Item 1. Business.
Alamco, Inc. (the "Company" or "Alamco") is an Appalachian-based independent gas and oil producer actively engaged in the acquisition, exploitation, development and production of domestic gas and oil. The Company's activities are conducted in West Virginia, Tennessee and Kentucky, with emphasis on producing natural gas for ultimate sale to customers in the Northeast gas markets. Independent petroleum engineers estimate that the Company's proved reserves totalled 128.0 equivalent billion cubic feet ("EBCF") as of December 31, 1994, using a conversion of six thousand cubic feet of gas to one barrel of oil. As of December 31, 1994, the Company had an average ownership interest of 82 percent in 1,162 gross wells and operates 97 percent of the wells in which it has an ownership interest.
Alamco, a Delaware corporation, was organized in 1981 as the successor of a privately held entity, Allegheny Land And Mineral Company ("Allegheny"), which had been engaged in the gas and oil business since 1956, and to certain interests in various gas and oil programs sponsored and/or operated by Allegheny. The Company's executive offices are located at 200 West Main Street, Clarksburg, West Virginia 26301, and its telephone number is (304) 623-6671. The Company currently employs approximately 94 persons on a full time basis. The Company's Common Stock is listed on the American Stock Exchange ("AMEX") under the trading symbol "AXO".
BUSINESS STRATEGY
The Company's business strategy is to economically increase its reserves and its production and sale of gas and oil from existing and acquired properties in the Appalachian Basin in order to maximize stockholders' return over the long term. To accomplish this strategy, the Company will continue to focus on increasing its gas and oil reserves through development and exploratory drilling, property acquisitions, well recompletion and exploitation programs, including remedial well enhancements. Using this strategy, the Company's reserves have increased in each of the past four years. Estimated reserves of 128.0 EBCF at December 31, 1994, compares favorably to estimated reserves of 88.0 EBCF, 64.1 EBCF and 49.6 EBCF as of December 31, 1993, 1992 and 1991, respectively.
The Company intends to continue to focus its activities in the Appalachian Basin, which is geographically one of the largest and oldest gas and oil producing regions in the United States. The Company and other operators in the Appalachian Basin have historically experienced high drilling success rates in the formations of the Basin, with wells generally producing for more than 25 years, although at low production volumes. The Company may expand its area of operations into other producing basins if management believes such an expansion is beneficial to the Company.
The Company develops reserves by drilling wells and recompleting
previously drilled wells to prove the existence of gas and oil reservoirs. Drilling activities are currently carried out in West Virginia, Tennessee and Kentucky. In certain situations, an alternative to drilling new wells is the recompletion of existing wells. Recompletions may prove the existence of additional quantities of natural gas and oil in formations which have not yet been opened to production in existing wells. Recompletion projects are attractive because they generally provide access to reserves at a cost which is substantially lower than the cost of drilling a new well. The Company's recompletion efforts are centered on its West Virginia properties.
The Company also intends to acquire additional producing properties to increase its gas and oil reserves. The Company actively pursues the acquisition of producing properties that will enhance the Company's revenue base without proportional increases in overhead costs. The Company has directed its attention to Appalachian Basin properties in which it will have a significant ownership interest and will serve as operator. In addition to the acquisition of properties owned and operated by third parties, the Company will continue to evaluate the purchase of outside investors' interests in wells operated by the Company.
Exploitation programs may add to the Company's reserves because of the upward revision in the estimate of existing producing properties' reserves from the prior year's reserve estimate. The upward revision is due to, among other things, recognition of the Company's effort to maximize productive capability through enhanced operating techniques and thus increase ultimate recoverable reserves by reducing reservoir abandonment pressures and increasing the well drainage area of its existing producing properties.
The Company has entered into certain oil field-related service businesses in order to diversify its revenue base. In addition to providing these services for itself, the Company intends to make these services available to others in the gas and oil industry (See "Business-Brine Hauling and Disposal Services"). Accordingly, the Company has formed HAWG Hauling & Disposal, Inc. ("HAWG"), a brine hauling and disposal service and Phoenix-Alamco Ventures, a Limited Liability Company ("PAV"), which is engaged in the marketing of Alamco's and other working interest owners' gas. HAWG is a wholly owned subsidiary of the Company while PAV is owned jointly by the Company and Phoenix Diversified Ventures, Inc. ("Phoenix"). Revenues generated by HAWG and PAV totalled $215,000 in 1994.
GAS AND OIL DEVELOPMENT ACTIVITIES
At December 31, 1994, the Company's proved reserves totalled 128.0 EBCF, representing a 40.0 EBCF increase from year-end 1993 reserves. Based on these reserve additions, the Company replaced 933 percent of the 4.8 EBCF it sold during 1994. Drilling and acquisition activities during the year added reserves of 33.8 EBCF while 11.0 EBCF was added because of the Company's on-going exploitation program and the net result of a well swap. The Company invested $15,812,000 in gas and oil development activities during the year, including $6,234,000 in producing property acquisitions. Internally generated cash flows and amounts drawn from the Company's revolving credit facility with Bank One, Texas, N.A. ("Bank One") funded the capital program.
DRILLING ACTIVITIES
A total of 16.1 EBCF was added to the Company's reserves as a result of the 1994 drilling program. The Company invested $9,312,000 or 59 percent of the Company's gas and oil development expenditures in the drilling of 46.7 net wells, of which 38.0 net wells were successful. The Company drilled, for its own account, 30 and 16 gross wells in West Virginia and Tennessee, respectively. The Company also drilled one gross (0.7 net) well in Kentucky, which was unsuccessful.
Of the total number of wells drilled in West Virginia, 15 were drilled in the South Burns Chapel Field in Monongalia and Preston Counties, including 5 wells drilled to the deep Oriskany Formation. The remaining 10 wells were
drilled to shallower zones at a depth of less than 3,000 feet. Also in North Central West Virginia, the Company drilled 15 shallow gas wells located in various counties throughout the region.
The 38.0 net productive wells drilled in 1994 is an increase over the 26.0 and 4.5 net wells drilled in 1993 and 1992, respectively. The increase in development drilling during 1994 and 1993 is due to, among other things, the number of drilling prospects identified by the Company's geological staff and the availability of funds to finance the drilling activity. A number of additional prospects have been identified on Company-held acreage in the South Burns Chapel Field in West Virginia, the Days Chapel Field in Tennessee and in various counties in Kentucky. (See "Future Activities").
During 1994, the Company drilled 9 dry holes, all of which were development wells and within a proved area of a gas or oil reservoir. The wells did not contain sufficient reserves warranting further expenditures.
RECOMPLETION ACTIVITIES
The Company invested $266,000 in recompletion projects during 1994 as compared to $119,000 and $542,000 in 1993 and 1992, respectively. Two recompletion attempts were successful and three attempts did not establish economic quantities of gas and oil production. All of the recompletion attempts were located in West Virginia. The Company believes its inventory of wells contains a significant number of recompletion candidates.
ACQUISITION ACTIVITIES
In 1994, the Company invested $6,234,000 or 39 percent of its gas and oil development expenditures in the acquisition of 172.6 net wells. The acquisition activities added 17.7 EBCF to the Company's reserves. The program included the acquisition of both properties owned and operated by third parties and outside investors' interests in wells operated by the Company.
In two transactions, the Company acquired from third parties 69 wells (63.4 net wells) and over 35,000 gross acres (31,000 net acres) in southeastern Kentucky for $1.8 million in cash. The Company became the operator of the wells effective on the purchase dates. The Company continues to seek other well acquisitions and leases in these areas.
The Company acquired, effective as of January 1, 1994, all of the interests held by a number of limited partnerships in 114 West Virginia gas wells (91.2 net wells), 102 of which were already operated by the Company for $3.8 million in cash. The Company also acquired outside investors' interests in other Company-operated wells, none of which were individually significant. Also in West Virginia, the Company acquired 2.5 net Oriskany wells in the South Burns Chapel Field.
In order to consolidate its operations geographically and to reduce the administrative burdens associated with operating co-owned wells, the Company, effective March 1, 1994, exchanged its interest in approximately 141 gross wells in West Virginia for outside investors' interests in approximately 237 gross wells located in West Virginia. The exchange has been treated as a like-kind exchange and no gain or loss has been recognized on this transaction.
GAS AND OIL PRODUCTION AND SALES
For 1994, gas sales accounted for 92 percent of the Company's total gas and oil sales. The average 1994 sales price received by the Company was $2.22 per MMBtu ($2.50 per MCF) for gas and $14.52 per barrel for oil. The following table sets forth the Company's sales volumes and other information for each of the years ended December 31, 1994, 1993, and 1992.
(a) Oil production is converted to gas equivalents at a rate of 6 MCF per barrel.
WELL TENDING SERVICES
In the aggregate, the Company owns as of December 31, 1994, approximately 82 percent of all Company operated wells with the remaining 18 percent being held by outside investors. The Company charges a monthly fee for well operation services and each outside investor pays a proportional share based on his ownership percentage. For most of 1994, the monthly fees were $323 per well for gas wells and $392 per well for oil wells compared to monthly charges in 1993 of $308 per well for most gas wells and $374 per well for most oil wells. In 1994, about 159 wells were not subject to the monthly operating fee due to temporary abandonments. The income which the Company generates from these fees, well tending income, accounted for approximately 9.0 percent, 18.3 percent, and 20.3 percent of the Company's revenues in 1994, 1993 and 1992, respectively.
Effective March 1, 1994, the Company exchanged its interests in approximately 141 gross wells for outside investors' interests in approximately 237 gross wells located in West Virginia. Well tending income was substantially reduced because this like-kind exchange reduced the number of wells that the Company operates for outside investors. The Company believes, however, that this reduction in well tending income will be offset over time by the effect of higher gas and oil revenues attributable to the Company's greater ownership interest in the wells.
BRINE HAULING AND DISPOSAL SERVICES
The Company has a wholly-owned subsidiary, HAWG, a commercial brine hauling and disposal service company. The service entails, for a fee, the transportation of brine to a central processing facility and injection of the brine into non-economic wells. The subsidiary accepts brine, which is produced naturally with gas and oil, from wells operated by the Company as well as from other operators in West Virginia. HAWG currently operates a restricted use, non-public brine disposal facility and has plans for converting other wells for disposal service if HAWG obtains commercial contract status. In 1994, HAWG provided 0.5 percent of the Company's total revenues.
GAS MARKETING
As a response to the changing gas marketing environment, the Company formed PAV with Phoenix, a gas marketing company. PAV provides gas marketing services to Alamco and other interest owners in Alamco operated wells. PAV has the exclusive right to market most of Alamco's gas supply. PAV has been and will be seeking diversification for Alamco's gas sales to other marketing entities, local distribution companies and industrial users with a mixture of short-term deals (less than a month), mid-term deals (one month to one year) and long-term deals (one year or more). In 1994, PAV provided 1.0 percent of the Company's total revenues.
While Alamco's share of the profits from PAV are not expected to be
significant, the prices received for gas sales marketed through PAV have been on average above that which the Company would likely otherwise receive.
