (300 ) feet below the base of the Black Creek Group Coal Seams in order to establish a sump for the wells drilled under the terms of this lease.
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Paragraph 1.9 of Article 1 of the Occluded Gas Lease shall be amended to read as follows:
1.9 Net Profits: With respect to each Payout Unit before Payout, an amount equal to the Average Wellhead Price multiplied by the quantity of Occluded Gas produced less applicable Operating Costs, royalties and those severance taxes paid by Lessee with respect to which no deduction is made against Lessor s royalties pursuant to Article 8. After Payout, an amount equal to the Average wellhead Price multiplied by the quantity of Occluded Gas produced less applicable Operating Costs, Capital Well Costs, royalties paid to lessee, and severance taxes paid by Lessee with respect to which no deduction is made against Lessor s royalties.
Paragraph 1.16 of Article 1 of the Occluded Gas Lease shall be amended to read as follows:
1.16 Payout Unit: All wells spudded within a single calendar year. Notwithstanding the above, in the event Lessee assigns all or a portion of this Occluded Gas Lease pursuant to Article 21 , Lessee and its assignee may establish separate Payout Units for their respective accounts. One of said Payout Units shall consist of the wells spudded within a single calendar year on any acreage not made a part of the assignment. The other Payout Unit shall consist of wells spudded within a single calendar year on any acreage which has been assigned. The separation of Payout units shall be retroactive to January 1, 1988.
Paragraph 1.20 of Article 1 of the Occluded Gas Lease shall be amended to read as follows:
1.20 Treatment Factor: as used herein, the amount determined below to allow Lessee to recover all costs of obtaining and/or constructing facilities that are not included in the Payout account, i.e for gathering , compression, treatment dehydration, and transportation to the delivery point at which gas enters either an interstate pipeline or the Alagasco system The Treatment Factor shall be the amount of $0.78 per MMBtu or such other amount that is in effect from time to time, adjusted; (a) as of January 1 of each year beginning January 1, 1987 upward by 20% of the difference between (1) 95% (to read 100% until the expiration of the first 5 years of this Lease or until Article 1.22(a) (8) [2] comes into effect, whichever comes first) of the OCD-2 Rate in effect as of said date and (2) the sum of the Wellhead Price under Article 1.22(a) and the Treatment Factor, both as in effect as of the day prior to the adjustment; provided however, that the cumulative amount of all such increases shall not exceed $.01 per MMBtu times the number of years elapsed between the commencement of this Lease and date of the adjustment; and (b) as of the first day of each month shall be adjusted by 5.5% of any increase or decrease in the Average Wellhead Price in effect for production from the immediately preceding month as compared to the Average wellhead Price in effect for production from the second preceding month; in no case, however shall the Treatment Factor be reduced other than as a result of this 1.20(b).
Paragraph 1.22(b) of Article 1 of the Occluded Gas Lease shall be amended to read as follows:
(b) For Occluded Gas sold or transferred to a bona fide third party purchaser not affiliated with Lessee, pursuant to a sales contract arrived at through good faith, arm s length negotiations and through which no entity is intending to take unfair advantage of the Lessor:
The Wellhead Price shall be the price required to be paid under said sales contract, provided however, that if the price stated in said sales contract includes transportation of the Occluded Gas beyond the wellhead, the Wellhead Price shall be the price required to be paid under said sales contract less the Treatment Factor then in effect.
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Paragraph 7.2 of Article 7 of the Occluded Gas Lease shall be amended to read as follows:
7.2 Lessee shall maintain and operate at its sole expense measuring stations located at each wellhead. Said measuring stations shall be equipped with turbine or rotary meters or other types of meters with totalizer as agreed to by Lessor and Lessee so as to accomplish the accurate measurement of volumes of Occluded Gas produced hereunder. To avoid the expense of wellhead temperature compensation equipment, Lessee may allocate back to the individual well the full production stream, which includes sendout on the discharge side of the compressor plus fuel. Such allocation will be based on each wellhead meters production as a percentage of total.