FUTURE ACTIVITIES
In the future, the Company intends to use internally generated cash flows and amounts available under the Company's $25.0 million revolving credit facility with Bank One to fund the development of its gas and oil reserves and property acquisitions. As of March 22, 1995, $12.0 million was available for borrowing under the credit facility.
The Company's 1995 capital investment program will ultimately depend upon the market and prices received for natural gas and the ability of the Company to capitalize on acquisition opportunities that may arise during the year. Until gas prices improve, drilling activity will be limited to an estimated 5 to 10 wells in order to maintain leasehold positions, fulfill contractual commitments and explore oil prospects. The Company will continue with its enhancement program on existing wells, particularly the wells acquired last year in its Kentucky acquisition program and where the Company has established a significant acreage position. The Company's objective will be to maintain current production and gas and oil reserve levels through well enhancements and limited drilling activity while using excess cash flow to retire debt. The Company plans to continue with its aggressive acreage acquisition strategy and will position itself to increase both exploratory and development drilling when gas prices recover. The Company remains committed to the acquisition of producing properties at favorable prices.
MARKETS AND CUSTOMERS
General.
The Company operates exclusively in the gas and oil industry.
Sales through PAV and to Hope Gas, Inc. ("Hope") accounted for a substantial portion of the Company's total 1994 gas and oil sales. The Company sold 53.8 percent of its gas and oil sales through PAV to various marketers, local distribution companies and commercial users. Additionally, sales to Hope accounted for approximately 28.2 percent of the Company's total 1994 gas and oil sales.
West Virginia Production.
PAV. In 1993, the Company entered into a three year gas marketing agreement with PAV for nearly all gas transported on the Consolidated Natural Gas Transmission Corporation ("CNG") pipeline system and all gas on the Columbia Gas Transmission Corporation ("Columbia") pipeline system. Volumes sold in 1994 through PAV on the CNG and the Columbia systems totalled approximately 2.4 BCF. The average price received from sales to PAV averaged $2.14 per MMBTU ($2.44 per MCF) in 1994.
Hope. Hope purchases the Company's production from the South Burns Chapel Field. The terms of the contract provide for Hope to purchase all of the gas produced through November 1, 1999, at the monthly Appalachian index price. Additionally, Hope pays to the Company a monthly demand charge for the Company's ability to provide Hope with specified levels of gas supply. The pricing provision is subject to renegotiation on April 1, 1996. This contract has proven to be more favorable than spot market prices. However, Hope does have the right, under certain conditions, to curtail gas purchases and did, in fact, notify producers whose production flows directly into its system that it would curtail all production from September 9, 1994 through October 18, 1994. The Company was able to negotiate an interim purchase arrangement with Hope which allowed the Company to produce and sell approximately 50 percent of its volumes during most of the curtailment period. Since October 21, 1994, all of the affected wells have been producing at unrestricted levels. The Company estimates revenues were adversely affected by $250,000 due to this reduction in volumes. Additionally, the Company sells other volumes of gas from the South Burns Chapel Field to Hope under a market-sensitive pricing arrangement which is subject to renegotiation on April 30, 1995. The Company believes the contract will be extended under similar terms. The loss of this customer could have a material adverse effect on the Company. However, the Company believes it would be able to locate alternate customers in the event of such loss. Total volumes sold to Hope in 1994 were approximately 1.4 BCF and averaged $2.50 per MMBTU ($2.50 per MCF).
Other. The Company sold gas from approximately 110 wells in its Tallmansville, West Virginia field to CNG. CNG is permitted to recoup gas as a result of a $3,800,000 prepayment made in 1989 for 1,565,000 MMBTU of gas. This recoupment will take place under specified conditions until the earlier of full recoupment or December 31, 1999, at which time the Company's obligation will be fulfilled, whether or not the entire prepaid volumes have been recouped by CNG. As of December 31, 1994, the Company had delivered approximately 1,120,000 MMBTU of these prepaid volumes. Beginning March 1, 1994, the Company began selling 33.33 percent of the field's production through PAV with the remaining 66.67 percent of the production dedicated to CNG as recoupment. The Company intends, however, in light of current depressed gas prices, to permit CNG to recoup 100 percent of the production beginning on or after March 1, 1995, and continuing until gas prices improve or until the volumes are fully recouped. The Company's remaining estimated share of the prepaid amount is included in deferred revenue.
The Company sells its other West Virginia gas production to various purchasers that are not significant to the Company's revenue base.
Tennessee Production.
The Company is currently selling the gas production from its Tennessee operations to Equitable Resources Marketing Company. This is a month-to-month contract with market-sensitive pricing tied to Gulf Coast prices, less transportation and compression charges. For 1994, the net-back price (reduced for transportation) on volumes of approximately 180,000 MCF averaged $1.26 per MMBTU ($1.49 per MCF). Tennessee production represents approximately 2.2 percent of total Company gas and oil sales.
Kentucky Production.
The Company's Kentucky production is currently approximately 1.2 percent of total Company gas and oil sales. The Company is selling 60 percent of the production from its Kentucky operations on the spot market or under short term contracts providing for fixed or market-sensitive prices. Approximately 40 percent of the Company's Kentucky production is sold to one buyer under a contract which dedicates the gas for the life of the wells, but which still involves market-sensitive pricing. Company sales of Kentucky production totalled 82,626 MCF and averaged $1.47 per MMBTU ($1.73 per MCF) in 1994.
Principal Transporters.
Most of the Company's gas is transported though the CNG, Hope, Columbia, Texas Eastern, and Wiser Oil Company ("Wiser") pipeline systems which give the Company access to major Northeastern markets. With the exception of the Kentucky production, each of the Company's major gas production areas and leases is in close proximity to at least one of those pipelines. A relatively minor amount of the Company's gas is transported on other pipeline systems.
Oil Sales.
The Company's oil production is sold to various purchasers under agreements at posted field prices. These sales, which accounted for 8 percent of the Company's total gas and oil sales, averaged $14.52 per BBL in 1994.
Marketing Risks.
During the last several years, the gas industry has been adversely affected by a surplus, which has tended to depress prices and has created
difficulty in estimating future prices. The Company is unable to predict with certainty the future stability or direction of natural gas prices.
The availability of a ready market for the Company's gas and oil depends on numerous factors beyond its control, including, among other factors, the demand for and supply of gas and oil, the weather, the proximity of the Company's natural gas reserves to pipelines, the capacity of such pipelines, the cooperation of pipeline owners, general economic conditions, fluctuations in seasonal demand and the effects of inclement weather and governmental regulation. In addition, under certain gas purchase arrangements the Company is subject to the risk of periodic reduced purchases or access to pipelines. Any significant reduction or curtailment of production for an extended period of time could have a material adverse effect on the Company's results of operations.
Additionally, FERC Order 636, issued in 1992, appears to have resulted in increased competition in the marketing of natural gas (see "Regulation").
COMPETITION
The Company operates in a highly competitive environment. Competition is particularly intense with regard to the acquisition of producing properties and, to a lesser extent, undeveloped acreage. Independent gas and oil companies, partnerships and drilling programs with financial and human resources substantially in excess of those available to the Company, compete with the Company, actively bidding for desirable gas and oil properties.
Similarly, there is intense competition not only from other gas production entities, but also from other marketing firms, both of which have the capabilities to seek out and serve various customers. Although the Company has historically enjoyed a price premium over Gulf Coast gas production (as do others in the Appalachian Basin) due to the proximity of its production to major Northeast markets, deregulation of the industry and the advent of open access transportation on interstate pipelines have caused an erosion of this premium.
REGULATION
General. The oil and gas industry is extensively regulated by federal, state and local authorities, with legislation affecting the industry under constant review for changes and/or expansion, particularly with regard to environmental issues. Numerous agencies, both federal and state, have issued rules and regulations, some of which carry substantial penalties for failure to comply, binding on the industry and its members. To date, these mandates have had no material effect on the Company's capital expenditures, earnings or competitive position. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws and regulations.
Environmental. The Company's operations are subject to various federal and state statutes, rules and regulations regarding the control of discharging materials into, or otherwise protecting the environment. These requirements relate to drilling and production operations, activities in connection with storage and transportation of gas and oil and facilities used for treating, processing, injecting or handling the wastes therefrom. Additionally, in the case of spills or other impermissible discharges of certain materials into the environment, there are provisions for record keeping, notification and reporting, as well as severe civil and criminal penalties for violations, and potential liability for the costs of cleanup and any resultant damages. Further, the possibility exists that certain oil and gas wastes may be classified as hazardous or semi-hazardous, which could impose substantial obligations on the Company. The Company does not believe that its compliance with current environmental laws constitutes a material expense. (See Part I, Item 3. Legal Proceedings.)
During 1994, the Company retained the services of an independent engineer and an environmental engineering firm to assist with record keeping and compliance matters and fully expects to continue using them for the foreseeable future on an as-needed basis.
Federal Regulation. As a result of the Wellhead Decontrol Act of 1989, all price controls for various classifications of gas were terminated as of January 1, 1993. This has had no impact on the Company's gas sales since its reserves were either previously deregulated or sold under contracts with alternate pricing.
FERC Order 636, issued in 1992, generally required the unbundling or separating of various components of pipelines services, i.e,, gathering, transportation, storage and sales. Thus far, it appears to have resulted in increased competition in the marketing of natural gas and could cause increased costs for services the Company uses and decreased costs for services utilized by producers in the Gulf Coast and Southwest regions.
Occupational and Safety Regulations. The Company is subject to the requirements of the Occupational Safety and Health Act ("OSHA"), as well as other state and local labor rules and regulations. The cost of compliance with health and safety requirements has had no material impact on the Company's aggregate production expenses to date. Nevertheless, the Company is unable to predict the ultimate cost of compliance.
State Regulation. State regulatory authorities have established laws, rules and regulations requiring, among other matters, permits for drilling and recompletion operations, drilling and operating bonds or bank letters of credit, and reports concerning operations. Further, there are statutes and regulations governing the unitization or pooling of oil and gas leases, the spacing of wells and plugging requirements for abandoned wells. To date, these requirements have had no material effect on the Company's operations and the cost of compliance has been minimal. Future regulations could, however, increase the cost of the Company's production operations.
Brine Hauling and Disposal Services. In order to comply in an economical manner with regulations governing the disposal of salt water, the Company began operating its own salt water disposal well in 1992. In 1993, the Company formed a new subsidiary, HAWG, which is responsible for the transportation and disposal of the water. Additionally, HAWG received authority from the Public Service Commission of West Virginia (the "PSC") in October 1993 to operate as a contract carrier for the Company and other West Virginia producers. HAWG, in 1994, applied to the PSC for approval to operate as a common carrier, which would permit it to haul brine water commercially for any producer desiring such service. The Company has not yet received approval from the PSC, but believes that the PSC no longer has the authority to regulate the granting of such certificates due to a federal law which went into effect on January 1, 1995. However, since the PSC currently contends that it does have regulatory authority over such issues, there may be continued delay in the start-up of the business commercially.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the exploration for and production of gas and oil, such as blowouts, cratering, abnormally pressured formations, explosions, uncontrollable flows of oil, gas or well fluids into the environment, fires, pollution and other environmental hazards and risks. These hazards could result in substantial losses to the Company due to personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage or suspension of operations.
Expenditures made in 1994 due to environmental claims which were unreimbursed were immaterial.
While the Company maintains levels of insurance which it believes to be
customary in the industry, the Company's insurance does not cover every potential risk associated with the drilling and production of gas and oil wells. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on the Company's financial condition and results of operations. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable.
Item 2.
Item 2. Properties.
The Company's properties consist essentially of the working and royalty interests owned by the Company in various gas and oil leases which are located in West Virginia, Tennessee and Kentucky. The Company's proved reserves for the years ended December 31, 1994, 1993 and 1992 are presented below:
These estimates are based primarily on the reports of independent petroleum and geological engineers. Such reports are, by their very nature, inexact and subject to changes and revisions. Proved developed reserves are reserves expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. No estimates of reserves have been included in reports to any federal agency other than the Securities and Exchange Commission and the Department of Energy (Note 15).
WELL COUNT
The Company obtained gas and oil sales revenues from 1,162 wells as of December 31, 1994. The majority of the Company's producing wells, located in northern and central West Virginia, are shallow wells drilled to a depth of up to 6,000 feet and are characterized by long producing lives with low volume production from low permeability reservoirs with a thickness ranging from 10 to 40 feet. A typical shallow well will encounter commercial gas production from between 4 and 10 separate and distinct production horizons. Approximately 929 of the Company's wells produce from one or more of these "blanket" formations that cover large areas of northern and central West Virginia. Due to mechanical and technical constraints, it is usually possible to produce only up to three to five of these formations simultaneously, and, consequently, it is necessary either to drill a twin well or recomplete the original well at a later date.
A significant production horizon below 6,000 feet in the Company's West Virginia operations is the Oriskany/Huntersville Chert formation. Deeper wells in this formation exhibit higher pressure and productivity than wells in the shallow West Virginia formations and reservoirs have thicknesses of up to 125 feet.
The Company's Tennessee production is from the Big Lime formation, an oil reservoir that also produces casinghead gas. Big Lime wells are typically characterized by low production volumes (5 to 35 barrels of production per day) from low pressure and low permeability reservoirs varying in thickness from 10 to 40 feet.
In Kentucky, the Company's production is from numerous zones, including the Big Lime, Coniferous, Maxton and Knox formations. These oil and gas reservoirs, like many other Appalachian formations, are characterized by low productive volumes with long producing lives.
Note: Many of the Company's wells produce both gas and oil. For purposes of computing the above data, the gas well versus oil well designations were made on the basis of the type of artificial lift installed on the well.
PROSPECTS
The Company's producing wells hold approximately 122,000 acres under lease which the Company believes includes a substantial number of promising development prospects. The prospects include new development well locations and candidates for the recompletion of now depleted or nearly depleted existing wells to formations in the respective wellbores that have not yet been opened to production.
Also, at December 31, 1994, the Company held leases which have not yet been explored for the existence of gas and oil reservoirs. The Company may drill wells on the acreage to determine the existence of productive reservoirs, sell the leases to another gas and oil operator or abandon the acreage upon the expiration of the lease term.
TITLE TO PROPERTIES
Substantially all of the Company's property interests are held pursuant to leases from third parties. Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the gas and oil industry, liens incident to operating agreements, liens relating to amounts owed to the operator, liens for current taxes not yet due and other encumbrances. The Company believes that such burdens neither materially detract from the value of such properties nor from the respective interests therein, or materially interfere with their use in the operation of the business.
As is customary in the industry, little investigation of record title is made at the time of lease acquisition (other than a preliminary review of local records) in regard to undeveloped properties. Investigations, including a title opinion of local counsel, are generally made prior to the consummation of an acquisition of larger producing properties and before commencement of drilling operations.
OTHER PROPERTY
In addition to gas and oil properties, the Company's property and equipment includes field warehouses, service (workover) rigs and support vehicles. All of the Company's assets collateralize its indebtedness under its revolving credit facility with Bank One. See Note 6 to the Company's Notes to Consolidated Financial Statements. The Company's executive offices are under leases which expire on August 31, 1996.
Item 3.
Item 3. Legal Proceedings.
The Company is not at this date a party to any material pending legal proceeding, other than ordinary, routine litigation incidental to the business of the Company and its subsidiaries. See Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 4 for information related to the Company's litigation claim against Columbia.
On May 23, 1994, the United States Environmental Protection Agency (the "EPA") issued an administrative complaint against the Company for alleged violations of the Clean Water Act resulting from an oil discharge at the Company's Days Chapel Field in Claiborne County, Tennessee. The incident occurred in December 1993 when vandals severed locks securing the valves on the Company's oil storage tanks and discharged approximately 174 barrels of oil into a local creek.
The EPA has proposed that penalties of nearly $124,000 be assessed against the Company. However, the Company contends that the asserted penalties exceed the statutorily authorized limits. Settlement negotiations are ongoing and the Company believes that, due to meritorious defenses, any final penalties will be substantially less than those proposed although no assurances can be given as to the exact amount of any final penalties.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of the Company's stockholders during the quarter ended December 31, 1994.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of the Company are as follows:
No family relationship exists among any of the Company's executive officers or directors.
John L. Schwager has been President and Chief Executive Officer of the Company since October 1987. Mr. Schwager served as the Company's Executive Vice President from May 1987 through October 1987 and Senior Vice President of Operations from September 1984 through May 1987. Mr. Schwager was elected a director in 1986.
Richard R. Hoffman became the Company's Executive Vice President and Chief Operating Officer on December 13, 1990. Mr. Hoffman served as Senior Vice President, Exploration and Production from November 1988 through December 12, 1990, Vice President, Production from November 1986 to November 1988 and Manager of Production from October 1982 through October 1988. Mr. Hoffman was elected as a director in 1988.
Steven E. May has been the Vice President and Controller of the Company since December 13, 1990. From June 1989 through December 1990, he served as Assistant Controller and from October 1987 through May 1989 as the Manager of Corporate Planning and Data Processing of the Company. Mr. May joined the Company in April 1985 as a Senior Production Engineer.
Bridget D. Furbee has been the Vice President, Administration and Legal Affairs of the Company since May 1994. Ms. Furbee served as Manager, Gas Marketing and Legal Affairs from August 1992 through April 1994, and Gas Marketing/Office Administration Manager from January 1985 through July 1994. Prior to January 1985, Ms. Furbee served the Company in various clerical positions.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
The Company's Common Stock is listed on the American Stock Exchange under the trading symbol "AXO". The following table sets forth for the periods indicated the high and low sales price of the Common Stock for each quarters in 1994 and 1993.
As of March 1, 1995, there were approximately 1,445 holders of the Company's voting Common Stock. Since its incorporation in 1981, the Company has not declared or paid any dividends with respect to the Company's Common Stock.
The Company presently intends to retain its funds for operations and expansion of its business and does not expect to pay any cash dividends in the foreseeable future. While the Company is not currently prohibited in its credit agreement with Bank One from paying cash dividends, certain financial covenants may, however, restrict such payments in the future. Subject to the terms of the agreement, the declaration and payment by the Company of any dividends on its Common Stock in the future and the amount thereof will, nevertheless, depend upon the Company's operating results, financial condition, cash requirements, future prospects, and other factors deemed relevant by the Company's Board of Directors.
During 1993, the Company consummated a public offering of 3,105,000 shares of Common Stock, of which 2,071,404 newly issued shares were sold by the Company and 1,033,596 shares were sold by PNC Bank ("PNC"). The sale of the stock by PNC represents all of the shares issued to PNC by the Company as part of the Company's 1988 debt restructuring.
Item 6.
Item 6. Selected Financial Data
The information below should be read in conjunction with the Consolidated Financial Statements and the related notes in Item 8 and in Item 7
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Management's discussion and analysis of changes in the Company's financial condition, including liquidity and capital resources, and results of operations during the twelve-month periods ended December 31, 1994, 1993 and 1992 are presented below.
RESULTS OF OPERATIONS
Year Ended December 31, 1994 vs. Year Ended December 31, 1993 --------------------------------
The Company reported net income of $1,646,000 for the year ended December 31, 1994, an increase of $94,000 or 6.1 percent as compared to net income of $1,552,000 in 1993. Income from operations for 1994 decreased $449,000, or 21.6 percent, to $1,625,000 as compared to $2,074,000 for 1993.
Total revenues of $13,671,000 in 1994 were $1,771,000 or 14.9 percent higher than total revenues of $11,900,000 in 1993.
Gas and oil sales totalled $11,993,000 in 1994 which represents a $2,489,000 increase over the same period last year. Higher gas and oil sales volumes, resulting principally from the acquisition of producing properties and the drilling of new wells, contributed $3,362,000 and
$486,000, respectively, to the increase and were offset by lower gas prices of $1,258,000 and lower oil prices of $101,000. Gas and oil sales volumes totalled 4,810,681 equivalent thousand cubic feet ("EMCF") and 3,421,510 EMCF for the years ending December 31, 1994 and 1993, respectively. The Company received on average $2.50 per MCF and $14.52 per barrel ("BBL") in 1994, compared to $2.79 per MCF and $16.01 per BBL last year.
In early September 1994, Hope informed the Company and other local suppliers that its gas supply exceeded its sales market requirements, which could create an imbalance with CNG, its pipeline transporter, and requested a temporary reduction of production volumes for an unstated period of time. The Company agreed to temporarily reduce its production by approximately 50 percent beginning September 12, 1994. Since October 21, 1994, all of the affected wells have been producing at unrestricted levels. The Company estimates revenues were adversely affected by $250,000 due to this reduction in volumes.
Current gas futures prices indicate the Company will receive in 1995 lower prices as compared to that received in the past three years. Based on the foregoing, the Company does not expect that it will be required to reduce the carrying value of its gas and oil properties during 1995.
Well tending income decreased $940,000 or 43.3 percent due principally to the reduction in the number of wells the Company operates for outside investors. Effective March 1, 1994, the Company exchanged its interests in approximately 141 gross wells for outside investors' interests in approximately 237 gross wells. In addition, on August 1, 1994, but effective January 1, 1994, the Company acquired an outside owners' approximately 80 percent interest in 114 gross wells. The Company believes the reduction in well tending income, as a result of these transactions, will be offset over time by the effect of higher gas and oil revenues attributable to the Company's greater ownership interest in the wells (Note 2).
Other operating revenue increased $222,000 due primarily to the recognition of income relative to the transaction in which the Company formed a partnership with an East Coast financial institution (Note 3). The partnership is structured such that the financial institution will be allocated IRC Section 29 tax credits as a result of production from properties contributed by the Company to the partnership. The financial institution initially paid the Company $1.0 million, less $100,000 for certain expenses incurred by the financial institution. The Company recognizes income from this transaction, as the tax credits are generated.
Total expenses in 1994 were $12,046,000, an increase of $2,220,000 or 22.6 percent from expenses of $9,826,000 in 1993.