An example to calculate the allocation to a well is as follows:
Assume:
Number of wells delivering gas to a compressor station = 10
Quantities Measured at Wellheads
Well 1 5,000 Mcf
2 6,000 Mcf
3 6,500 Mcf
4 6,800 Mcf
5 6,800 Mcf
6 7,000 Mcf
7 7,200 Mcf
8 7,600 Mcf
9 8,000 Mcf
10 8,500 Mcf
Fuel Used = 4,200 Mcf
Send Out = 65,800
Then:
Sum of Wells = 69,400
Sum of Fuel & Send out = 70,000
(Sum of Fuel & Send Out) divided by Sum of Wells = 1.0086
39
Therefore:
Allocated Wellhead Production =
Well 1 5,000 x 1.0086 = 5,043
2 6,000 x 1.0086 = 6,052
3 6,500 x 1.0086 = 6,557
4 6,800 x 1.0086 = 6,858
5 6,800 x 1.0086 = 6,858
6 7,000 x 1.0086 = 7,060
7 7,200 x 1.0086 = 7,263
8 7,600 x 1.0086 = 7,666
9 8,000 x 1.0086 = 8,069
10 8,500 x 1.0086 = 8,674
70,000
Paragraph 7.9 is hereby added to Article 7 as follows:
7.9 The measurement and testing provisions of this Article 7 shall apply to all meters used hereunder including but not limited to wellhead, fuel and send out meters.
Article 12.12 shall be amended by adding the following example calculation:
Assume: Initial Unit = 20 Wells
Initial Unit Investment (IUI) = $2,000,000
Number of wells qualifying for mine through = 1
Net Profits (NP) at time of mine through = $,500,000
Calculate: Initial Unit Investment per well = $2,000,000/20
$100,000/Well
Net Profits per well at time of mine through $1,500,000/20 = $75,000
Therefore: Reimbursement is equal to 165% x 1 Well = Net profits per well
= 1.65 x $100,000 = $75,000
= $165,000 = $75,000
= $90,000
The reimbursement to Lessee is $90,000.
Article 15.1 of the Occluded Gas Lease shall be amended to read as follows:
15.1 Lessee shall promptly furnish to Lessor any information reasonable requested by Lessor or Lessors agents or representatives with respect to operations of the Lease Premises. Lessor and Lessors agents or representatives shall at all times have full and free ingress and egress to and from all of Lessee s operations on Leased
40
Premises for the purposes of inspecting Lessee s installations and operations. Lessee shall not be liable for injury to Lessor s agents engaged in such activities except for any of the same caused by negligence of Lessee or its agents, servants or employees. Lessor and Lessor s authorized representative shall also have the right at all reasonable times and at Lessor s sole cost and expense, to inspect and examine the books and records of Lessee, its subcontractors, and successors and assigns, that relate to the Leased Premises, operations thereon, production of Occluded Gas therefrom and the accounting for royalties and other sums or determinations under this Lease for any calendar year within the thirty-six (36) months period following said calendar year.
Section 11.3 of the Accounting Procedure (Exhibit C) attached to the Occluded Gas Lease shall be amended to add Exhibits C-1 and C-2 and the following language:
11.3 Labor
A. |
Employees detailed in Exhibits C-1 and C-2 attached are direct changes to the account unless otherwise specified. Any additional job classifications added at a later date will be handled using the same methodology. |
IN WITNESS WHEREOF the undersigned have hereunto set their hands and seals as of the year and date first above written.
USX CORPORATION |
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ATTEST: |
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By: |
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Assistant Secretary |
General Manager Administration |
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& Group Comptroller |
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U. S. Diversified Group |
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Its: |
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TAURUS EXPLORATION, INC. |
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ATTEST: |
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By: |
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Assistant Secretary |
FIFTH AMENDMENT
TO
OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into by and between USX CORPORATION, a Delaware corporation which was formerly known as United States Steel Corporation ( Lessor ) and AMOCO PRODUCTION COMPANY, a Delaware corporation and TAURUS EXPLORATION. INC., an Alabama corporation( Lessee ).