Operating expenses were higher by $1,199,000 or 28.1 percent due primarily to the significant property acquisitions made and new wells drilled during 1994 and higher employee-related expenses due principally to the expansion of the Company's drilling operations in the past 12 months. Staff levels have increased in those departments that identify and acquire drilling prospects as well as the engineering staff which oversees the drilling of the wells.
General and administrative expenses for 1994 were higher by $535,000 or 22.5 percent as compared to last year due to, among other things, higher business franchise taxes due to the increase in the Company's equity as a result of the 1993 stock offering. In addition, higher employee-related costs as well as expenses associated with the Company's Stockholders' Rights Plan contributed to the increase. Also, amounts paid to Bank One were higher due to increased commitment fees and other fees which are based upon the unused portion of the Company's credit facility.
Depreciation, depletion and amortization expense was higher by $717,000
due to, among other things, higher depletion expenses related to the increased gas and oil investments and higher production levels. Higher depreciation expenses associated with fixed assets also contributed to the increase.
Interest expense for 1994 was $154,000, a decrease of $231,000 over the same period last year due primarily to capitalization of interest expense related to drilling activities. During 1994, interest incurred by the Company totalled $471,000 of which $317,000 was capitalized.
Non-operating income in 1994 totalled $155,000, a decrease of $166,000, as compared to $321,000 for 1993 due principally to the absence in 1994 of certain asset sales and franchise tax adjustments.
The Company's provision for income tax totalled $134,000 in 1994 as compared to $843,000 last year. The reduction of $709,000 is due to, among other things, a change in the effective state tax rate to reflect new business activities in states with lower tax rates and recently implemented tax planning activities, an increase in the deductions associated with percentage depletion and lower income from operations.
Year Ended December 31, 1993 vs. Year Ended December 31, 1992 --------------------------------
The Company reported net income of $1,552,000 for the year ended December 31, 1993, compared to net income of $1,997,000 in 1992, which includes the cumulative effect, net of tax, of a depreciation, depletion and amortization accounting change of $1,058,000. Income from operations totalled $2,074,000 for 1993 compared to $1,181,000 for 1992.
Total revenues of $11,900,000 were higher by $550,000 or 4.8 percent than revenues of $11,350,000 in 1992.
Gas and oil sales of $9,504,000 in 1993 were higher by $649,000 or 7.3 percent than 1992 sales of $8,855,000. Higher gas and oil sales volumes, resulting primarily from the positive results of drilling activities and the increase in the Company's ownership interest in a significant number of other wells operated by the Company, contributed $786,000 to the increase. The effect of lower gas and oil sales prices of $137,000 partially offset the increase due to higher gas sales volumes.
Well tending income in 1993 totalled $2,172,000 and was $136,000 or 5.9 percent lower than 1992 well tending income of $2,308,000. The reduction was due primarily to the purchase of certain outside investors' interests in Company-operated wells and lower fees chargeable to outside investors. Other revenue totalled $224,000 and was $37,000 higher than last year.
Total expenses in 1993 totalled $9,826,000, a decrease of $343,000 or 3.4 percent from 1992 expenses of $10,169,000.
Operating expenses totalled $4,262,000 for 1993 compared to $4,041,000 for 1992. The $221,000 or 5.5 percent increase was due to, among other things, higher production-based taxes and higher employee-related expenses.
General and administrative expenses totalled $2,373,000 and were $3,000 lower than 1992 expenses of $2,376,000. Higher employee-related expenses and other items were essentially offset by lower legal expenses.
Depreciation, depletion and amortization expense totalled $2,806,000 for 1993 and was lower by $201,000 or 6.7 percent due primarily to additions to the Company's gas and oil reserve base.
Interest expense for 1993 was $385,000, a decrease of $360,000 from 1992.
The decrease in interest expense reflects the repayment of the Company's credit facility in 1993.
Non-operating income in 1993 was $321,000, an increase of $121,000 from 1992. The increase is due primarily to higher asset sales and certain franchise tax adjustments.
Effective January 1, 1992, the Company adopted Statement of Financial Accounting Standard No. 109 retroactively to the beginning of 1990. The Company recorded an income tax provision of $843,000 and $442,000 in 1993 and 1992, respectively. The tax provisions reflect the Company's alternative minimum tax status.
Effective January 1, 1992, the Company changed the method used to calculate depreciation, depletion and amortization of producing properties (Note 7). The cumulative effect of the change, net of taxes, was $1,058,000.
LIQUIDITY AND CAPITAL RESOURCES
Working Capital. At December 31, 1994, the Company had working capital of $835,000, as compared to $1,321,000 at December 31, 1993. The $486,000 reduction in working capital is due to, among other things, lower accounts receivables resulting from the lower price received by the Company for gas sales in the latter part of 1994 as compared to last year and an increase in deferred revenues as a result of an agreement with an East Coast financial institution (Note 3). Because the Bank One credit facility agreement, as amended, calls for the payment of interest only until July 1, 1996, current liabilities on the Company's December 31, 1993, balance sheet do not include any principal payments relative to the Bank One credit facility.
Cash and cash equivalents totalled $2,632,000 at December 31, 1994. Of this amount, approximately $1,559,000 was available for general corporate purposes and the balance was held for third parties (Note 8). Operating activities provided a net $6,238,000 while investing activities used a net $17,210,000 including $16,734,000 in property acquisitions, drilling of new wells, and other capital investment activities. Financing activities provided a net $11,139,000.
Revolving Credit Facility. Currently, the Company has in place a $25.0 million revolving credit facility with Bank One (Note 6). The Company is required to pay interest only until July 1, 1996, at which time all principal and accrued interest is due and payable. Interest accrues and is paid monthly at a rate of Bank One's prime rate plus three-fourths of one percent.
The Company is no longer prohibited from paying dividends to its stockholders under the Bank One credit agreement, however, certain other financial covenants may restrict the payment of cash dividends. The Company presently intends to retain its funds for operations and expansion of its business and does not expect to pay any cash dividends in the foreseeable future.
Capital Expenditures and Commitments. The Company's 1994 capital investments totalled $16,734,000, including $15,812,000 for the acquisition of producing properties and drilling of new wells. These activities were funded from internal sources and the Bank One revolving credit facility. In the future, the Company intends to continue to use internally generated cash flows and amounts available under the credit facility to fund the development of its gas and oil reserves and property acquisitions. (See Part I, Item 1. "Business".)
Most of the Company's capital spending is discretionary and the ultimate level of spending will be dependent, among other things, on the Company's assessment of the gas and oil business environment, the number of gas and oil
prospects, and gas and oil business opportunities in general. The level of the Company's 1995 capital expenditures will to a great extent depend upon the gas prices received by the Company. Based on current gas futures prices, which indicate the Company will receive lower gas prices, as compared to that received in the past three years, the Company plans to limit annual drilling activities to an estimated five to ten wells in order to maintain leasehold positions, fulfill contractual commitments and explore oil prospects. The Company will continue with its enhancement program on existing wells, particularly the wells acquired last year in Kentucky and where the Company has established a significant acreage position. The Company's objective will be to maintain current production and gas and oil reserve levels through well enhancements and limited drilling activity while using excess cash flow, if any, to retire debt. The Company plans to continue with its aggressive acreage acquisition strategy and will position itself to increase both exploratory and development drilling when gas prices recover. The Company remains committed to the acquisition of producing properties at favorable prices.
CNG Agreement. The Company and other working interest owners are obligated to make available 445,000 MMBtu of gas for delivery to CNG between January 1, 1995 and December 31, 1999. The Company's estimated share of the obligation is included in deferred revenue. (See Part I, Item 1. "Business - Markets" and Note 13.)
Settlement of Columbia Litigation Claims. On June 8, 1992, the Company settled its outstanding gas purchase contract claims against Columbia. Pursuant to the settlement agreement, the Company, on behalf of itself and other interest owners in the wells covered by the settlement, has an allowed claim in the amount of $11,000,000 against Columbia, without security or priority, in Columbia's bankruptcy reorganization proceedings. The Company's share of the allowed claim is estimated to be approximately 55 percent, with the balance going to the other interest owners in the wells covered by the settlement. The timing and actual amount to be received by the Company and other interest owners will be affected by the terms of Columbia's reorganization plan as finally approved by the Bankruptcy Court and the amount of assets available to satisfy Columbia's unsecured creditors. Because of the uncertainty as to the actual amount which may be received, the Company's financial statements do not include any benefits of the settlement. However, management believes that the ultimate payment in respect of the Company's claim is likely to be substantial.
Section 29 Tax Credits. Effective August 11, 1994, the Company, through a series of transactions, formed a partnership with a major East Coast financial institution (the "Institution"). The partnership is structured such that the Institution will be allocated IRC Section 29 tax credits as a result of production from properties contributed by the Company to the partnership (Note 3). The institution initially paid $1.0 million (reduced by $100,000 for certain expenses incurred by the Institution), and will pay additional amounts, up to $4.0 million, in installments prior to December 31, 2002, upon achieving certain production minimums and satisfying other conditions. As part of the Section 29 tax credit transaction, the Company formed Alamco-Delaware, Inc. ("Aladel") as a Delaware Investment Holding Company.
Quarterly Financial Data (Unaudited) ------------------------------------
The following table sets forth selected historical quarterly financial data (unaudited) with respect to the Company for the quarters indicated in 1994 and 1993. The Company's results of operations are subject to quarterly variations due to, among other factors, weather conditions and other supply and demand factors affecting the natural gas markets. Historically, the demand and price paid for natural gas has increased in the cold winter months and decreased in the warm summer months. Such quarterly data is not necessarily indicative of the Company's future performance. Because of quarterly variations, the Company believes that its results of operation should be viewed on an annual basis.
(in thousands, except per share data)
First Second Third Fourth 1994 Quarter Quarter Quarter Quarter ---- ------- ------- ------- -------
Sales and other operating revenues $3,370 $3,208 $3,464 $3,629 Gross profit 1,347 1,128 1,161 1,051 Net income (1) 462 321 353 510 Net income per share $0.10 $0.07 $0.08 $0.10
First Second Third Fourth 1993 Quarter Quarter Quarter Quarter ---- ------- ------- ------- -------
Sales and other operating revenues $2,985 $2,765 $2,717 $3,433 Gross profit 1,242 1,074 976 1,540 Net income 457 215 368 512 Net income per share (2) $0.18 $0.08 $0.09 $0.10
----------------------
(1) In the fourth quarter of 1994, the Company adjusted its provision for income taxes by $256,000 to reflect a change in the effective state tax rate. In addition, an increase in deductions associated with percentage depletion and lower income from operations also reduced the income tax provision.
(2) In the third quarter of 1993, the Company consummated a stock offering in which 2,071,404 new shares were issued.
Item 8.
Item 8. Consolidated Financial Statements. ------- ----------------------------------
Index to Consolidated Financial Statements ------------------------------------------
Pages -----
Independent Auditor's Report 28
Consolidated Statement of Income, for the Years Ended December 31, 1994, 1993, and 1992 29
Consolidated Balance Sheet, as of December 31, 1994 and 1993 30-31
Consolidated Statement of Changes in Stockholders' Equity, for the Years Ended December 31, 1994, 1993 and 1992 32
Consolidated Statement of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 33-34
Notes to Consolidated Financial Statements 35-54
INDEPENDENT AUDITOR'S REPORT
To the Board of Directors and Stockholders of Alamco, Inc.
We have audited the accompanying consolidated balance sheet of Alamco, Inc. and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects the consolidated financial position of Alamco, Inc. and subsidiaries as of December 31, 1994 and 1993, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 7 to the consolidated financial statement, the Company changed its method of computing depreciation, depletion and amortization in 1992.
/s/ Coopers & Lybrand L.L.P.
600 Grant Street Pittsburgh, Pennsylvania March 3, 1995
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Years Ended December 31, 1994, 1993 and 1992 (In thousands, except share data) ===============================================================================
1994 1993 1992 ---- ---- ----
Revenues: Gas and oil sales $11,993 $ 9,504 $ 8,855 Well tending income 1,232 2,172 2,308 Other revenue 446 224 187 ------- ------- -------
Total revenues 13,671 11,900 11,350 ------- ------- -------
Expenses: Operating 5,461 4,262 4,041 General and administrative 2,908 2,373 2,376 Depreciation, depletion, and amortization 3,523 2,806 3,007 Interest 154 385 745 ------- ------- -------
Total expenses 12,046 9,826 10,169 ------- ------- -------
Income from operations 1,625 2,074 1,181 Other nonoperating income 155 321 200 ------- ------- -------
Income before income tax 1,780 2,395 1,381 Provision for income taxes 134 843 442 ------- ------- -------
Income before cumulative effect of DD&A accounting change 1,646 1,552 939
Cumulative effect of DD&A accounting change, net of tax -- -- 1,058 ------- ------- -------
Net income $ 1,646 $ 1,552 $ 1,997 ======= ======= =======
Per share data: Income before cumulative effect of DD&A accounting change $0.35 $0.45 $0.37 Cumulative effect of DD&A accounting change -- -- 0.41 ----- ----- -----
Net income $0.35 $0.45 $0.78 ===== ===== =====
Weighted average number of shares outstanding 4,645,154 3,438,594 2,555,654 ========= ========= =========
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1994 and 1993 (In thousands) ===============================================================================
ASSETS 1994 1993 ------ ---- ----
Current assets: Cash and cash equivalents $ 2,632 $ 2,465 Accounts receivable, net of allowance of
$9-1994; $127-1993; 2,693 3,975 Due from partnerships and programs 140 158 Inventories and other current assets 428 261 ------- -------
Total current assets 5,893 6,859 ------- -------
Property and equipment: Gas and oil producing properties (Successful Efforts Method) 71,782 60,181 Other property and equipment 5,270 4,944 ------- -------
77,052 65,125 Less accumulated depreciation, depletion and amortization 28,487 29,647 ------- -------
48,565 35,478
Other assets 1,600 924 ------- -------
Total assets $56,058 $43,261 ======= =======
(Continued)
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1994 and 1993 (In thousands, except share data) ===============================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY 1994 1993 ------------------------------------ ---- ----
Current liabilities: Current portion of long-term debt and capital lease obligations $ 106 $ 283 Accounts payable 1,325 847 Accrued expenses 1,398 979 Due working interest and royalty owners 1,064 2,738 Deferred revenue 1,165 691 ------- -------
Total current liabilities 5,058 5,538 ------- -------
Long-term debt and capital lease obligations 12,889 720 Due working interest and royalty owners 888 1,404 Deferred revenue 333 674 Deferred taxes 8,011 7,810 Other long-term liabilities 404 372 ------- -------
Total liabilities 27,583 16,518 ------- -------
Commitments and contingencies
Stockholders' equity: Preferred stock, par value $1.00 per share; 1,000,000 shares authorized, none issued -- -- Common stock, par value $0.10 per share; 7,500,000 and 6,400,000 shares authorized, respectively; 4,712,713 and 4,703,677 shares issued and outstanding, respectively 471 470 Additional paid-in capital 31,039 30,981
Accumulated deficit since September 30, 1985 quasi-reorganization (2,847) (4,493) ------- -------
28,663 26,958
Less treasury stock, at cost, 63,360 and 72,792 shares of common stock, respectively 188 215 ------- -------
Total stockholders' equity 28,475 26,743 ------- -------
Total liabilities and stockholders' equity $56,058 $43,261 ======= =======
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
Years Ended December 31, 1994, 1993 and 1992 (In thousands) ===============================================================================
Accumulated Class A Additional Deficit Common Common Paid-in Since Treasury Stock Stock Capital 9/30/85 Stock ----- ----- ------- ------- -----
Balance January 1, 1992 $157 $103 $21,155 ($8,042) $221
Issuance of treasury stock -- -- 3 -- (64)
Exercise of stock options -- -- 6 -- --
Net income -- -- -- 1,997 -- ---- ---- ------- ------- ----
Balance December 31, 1992 157 103 21,164 (6,045) 157
Acquisition of treasury stock -- -- -- -- 129
Issuance of treasury stock -- -- 10 -- (86)
Public stock offering 310 (103) 9,741 -- --
Exercise of stock options 3 -- 66 -- 15
Net income -- -- -- 1,552 -- ---- ---- ------- ------ ----
Balance December 31, 1993 470 -- 30,981 (4,493) 215
Issuance of treasury stock -- -- 36 -- (34)
Issuance of common stock -- -- 32 -- --
Acquisition of treasury stock -- -- -- -- 7
Exercise of stock options 1 -- 10 -- --
Public stock offering- additional costs -- -- (20) -- --
Net income -- -- -- 1,646 -- ---- ---- ------- ------ ----
Balance December 31, 1994 $471 $ -- $31,039 ($2,847) $188 ==== ==== ======= ====== ====
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1994, 1993 and 1992 (In thousands) ===============================================================================
1994 1993 1992 ---- ---- ----
Cash flows from operating activities: Net income $1,646 $1,552 $1,997 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion and amortization 3,523 2,806 3,007 Deferred taxes 201 744 144 Cumulative effect of DD&A accounting change -- -- (1,058) Gain on asset sales (76) (141) (74) Issuance of stock for employee benefits and compensation expense 102 86 69 Other factors, net 12 13 17 Increase (decrease) in cash from changes in: Accounts receivable 1,282 (275) (379) Due from partnerships and programs 18 97 184 Due working interest and royalty owners (1,674) (340) 561 Inventories and other current assets (167) (105) 39 Accounts payable and accrued expenses 897 438 74 Deferred revenue 474 231 268 ------ ------ ------
Net cash provided by
operating activities 6,238 5,106 4,849 ------ ------ ------
Cash flows from investing activities: Proceeds from disposal of fixed assets 278 150 133 Payment for the acquisition of producing properties (6,234) -- -- Capital expenditures (10,500) (6,685) (2,715) Investment in limited partnership (290) -- -- Other assets (464) (161) (678) ------ ------ ------
Net cash used in investing activities (17,210) (6,696) (3,260) ------ ------ ------
(Continued)
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1994, 1993 and 1992 (In thousands) ===============================================================================
1994 1993 1992 ---- ---- ----
Cash flows from financing activities:
Borrowings under line of credit $13,300 $ 500 -- Payment on line of credit (1,000) -- -- Principal payments on long-term debt and capital lease obligations (320) (9,098) $ (759) Acquisition of treasury stock (7) (144) (5) Net proceeds from public offering of common stock -- 9,948 -- Additional costs of public offering of common stock (20) -- -- Proceeds from exercise of stock options 11 69 9 Other liabilities (825) (1,012) (53) ------ ------ ------
Net cash provided by (used in) financing activities 11,139 263 (808) ------ ------ ------ Net increase (decrease) in cash and cash equivalents 167 (1,327) 781 Cash and cash equivalents - beginning of period 2,465 3,792 3,011 ------ ------ ------
Cash and cash equivalents - end of period $2,632 $2,465 $3,792 ====== ====== ======
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest $216 $373 $732
Income taxes 55 180 308
Supplemental Schedule of Non-Cash Investment and Financing Activities:
Fixed assets acquired under capital lease -- $27 --
Like-kind exchange of property $3,270 -- --
Accompanying notes are an integral part of the consolidated financial statements.
1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. These consolidated financial statements include the combined accounts of Alamco and its subsidiaries, Aladel, HAWG and PAV. Aladel and HAWG are wholly owned subsidiaries of the Company. All sig- nificant intercompany balances have been eliminated in consolidation.
Revenue Recognition. Royalties, overrides and working interest revenues are recognized based on production. No material difference would result if revenues were recognized based on sales. Well tending income is recognized as revenue as services are performed.
Cash and Cash Equivalents. The Company considers certificates of deposit, U.S. government securities and other short-term securities with maturities of three months or less as cash and cash equivalents.
Fair Value of Financial Instruments. The following methods and assumptions were used by the Company in estimating the fair value of each class of financial instruments for which it is practicable to estimate that value.
For cash and cash equivalents, receivables, and payables, the carrying amounts approximate fair value because of the short maturity of these instru- ments. For long-term debt, including current maturities, the fair value of the Company's long-term debt approximates historically recorded cost since interest rates approximate market.
Off-Balance Sheet Risk. In accordance with industry practice, the Company has gas and oil sales contracts with commitments to sell minimum quantities of gas and oil, primarily at market prices, for varying periods.
Gas and Oil Producing Properties. The Company uses the successful efforts method of accounting for gas and oil producing properties. Under the successful efforts method, certain expenditures, such as geological and geophysical costs, exploratory dry hole costs, delay rentals, and other costs directly related to exploration are recognized currently as expenses. All direct costs relating to property acquisitions, successful exploratory wells, all development costs, and support equipment and facilities are capitalized and depreciated, depleted or amortized using the units-of-production method (Note 7). Production overhead and other costs are expensed as incurred. Gas and oil producing properties also include well equipment covered by capital lease obligations. Amortization of the lease assets is included in depreciation, depletion and amortization expense. Interest costs incurred in the drilling of wells are capitalized and amortized using the units-of-production method. The Company capitalized interest costs of $317,000 in 1994 and none in the years 1993 and 1992. Interest incurred during 1994 totalled $471,000.
The Company compares the carrying value of its gas and oil producing properties to the estimated future cash flow from such properties, less applicable income taxes (the "ceiling") in order to determine whether the carrying value of such properties should be reduced. No adjustment was necessary as of December 31, 1994, 1993, or 1992.
On September 30, 1985, as a part of the Company's quasi-reorganization to revalue its assets and liabilities, the carrying value of gas and oil producing properties was reduced to an estimated fair value. The quasi-reorganization was implemented to reflect the impaired ability at that time to fully recover the investments in gas and oil properties.
Other Property and Equipment. Other property and equipment are stated at cost, except that the carrying values of property and equipment were reduced to estimated fair value as of the quasi-reorganization. Depreciation of other property and equipment is computed using the straight-line method over estimated useful lives of three to forty years, without considering the recoverable value of equipment salvageable from the wells.