41
WITNESSETH:
WHEREAS UNITED STATES STEEL CORPORATION and TAURUS EXPLORATION. INC. entered into an Occluded Gas Lease dated January 1, 1986 covering certain lands in Jefferson and Tuscaloosa Counties, Alabama (the Lease ); and
WHEREAS by Assignment executed on March 1, 1991, TAURUS EXPLORATION, INC., assigned to AMOCO PRODUCTION COMPANY all of its right, title and interest in and to the Lease insofar as it affects certain lands set forth on Exhibit A of said Assignment; and
WHEREAS, USX CORPORATION and TAURUS EXPLORATION, INC. have previously amended the Lease by amendments dated April 30, 1987, January 1, 1989. June 1, 1990 and December 11, 1990; and
WHEREAS , Lessor and Lessee desire to make a fifth amendment to the Occluded Gas Lease as hereinafter set forth.
NOW THEREFORE , Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
Paragraph 1.22(a) of Article 1 shall be amended to read as follows:
(a) For Occluded Gas sold or transferred to an entity that is within the Energen group of related companies, for Occluded Gas that is produced but not sold or transferred, and for Occluded Gas that is sold or transferred other than under conditions described in Article 1.22(b) below:...
Paragraph 1.22(b) of Article I shall be amended in its entirety as follows:
1.22(b) For Occluded Gas sold or transferred to a bona fide third-party purchaser not affiliated with Lessee, pursuant to a sales contract arrived at through good faith, arms length negotiations and through which no entity is intending to take unfair advantage of the Lessor; or for Occluded Gas sold pursuant to a gas sales agreement with an affiliated purchaser and subsequently sold or transferred to a bona fide third party purchaser where the sales price and delivery conditions under such agreement between Lessees affiliate and a bona fide third party purchaser are representative of prices and delivery conditions existing under other similar agreements in the area between unaffiliated parties at the same time for natural gas of comparable quality and quantity:
The Wellhead Price shall be the price required to be paid under said sales contract between Lessee and/or Lessees affiliate and a bona fide third party purchaser provided however that if the price stated in said sales contract includes transportation of the Occluded Gas beyond the wellhead, the Wellhead Price shall be the price required to be paid under said sales contract less the Treatment Factor then in effect.
IN WITNESS WHEREOF this agreement shall be effective as of the 1 st day of January, 1993.
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ATTEST: |
USX CORPORATION |
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By: |
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Assistant Secretary |
Its: |
Executive Vice President |
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WITNESSES: |
AMOCO PRODUCTION COMPANY |
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By: |
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Its: |
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ATTEST: |
TAURUS EXPLORATION, INC. |
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By: |
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Its: |
Senior Vice President - Methane |
SIXTH AMENDMENT
TO
OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into by and between United States Steel Corporation, a Delaware corporation, successor (by conversion) to United States Steel LLC and remote successor to USX Corporation (Lessor) and Energen Resources Corporation, an Alabama corporation, formerly known as Taurus Exploration, Inc., (Lessee), Lessor and Lessee are sometimes collectively referred to as the Parties.
WITNESSETH:
WHEREAS Lessor and Lessee entered into an Occluded Gas Lease dated January 1, 1986 covering certain lands in Jefferson and Tuscaloosa County, Alabama (the Lease); and
WHEREAS, the parties have previously amended the Lease by amendments dated April 30, 1987, January 1, 1989, June 1, 1990, December 11, 1990 and January 1, 1993 respectively; and
WHEREAS, Lessor and Lessee desire to make a sixth amendment to the Occluded Gas Lease as hereinafter set forth.