On an annual basis, the Company estimates the costs of future dismantlement, restoration, reclamation and abandonment of its gas and oil producing properties. Concurrently, the Company evaluates the estimated salvage value of equipment recoverable upon abandonment. At December 31, 1994, the Company's estimate of equipment salvage values is in excess of the costs of future dismantlement, restoration, reclamation and abandonment.
Costs of individual gas and oil wells determined to be uneconomical are charged to accumulated depreciation, depletion and amortization, with no gain or loss being recognized until the depositional group in which the well is included is abandoned. When other property and equipment are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred; significant renewals and betterments are capitalized.
Intangible Assets. Intangible assets, which are reported in other assets on the Company's balance sheet, consist of a non-compete and a consulting agreement arising from the acquisition of 62 wells in Southeastern Kentucky (Note 2). The values assigned to intangible assets are being amortized on a straight line basis over the life of the agreements which range from four to five years.
Covenant not to compete . . . . . . $312,000 Consulting agreement . . . . . . . . 390,000
Less accumulated amortization . . . (78,000) --------
$624,000 ========
Income Taxes. The Company accounts for certain income and expense items differently for financial reporting purposes than for purposes of computing income taxes currently payable. These differences arise primarily due to when certain income and expense items are recognized for financial reporting and tax purposes and are generally referred to as temporary differences. Provisions for deferred taxes are made in recognition of such temporary differences.
Common Stock Designation. In consideration of the Company's public stock offering, in 1994, the Board of Directors authorized that the number of authorized shares of the Class A Common Stock be decreased from 1,100,000 shares to zero. The Board further authorized that the shares previously designated as Class A Common Stock be restored to the status of authorized but unissued shares of the Company's common stock.
Income Per Share. Income per share amounts are computed by dividing the income before the cumulative effect of DD&A accounting change and net income by the weighted average number of shares outstanding in 1994, 1993 and 1992.
Reclassifications. Reclassifications have been made to certain amounts previously reported in the consolidated financial statements, principally with
respect to the Consolidated Statement of Cash Flows for the year ended December 31, 1993.
2 - PROPERTY ACQUISITIONS AND WELL SWAP
On March 31, 1994, the Company exchanged its interests (the "Well Exchange") in 141 gross wells for outside investors' interests in 237 gross wells. The exchange was effective March 1, 1994. The exchange has been treated as a like-kind exchange and no gain or loss has been recognized on this transaction.
In a separate transaction, the Company received a note in exchange for the sale of operating rights in a number of wells. Further, the Company sold its wholly-owned subsidiary, Interstate Resources, Inc. ("IRI"), in exchange for a note. The sale of the Company's operating rights and IRI were to the same non- affiliated party and combined into a single interest bearing note in the principal amount of $272,000. The gain resulting from the sale of operating rights and sale of IRI will be deferred and recognized as principal payments are received.
On July 18, 1994, the Company acquired certain gas and oil properties and intangible assets located in Southeastern Kentucky for $2.5 million in cash (Note 1). The Company acquired 62 wells (56.4 net wells) together with 34,000 gross acres (30,000 net acres) and became the operator of the wells.
On August 1, 1994, the Company acquired all of the interest held by a number of limited partnerships in 114 West Virginia gas wells (91.2 net wells), of which 102 were already operated by the Company (the "West Virginia Acquisition"). The Company acquired these wells for a net $3.8 million in cash.
Also, on August 1, 1994 the Company acquired seven wells and 1,275 acres in Whitley County, Kentucky, for $185,000. The Company became the operator effective as of the purchase date.
The Company also acquired 2.5 net wells producing from the Oriskany formation in the South Burns Chapel Field for $500 effective as of July 1, 1994.
These transactions have been accounted for under the purchase method and, accordingly, the operating results for the transactions have been included in the Company's consolidated operating results from the dates of the respective acquisitions forward.
As the West Virginia Acquisition and the Well Exchange represent a substantial majority of the assets acquired during the year, the following summary, prepared on a pro forma basis, combines the consolidated results of operations as if the two transactions had been consummated as of January 1, 1994.
The pro forma results are not necessarily indicative of what actually would have occurred if the acquisitions had been in effect for the entire periods presented. In addition, they are not intended to be a projection of future results and do not reflect any synergies that might be achieved from combined operations.
3 - SECTION 29 TAX CREDITS
The Company currently produces approximately 800,000 MMBtu per year of natural gas that is eligible for a tax credit of $1.00 per MMBtu under Internal Revenue Code ("IRC") Section 29. The tax credit applies to natural gas produced from "nonconventional" fuel sources, as defined, including gas production from Devonian Shale formations in certain West Virginia counties where the Company has production operations. In addition to producing from certain nonconventional fuel sources, the production must have been from wells drilled between December 31, 1979 and December 31, 1992, and the gas must be sold before December 31, 2002. The tax credit is allowed to reduce a taxpayer's regular tax liability but may not be used to reduce a taxpayer's alternative minimum tax ("AMT") liability. The credits also must be used in the tax year in which they are generated.
The Company is currently, and is projected to be in the future, an AMT taxpayer and therefore is unable to fully use the tax credits to reduce its tax liability. In this regard, through a series of transactions, the Company formed a partnership with a large East Coast financial institution (the"Institution"). The partnership is structured such that the Institution will be allocated IRC Section 29 tax credits as a result of production from properties contributed by the Company to the partnership. The Institution initially paid $1.0 million (reduced by $100,000 for certain expenses incurred by the Institution), and will pay additional amounts, up to $4.0 million, in installments prior to December 31, 2002, upon achieving certain production minimums and satisfying other conditions. The Company estimates that this transaction, which was effective August 11, 1994, will allow it to realize $0.65 for each $1.00 in available Section 29 tax credits generated by the producing properties.
As of August 11 1994, the effective date of the transaction, the Company recognized $1.0 million in deferred revenues and will recognize income from this transaction as the required gas production levels are achieved. In 1994 the Company recognized $249,000 in income relative to this transaction. Accordingly, as of December 31, 1994, the Company's balance sheet includes $751,000 in deferred revenues, of which $676,000 is current.
4 - SETTLEMENT OF COLUMBIA LITIGATION CLAIMS
On June 8, 1992, the Company settled its outstanding gas purchase contract claims against Columbia. Pursuant to the settlement agreement, the Company, on behalf of itself and other interest owners in the wells covered by the settlement, has an allowed claim in the amount of $11,000,000 against Columbia, without security or priority, in Columbia's bankruptcy reorganization proceedings. The Company's share of the allowed claim is estimated to be approximately 55 percent, with the balance going to the other interest owners in the wells covered by the settlement. The timing and actual amount to be received by the Company and other interest owners will be affected by the terms of Columbia's reorganization plan as finally approved by the Bankruptcy Court and the amount of assets available to satisfy Columbia's unsecured creditors. Because of the uncertainty as to the actual amount which may be received, the Company's financial statements do not include any benefits of the settlement. However, management believes that the ultimate payment in respect of the Company's claim is likely to be substantial.
5 - PUBLIC STOCK OFFERING
On July 29, 1993, the Company consummated a public offering at a price to the public of $5.50 per share for 2,700,000 shares of Common Stock, of which 2,000,000 shares were sold by the Company and 700,000 shares were sold by PNC. The Company's net proceeds from this sale approximated $10.2 million before
considering expenses associated with the stock offering. The Company used approximately $8.6 million of the net proceeds to repay its revolving credit facility loan balance with Bank One.
On August 18, 1993, the underwriters exercised their option to purchase at a price to the public of $5.50 per share an additional 405,000 shares, of which the first 333,596 shares were sold by PNC and the remaining 71,404 shares were newly issued shares sold by the Company. The aggregate 1,033,596 shares sold by PNC represented all of the non-voting Class A Common Stock issued to PNC by the Company as part of the 1988 debt restructuring. Upon the sale of the 1,033,596 shares in the stock offering, the shares automatically converted to voting Common Stock on a one-for-one basis.
6 - LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
The Company has a $25.0 million revolving credit facility with Bank One which calls for the payment of interest only until July 1, 1996 at which time all outstanding principal and interest amounts are due. Interest accrues and is paid monthly at a rate of Bank One's prime rate plus three-fourths of one percent. During 1993, using a portion of the 1993 stock offering, the Company repaid all amounts outstanding under the Bank One credit facility. As of December 31, 1994 the aggregate amount of borrowing under the Bank One revolving credit facility was $12,800,000. Bank One's prime interest rate on December 31, 1994, was 8.5 percent.
The credit facility is subject to semiannual borrowing base revisions (in March and September of each year) to be made in accordance with borrowing base recalculations performed by Bank One. Revisions could result in the extension of credit and repayment terms or, in the case of erosion of the borrowing base, the reduction of outstanding principal amounts or the amount of the credit facility. Based on the latest Bank One recalculation, performed in September 1994, the borrowing base is sufficient to allow full utilization of the maximum $25.0 million credit facility.
In addition to interest payments, the Company is required to pay a commitment fee equal to the difference between the facility amount and the amount borrowed multiplied by one-half of one percent prorated into quarterly payments. The agreement also contains covenants which, among other things, require that the Company maintain specified levels of cash flow, stockholders' equity and ratio of current assets to current liabilities. The credit facility is collateralized by all of the Company's assets including the Company's gas and oil reserves.
Included in 1994 long-term debt is one installment sales obligation of $27,000 to McJunkin Corporation ("McJunkin"). Interest on this obligation, which is scheduled to be satisfied during the first quarter of 1995, is paid monthly at 8.7% per annum.
Long-term debt at December 31, 1994 also included five note obligations to PNC in the aggregate remaining amount of $146,000 relative to the settlement of certain investor-related lawsuits. The terms of the obligations vary by note; however the largest of the five notes, in the original principal amount of $263,000, requires quarterly payments. Interest accrues on the notes at PNC's prime rate, except for three notes aggregating $193,500 in original principal on which interest payments are not required.
The aggregate maturities of long-term debt for each of the next five years and thereafter are as follows (in thousands):
1995 $ 106 1996 12,832 1997 20 1998 19 1999 and thereafter 18 ------ $12,995
======
The Company also leases certain equipment used in the production of gas and oil under three lease programs with McJunkin. These equipment leases are for varying terms with purchase options at the end of the lease term. In addition, as part of a 1988 restructuring with McJunkin, the leases were amended to permit the Company to extend the leases for varying periods with rentals due with respect to the extension periods to be paid from a 2-1/2 percent working interest of the Company on the wells where the leased equipment is situated. The Company has extended the lease periods for all three programs. Since rental payments due under such extensions are contingent upon the proceeds of gas and oil production, such payments will be expensed as incurred. There are no future minimum lease payments due.
Gas and oil properties related to capital leases total $2,328,000 and are fully amortized, as adjusted for the quasi-reorganization effected September 30, 1985.
7 - ACCOUNTING CHANGE
Effective January 1, 1992, the Company changed the method used to calculate depreciation, depletion and amortization ("DD&A") of producing gas and oil properties from an individual well basis to an aggregation of wells by a common geological depositional system. The cumulative effect of the pre-tax accounting change was $1,763,000 and increased net income by $1,058,000 in 1992, which includes the effect on prior years, net of tax. The effect of the change during 1992 increased income from operations by $17,000.
8 - CASH AND CASH EQUIVALENTS
Cash and cash equivalents totalled $2,632,000 at December 31, 1994. Of this amount, approximately $1,559,000 was available for general corporate purposes and the balance was held for third parties, including $207,000 in gas and oil sales proceeds held for eventual distribution to outside working interests and royalty owners, $646,000 representing the outside interests' estimated share of cash prepaid by CNG for future gas deliveries, and $220,000 withheld from outside working interests' proceed distributions to be utilized for future ad valorem tax payments (Note 9). The Company's cash balance at December 31, 1994 includes $2,340,000 invested in commercial paper, U.S. Government and Agency Securities and Bankers' Acceptances, the annualized annual percent of return of which was 5.5 percent at December 31, 1994.
9 - PLUGGING AND AD VALOREM TAX FUNDS
The Company retains a portion of outside investors' monthly gas and oil production proceeds to be utilized for future well plugging and abandonment costs and ad valorem tax payments. The funds, totalling $662,000 at December 31, 1994, are invested in securities issued or guaranteed by the United States Treasury in accounts segregated from those of the Company. Interest earned on the funds accrues to the benefit of the working interest owners. Included in other assets is $442,000 for future ad valorem payments and plugging and abandonments. Corresponding amounts recorded in assets are included in liabilities.
10 - INCOME TAXES
The following table details the components of the Company's income tax expense for the year 1992 through 1994.
1994 1993 1992 ---- ---- ---- (In thousands)
Federal: Current ($67) $ 99 $298 Deferred 397 618 46
---- ---- ----
Total Federal 330 717 344 ---- ---- ----
State: Deferred (196) 126 98 ____ ____ ____
Total $134 $843 $442 ==== ==== ====
Reconciliations of the income tax provision (benefit) computed at the statutory rate and the provision for income taxes as shown on the Statement of Income are summarized below:
Year Ended December 31, -------------------------- 1994 1993 1992 ---- ---- ---- (In thousands)
Tax provision computed at statutory rate $592 $814 $470
State taxes 104 126 83
Change in effective state tax rate (255) -- --
Use of percentage depletion (321) (103) (122)
Other 14 6 11 ---- ---- -----
Provision (benefit) for income taxes $134 $843 $442 ==== ==== =====
The change in effective state tax rate reflects the Company's new business activities in states with lower tax rates and recently implemented tax planning activities.
The components of the net deferred tax liability are as follows:
December 31, ---------------------------- 1994 1993 1992 ---- ---- ---- (In thousands)
Depreciation, depletion and amortization $12,293 $10,668 $9,694 Accounts receivable write-off (30) (31) (33) Future litigation payments (72) (126) (161) Sale of partnership interest (293) -- -- Net operating loss carryforwards (1,704) (490) (306) AMT credits (746) (837) (699) ITC carryforwards (1,394) (1,371) (1,409) Other (43) (3) (20) ------- ------ ------
Net deferred tax liability $8,011 $ 7,810 $7,066 ======= ====== ======
The Company's investment tax credit carryforwards expire between the years 1996 and 2000.
Prior to August 1994, the Company owned interests in 504 gas wells which
qualified for Devonian Shale tax credits. These credits which approximate $1.00 per MMBtu of qualified gas produced in 1994 can be applied to reduce regular income taxes payable only in the years the gas is produced. Effective August 11, 1994, the Company formed a partnership with a large East Coast financial institution structured such that the Institution will be allocated substantially all of the Devonian Shale tax credits previously allocated to the Company (see Note 3). No Devonian Shale tax credits were used by the Company in years 1994, 1993 or 1992.
During 1992, the Company changed its method of computing income taxes to reflect adoption of Statement 109 retroactive to January 1, 1990. The adoption of Statement 109 resulted in the recognition of approximately $4.7 million of net deferred tax liabilities in 1989. Statement 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
11 - STOCKHOLDERS RIGHTS PLAN
On November 30, 1994, the Board of Directors of the Company adopted a Preferred Stock Purchase Rights Plan (the "Rights Plan"). Under the Rights Plan, the Board declared a dividend of one preferred share purchase Right for each outstanding share of Alamco Common Stock. In the event that any entity acquires 15% or more of the outstanding shares of Common Stock of the Company, the Rights will become exercisable subject to the terms of the Rights Plan and will entitle each holder of a Right (other than the acquiring person or group) under certain circumstances to purchase that number of shares of Alamco Common Stock having a market value equal to two times the exercise price of the Right.
Rights were distributed to stockholders of record at the close of business on December 12, 1994. The Rights will trade with the Company's Common Stock until the Rights become exercisable and no separate certificates will be issued until that time. The rights will expire on December 12, 2004. The Rights Plan is designed to enable the Company and its Board to develop and preserve long- term value for stockholders and to protect stockholders in the event an attempt is made to acquire control of the Company through certain coercive or unfair tactics or without a bona fide offer at fair value to all of the stockholders of the Company.
12 - SALES CONCENTRATION
During 1994, gas sales to PAV, Hope and CNG accounted for 53.8 percent, 28.2 percent and 5.3 percent, respectively, of the Company's gas and oil sales. In 1993 sales to Hope, CNG, Phoenix and Enron accounted for 25.2 percent, 24.1 percent, 14.4 percent and 14.2 percent, respectively, of the Company's gas and oil sales. During 1992 a substantial portion of the Company's revenues was derived from the sale of gas to CNG and gas marketers purchasing gas transported on the Columbia pipeline system (see Part I, Item 1. "Business"). Sales to CNG and the gas marketers approximated 51 percent and 17 percent in 1992.
13 - COMMITMENTS AND CONTINGENCIES
CNG Agreement. In November 1989, CNG made a $3,800,000 prepayment for 1,565,000 MMBtu of gas to be produced from the Company's Tallmansville production area. CNG has the right, within certain specified limitations, to take deliveries of this gas up to December 31, 1999. As of December 31, 1994, CNG has taken delivery of 1,120,000 MMBtu of Tallmansville gas for which it has prepaid. The Company recognizes its proportionate share of this deferred revenue as volumes are recouped in accordance with the CNG Agreement.
14 - STOCK OPTIONS AND BENEFIT PLANS
Employee Stock Option Plans. Stock options have been granted to Company employees through two stock option plans, the 1992 Employees' Stock Option Plan (the "1992 Stock Option Plan") and the 1982 Employees' Stock Option Plan (the "1982 Stock Option Plan").
The 1992 Stock Option Plan was established March 20, 1992, and provides for the grant to officers and other key management employees of the Company of stock options covering an aggregate of up to 100,000 shares of the Company's Common Stock. Options may be designated as either non-qualified stock options or incentive stock options, the latter of which must be exercised sequentially in grant date order. The Compensation Committee of the Company's Board of Directors administers the 1992 Stock Option Plan. The exercise price for each option granted must be equal to the fair market value per share of the Company's Common Stock on the date of the granting of the options (except when incentive stock options are granted to any person who owns more than 10% of the total combined voting power of all classes of stock of the Company, the exercise price of each option will be at least 110% of the fair market value of the Common Stock). At December 31, 1994, there were 35,500 shares available for future grants.
The 1982 Stock Option Plan provided for the grant of stock options to officers and other employees of the Company for up to 65,000 shares of the Company's Common Stock. As of November 8, 1992, no additional options may be granted from the 1982 Stock Option Plan. Options are designated as either non-
qualified stock options or incentive stock options. Information with respect to the options granted under each plan follows:
1982 EMPLOYEES' 1992 EMPLOYEES' STOCK OPTION PLAN STOCK OPTION PLAN ----------------- ----------------- Option Option Number of Price Range Number of Price Range Shares Per Share* Shares Per Share* ------ ---------- ------ ----------
Outstanding at January 1, 1992 49,000 $1.25--3.15 --
Granted 4,000 2.625 17,500 $4.875 Exercised -- -- Canceled 2,500 1.875-2.50 -- ------ ------ Outstanding at December 31, 1992 50,500 1.25--3.15 17,500 4.875 ------ ------
Granted -- 36,000 6.75 Exercised 17,100 1.25--2.50 -- Canceled -- -- ------ ------ Outstanding at December 31, 1993 33,400 1.875-3.15 53,500 4.875-6.75 ------ ------
Granted -- 18,500 6.75 Exercised -- -- Canceled 19,900 1.875-3.15 7,500 4.875 ------ ------ Outstanding at December 31, 1994 13,500 1.875-3.15 64,500 4.875-6.75 ------ ------
Exercisable at December 31, 1994 13,500 1.875-3.15 18,665 4.875-6.75 ------ ------
------------------------ *Reflects the option price range applicable to only those installments included in the total number of shares with respect to which the options are or were exercisable.
Non-Qualified Stock Options. At December 31, 1994, non-qualified stock options granted outside of any stockholder-approved plan totalled 370,100 shares of Common Stock and were held by 10 employees. At December 31, 1994, 225,433 shares were exercisable with the remaining stock options becoming exercisable at various dates between March 1995 and November 1996. The stock option exercise prices range from $1.875 to $6.75 per share.
The 1992 Equity Compensation Plan for Outside Directors. The 1992 Equity Compensation Plan for Outside Directors (the "1992 Outside Directors' Plan") was established March 20, 1992 and provides for a maximum number of 75,000 shares of Common Stock from the Company's authorized and unissued shares of Common Stock and/or treasury shares to be available for issuance, subject to adjustments in certain instances. Outside Directors receive 50 percent of their annual retainer in the form of Common Stock and may elect to receive any or all of the remaining cash balance of their retainer in the form of Common Stock.
Outside Directors' Stock Option Plan. The 1982 Outside Directors' Stock Option Plan (the "Outside Directors' Plan") provided for the automatic grant of options of the Company's Common Stock to non-employee Directors of the Company. As of November 9, 1991, stock options may not be granted under the Outside Directors' Plan. Information with respect to the Outside Directors' Plan is presented below. Number of Option Price Range Shares Per Share* -------- -----------------
Outstanding at January 1, 1992 10,400 $2.50--$50.00 ------
Granted -- Exercised -- Canceled 2,400 2.50--50.00 ------
Outstanding at December 31, 1992 8,000 ------
Granted -- Exercised 2,800 2.50---5.60 Canceled 400 50.00 ------
Outstanding at December 31, 1993 4,800 2.50--32.50 ------
Granted -- Exercised -- Canceled 400 32.50 ------
Outstanding at December 31, 1994 4,400 2.50-3.875 ------
Exercisable at December 31, 1994 4,400 2.50-3.875 ------
------------------------ *Reflects the option price range applicable to only those installments included in the total number of shares with respect to which the options are or were exercisable.
Employee Savings and Protection Plan. Effective October 1, 1987, the Company instituted a 401(k) Plan titled the Alamco, Inc. Employee Savings and Protection Plan. In addition to employee contributions, the Company contributed cash and stock of approximately $110,000, $97,000 and $87,000 in 1994, 1993 and
1992, respectively.