NOW THEREFORE, Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
Insofar and only insofar as that portion of the Lease covers the Southwest Quarter (SW 114) and the West Half of the Northeast Quarter (WI/2 NE114) of Section 22, Township 19 South, Range 8 West, of the Huntsville Principal Meridian, Tuscaloosa County, Alabama, Article 4 Royalties of the Occluded Gas Lease shall be amended in its entirety as follows:
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ARTICLE 4
ROYALTIES:
4.1 |
The royalties to be paid by Lessee shall be, on all Occluded Gas produced from the Premises and sold or used off the Premises, the market value at the well of 1/8 of the Occluded Gas so sold or used, provided, however, that in determining market value there shall be no deduction from the value of Lessors royalty by reason of any required processing, cost of dehydration, compression, transportation (with the exception of the Lessors proportionate share of transportation costs incun-ed after delivery of Occluded Gas to the interstate or intrastate pipeline through which Occluded Gas produced under this Lease is marketed: an example of sue., a pipeline being Southern Natural Gas Company), or other cost of marketing such Occluded Gas. |
4.2 |
All contracts for the sale of Occluded Gas produced from the Premises and sold or used off the Premises, or for gathering, treating, compressing, dehydrating, separating, processing, or transporting the gas produced from any well or wells hereunder will be negotiated on an arms length basis. Should any such contract be negotiated on other than an arms-length basis and, as a result thereof, should the price on which royalties are calculated hereunder he reduced, then royalties shall nevertheless be calculated on an arms-length price. Such arms-length price shall be calculated by taking the average of the three (3) highest prices paid for gas under similar contract and delivery conditions within a 25-mile radius of the lands covered by the Lease. If no such sales on sin liar contract and delivery conditions can be identified, the arms-length price shall instead be calculated by taking the average of the three (3) highest prices paid for Occluded Gas produced within a 25-mile radius of the lands covered by this Lease, which shall then be adjusted for the reasonable value of differences in the contract and/or delivery conditions. |
The parties hereto further agree that the foregoing amendment to the Occluded Gas Lease shall be effective on the year and date first above written and shall not have retroactive effect.
IN WITNESS WHEREOF, this Agreement shall be effective as of the 16 th day of December , 2002.
WITNESS: |
UNITED STATES STEEL CORPORATION |
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By: |
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Name: |
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Title: |
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USS Real Estate, a division of |
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United States Steel Corporation |
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Date: |
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WITNESS: |
ENERGEN RESOURCES CORPORATION |
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By: |
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Name: |
John S. Richardson |
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Title: |
Vice President |
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Date: |
12/02/03 |
44
SEVENTH AMENDMENT
TO
OCCLUDED GAS LEASE
THIS AGREEMENT made and entered into by and between United States Steel Corporation, a Delaware corporation (Lessor) and Energen Resources Corporation, an Alabama corporation, formerly known as Taurus Exploration, Inc. (Lessee), Lessor and Lessee are sometimes collectively referred to as the Parties.
WITNESSETH:
WHEREAS, United States Steel Corporation and Taurus Exploration, Inc. entered into an Occluded Gas Lease dated January 1, 1986 covering certain lands in Jefferson and Tuscaloosa Counties, Alabama (the Lease); and
WHEREAS, the Parties have previously amended the Lease by amendments dated April 30, 1987, January 1, 1989, June 1, 1990, December 11, 1990, January 1, 1993 and December 16, 2002 respectively; and
WHEREAS, Lessor has conveyed certain mineral rights to U. S. Steel Mining Co., Inc. by instrument dated effective October 1, 1987 and recorded in the Office of the Judge of Probate of Jefferson County, Alabama in Volume 838, Page 609 (the 1987 Conveyance.) The 1987 Conveyance is attached hereto for convenience purposes as Attachment 1 ; and
WHEREAS, Lessor has conveyed certain mineral rights to U. S. Steel Mining Co., LLC. by instrument dated April 2, 1998 and recorded in the Office of the Judge of Probate of Jefferson County, Alabama in Book 9861, Page 2449 (the 1998 Conveyance.) The 1998 Conveyance is attached hereto for convenience purposes as Attachment 2 ; and
WHEREAS, Lessor and Lessee desire to make this Seventh Amendment to the Occluded Gas Lease for the purpose of amending the depths covered by said Occluded Gas Lease to include rights from the surface of the ground down to and including 80 feet below the base of the Lower Pottsville Formation; provided however that such additional depths shall not apply to the areas of the Occluded Gas Lease which are the subject of the 1987 Conveyance and the 1998 Conveyance;
45
NOW THEREFORE, Lessor and Lessee, intending to be legally bound, do hereby agree as follows:
Paragraph 1.8 of Article I of the Occluded Gas Lease shall be amended to read as follows:
1.8 Leased Premises: All those certain lands situated in Jefferson and Tuscaloosa Counties, Alabama, containing a total of 124,000 acres, more or less, described in Exhibit A-1, and further identified on Exhibit A-2, both attached hereto and incorporated herein, limited to a depth of 80 feet below the base of the Lower Pottsville Formation more specifically identified on Exhibit D attached hereto and incorporated herein. The Leased Premises are contained within the area generally described on the map attached as Exhibit B-1. Notwithstanding the above, Lessee shall have the right to drill up to three hundred feet (300) below the base of the Lower Pottsville Formation coal seams in order to establish a sump for the wells drilled under the terms of this Lease.
Exhibit D of the Occluded Gas Lease shall be deleted in its entirety and replaced with the Exhibit D attached hereto and made a part hereof.
Notwithstanding anything in this Seventh Amendment to the contrary, the provisions of this Seventh Amendment shall not be applicable to those portions of the Occluded Gas Lease which are subject to the 1987 Conveyance and the 1998 Conveyance.
In all other respects the terms and conditions of the Occluded Gas Lease, as previously amended, shall remain unchanged.
The parties hereto further agree that the foregoing amendment to the Occluded Gas Lease shall be effective on the year and date first above written and shall not have retroactive effect.
IN WITNESS WHEREOF, this Agreement shall be effective as of the 1 st day of March 2003.
46
Exhibit 21
SUBSIDIARIES OF ENERGEN CORPORATION
Alabama Gas Corporation*
Energen Resources Corporation*
Energen Resources TEAM, Inc.*
* Incorporated in the State of Alabama
Exhibit 23(a)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 333-26111, File No. 333-45107 and File No. 333-84170) of Energen Corporation of our report dated March 15, 2006 relating to the consolidated financial statements, financial statement schedule, managements assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 15, 2006
Exhibit 23(b)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (File No. 333-121077) of Alabama Gas Corporation of our report dated March 15, 2006 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 15, 2006
Exhibit 23(c)
CONSENT
We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2005, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 333-26111, File No. 333-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2005, which appears in this Form 10-K.
Ryder Scott Company, L.P.
Houston, Texas
March 14, 2006
Exhibit 23(d)
CONSENT
We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2005, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 333-26111, File No. 333-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2005, which appears in this Form 10-K.
T. Scott Hickman & Associates, Inc.
Midland, Texas
March 14, 2006
Exhibit 31(a)
CERTIFICATION
I, Wm. Michael Warren, Jr., certify that:
1. |
I have reviewed this report on Form 10-K of Energen Corporation and Alabama Gas Corporation; |
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. |
The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) |
Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) |
Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. |
The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent function): |
a) |
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and |
b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
March 14, 2006 |
By |
/s/ Wm. Michael Warren, Jr. |
||
Wm. Michael Warren, Jr. |
||||
Chairman and Chief Executive |
||||
Officer of Energen Corporation, Chairman and Chief Executive Officer of Alabama Gas Corporation |
Exhibit 31(b)
CERTIFICATION
I, G. C. Ketcham, certify that:
I |
have reviewed this report on Form 10-K of Energen Corporation and Alabama Gas Corporation; |
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. |
The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) |
Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) |
Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. |
The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent function): |
a) |
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and |
b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
March 14, 2006 |
By |
/s/ G. C. Ketcham |
||
G. C. Ketcham |
||||
Executive Vice President, Chief |
||||
Financial Officer and Treasurer of |
||||
Energen Corporation and Alabama Gas Corporation |
Exhibit 32
CERTIFICATION PURSUANT TO
18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Energen Corporation and Alabama Gas Corporation (the Registrants) on Form 10-K for the period ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies with respect to each registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Dated as of March 14, 2006
By |
/s/ Wm. Michael Warren, Jr. |
|
Chairman and Chief Executive |
||
Officer of Energen Corporation, Chairman and Chief Executive Officer of Alabama Gas Corporation |
By |
/s/ G. C. Ketcham |
|
G. C. Ketcham |
||
Executive Vice President, Chief |
||
Financial Officer and Treasurer of |
||
Energen Corporation and Alabama Gas Corporation |
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Energen Corporation and Alabama Gas Corporation and will be retained by Energen Corporation and Alabama Gas Corporation and furnished to the Securities and Exchange Commission or its staff upon request.