15 - SUPPLEMENTAL INFORMATION RELATED TO GAS AND OIL PRODUCING ACTIVITIES (Unaudited)
Costs incurred by the Company in gas and oil property acquisition, exploration, and development are presented below:
Year Ended December 31, --------------------------- 1994 1993 1992 ---- ---- ---- (In thousands)
Costs (capitalized or expensed) for:
Property acquisition $ 6,740 $ 592 $ 806 Exploration -- -- -- Development 9,578 5,479 1,451 ------ ------ ------ $16,318 $6,071 $2,257 ------ ------ ------
Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Exploration costs include the costs of geological and geophysical activity, dry holes, and drilling and equipping exploratory wells. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat, gather, and store gas and oil, and depreciation of support equipment used in development activities.
Aggregate capitalized costs for the Company related to gas and oil exploration and production activities, with applicable accumulated depreciation, depletion and amortization, are presented below:
1994 1993
---------------------- ----------------------- Accumu- Accumu- lated lated Cost DD&A Net Cost DD&A Net ---- ---- --- ---- ---- --- (In thousands)
Proved developed properties $71,782 $25,880 $45,902 $60,181 $27,325 $32,856
Pipelines and processing equipment 1,734 562 1,172 2,014 525 1,489
Vehicles, machinery and equipment consisting principally of assets used in gas and oil producing activities 1,913 1,024 889 1,516 855 661
Buildings used in gas and oil producing activities 206 84 122 160 87 73 ------- ------- ------- ------- ------- -------
$75,635 $27,550 $48,085 $63,871 $28,792 $35,079 ------- ------- ------- ------- ------- -------
The results of operations for gas and oil producing activities are presented below:
Year Ended December 31, --------------------------- 1994 1993 1992 ---- ---- ---- (In thousands)
Gas and oil sales revenues $11,993 $9,504 $8,855 ------ ------ ------ Expenses: Production 3,287 2,259 1,987 Depreciation, depletion and amortization 2,790 2,734 2,933 Exploration -- -- -- ------ ------ ------ 6,077 4,993 4,920 ------ ------ ------ Results of operations for gas and oil producing activities before provision for income taxes 5,916 4,511 3,935
Provision for income tax 887 677 590 ------ ------ ------ Results of operations for gas and oil producing activities $5,029 $3,834 $3,345 ------ ------ ------
Production expenses include those costs incurred to operate and maintain productive wells and related equipment and include costs such as labor, repairs and maintenance, materials, supplies, fuel consumed and other production taxes. Depreciation, depletion and amortization expense includes those costs associated with capitalized acquisition, exploration, and development costs including the depreciation applicable to support equipment. Exploration expenses would include the cost of exploratory dry holes, the geological and geophysical costs associated with undeveloped properties and write-offs or amortization of lease acquisition and other costs associated with undeveloped properties. The provision for income taxes is computed considering the Company's status as an alternative minimum tax payor.
The increase in the results of operations for gas and oil producing activities between 1994 and 1993 resulted from higher gas and oil sales revenues due primarily to the Company's successful 1994 acquisition and drilling programs. The increase between 1993 and 1992 reflects higher 1993 gas and oil sales revenues primarily due to the Company's successful 1993 capital investment program.
Estimates of net proved reserves of gas and oil for the Company, all of which are within the United States, are as follows:
Year Ended December 31,
-------------------------------------------------- 1994 1993 1992 ------------ ----------- ----------- MCF BBL MCF BBL MCF BBL --- --- --- --- --- --- (In thousands)
Proved reserves, beginning of year 82,617 897 58,830 881 45,751 644 Extensions, discoveries and other additions 13,529 435 23,727 142 6,400 85 Acquisitions 16,888 131 988 5 2,788 11 Revisions of previous estimates 10,995 4 2,269 (94) 6,840 173 Production (4,404) (68) (3,197) (37) (2,949) (32) ------- ----- ------ --- ------ --- Proved reserves, end of year 119,625 1,399 82,617 897 58,830 881
------- ----- ------ --- ------ ---
Proved developed reserves 85,654 1,164 56,560 605 43,502 524 ------- ----- ------ --- ------ ---
These estimates are based primarily on the reports of independent petroleum and geological engineers. Such reports are, by their very nature, inexact and subject to changes and revisions. Proved reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves increased in 1994 due to the success of the Company's acquisition and development drilling programs. Proved reserves increased in 1993 because of the success of the 1993 drilling program. Reserves were also added due to the inclusion of several additional drilling prospects on existing company acreage and on acreage leased in 1993. The estimates include only those amounts considered to be proved reserves and do not include additional amounts that may result from new discoveries in the future. Proved developed reserves are those reserves that are expected to be recovered through existing wells with existing equipment and operating methods.
The estimated future net cash flow and the present value of the proved reserves before taxes are presented below.
Proved Proved Total Developed Undeveloped Proved --------- ----------- ------ (In thousands)
Estimated future net cash flow attributable to production during
1995 $ 8,752 $(1,950) $ 6,802 1996 8,820 (914) 7,906 1997 8,166 203 8,369 1998 7,648 307 7,955 1999 and thereafter 93,391 43,080 136,471 ________ _______ _______
Total 126,777 40,726 167,503
Present value of future cash flow 58,349 9,862 68,211
Estimated future net cash flow represents future cash inflows generated by the sale of the proved reserves less estimated production and future development cost. For production from wells under fixed priced gas purchase contracts, the gas price used is the contractual gas price for the term of the contract. The gas price used is $2.20 per MCF and the oil price used is $15.13 per barrel. Production costs are based on those in effect at December 31, 1994. The estimated future net cash flow is based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. No assurance of levels of gas and oil prices and costs can be given nor can assurance be given that proved reserves will be developed within the periods indicated. Present value is calculated by discounting estimated future net revenue by 10 percent.
Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Estimated future net cash flow represents future cash inflows generated by the sale of the proved reserves less estimated production and future development cost. Future income tax expenses are computed by applying the statutory rate and tax laws applicable to the future pre-tax net cash flows for each year, less the tax basis of the properties, and giving
effect to permanent differences and net operating loss, investment tax credit, and percentage depletion carryforwards which exist as of the end of each year. In addition, 504 of the Company's gas wells qualify for Devonian Shale tax credits under Section 29 of the Internal Revenue Code. These tax credits, which in 1994, 1993 and 1992, are approximately $1.000, $.977, and $0.953, respectively, per MMBtu, of qualified gas produced, must be used in the year in which they originated and cannot be carried forward or back. During 1994, the Company entered into a transaction which allocated substantially all of its Devonian Shale tax credits to a third party (Note 3). Therefore, no Devonian Shale tax credits were included in the 1994 tax calculation. For 1993 and 1992, Devonian Shale tax credits expected to be generated from qualified wells were reflected as reductions of future income tax expense on gas and oil producing activities.
Year Ended December 31, -------------------------- 1994 1993 1992 ---- ---- ---- (In thousands)
Future cash inflows $275,745 $225,423 $151,876 Future production and development costs (108,241) (82,499) (62,520) Future income tax expense (42,915) (33,874) (18,527) -------- -------- --------
Future net cash flows 124,589 109,050 70,829
10% annual discount for estimated timing of cash flows (77,184) (65,395) (39,673) -------- -------- -------- Standardized measure of discounted future net cash flows $ 47,405 $ 43,655 $ 31,156 -------- -------- --------
Approximately 93.4 percent of the Company's reserves are natural gas reserves, the price for which has declined since year-end 1994. A recalculation of the standardized measure of discounted future net cash flows using prices at February 28, 1995 results in a decrease of $6.6 million to $40.8 million. The following table summarizes the principal sources of change in the standardized measure of discounted future cash flows:
Year Ended December 31, -------------------------- 1994 1993 1992 ---- ---- ---- (In thousands) Sales and transfers of gas and oil produced, net of production costs $(8,706) $(7,245) $(6,868) Net changes in prices, production and development costs, and quality estimates 26,825 48,702 22,426 Addition of proved undeveloped reserves 16,039 17,590 6,206 Development costs incurred during the period (9,578) (5,479) (1,451) Accretion of discount 6,540 3,967 2,961 Net change in income taxes (9,041) (15,347) (4,978) Other, including changes in the discount other than due to accretion (18,329) (29,689) (13,023) ------- ------- ------- $ 3,750 $12,499 $ 5,273 ------- ------- -------
It is necessary to emphasize that the data presented above should not be viewed as necessarily representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured
with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand, and governmental control, among other factors. Furthermore, actual prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. In addition, the reported data are applicable only to gas and oil reserves classified as proved; no amounts are included with respect to additional reserves that may become proved in the future. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
Item 9.
Item 9. Changes In and Disagreements With Accountants on Accounting and --------------------------------------------------------------- Financial Disclosure --------------------
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant -------------------------------------------------- Incorporated by reference from the Company's Proxy Statement to be filed not later than 120 days after the Company's 1994 fiscal year end.
Item 11.
Item 11. Executive Compensation ---------------------- Incorporated by reference from the Company's Proxy Statement to be filed not later than 120 days after the Company's 1994 fiscal year end. The Report of the Compensation Committee of the Board of Directors is not incorporated by reference herein.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management -------------------------------------------------------------- Incorporated by reference from the Company's Proxy Statement to be filed not later than 120 days after the Company's 1994 fiscal year end.
Item 13.
Item 13. Certain Relationships and Related Transactions ---------------------------------------------- Incorporated by reference from the Company's Proxy Statement to be filed not later than 120 days after the Company's 1994 fiscal year end.
PART IV
Item 14.
Item 14. Exhibits and Reports on Form 8-K -------------------------------- (a) 1. and 2. Financial Statements --------------------
Financial Statements included in this report:
Alamco, Inc., a Delaware corporation Independent Auditor's Report Consolidated Statement of Income for the Years Ended December 31, 1994, 1993 and 1992 Consolidated Balance Sheet as of December 31, 1994 and 1993 Consolidated Statement of Changes in Stockholders' Equity for the Years Ended December 31, 1994, 1993 and 1992 Consolidated Statement of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 Notes to Consolidated Financial Statements
Signatures ----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf of the undersigned, thereunto duly authorized.
ALAMCO, INC. (Registrant)
By: /s/ John L. Schwager ---------------------------------- John L. Schwager, President, Chief Executive Officer, Principal Executive Officer and Principal Financial Officer
Dated: March 24, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Signature and Title ---- -------------------
/s/ John L. Schwager March 24, 1995 -------------------------- John L. Schwager President, Chief Executive Officer, Principal Executive Officer, Principal Financial Officer and Director
March 24, 1995 /s/ Robert S. Maust -------------------------- Robert S. Maust Director
March 24, 1995 /s/ James B. Gehr -------------------------- James B. Gehr Director
March 24, 1995 /s/ Richard R. Hoffman -------------------------- Richard R. Hoffman Executive Vice President, Chief Operating Officer and Director
March 24, 1995 /s/ Stephen L. Barr -------------------------- Stephen L. Barr Director
March 24, 1995 /s/ James H. Weber -------------------------- James H. Weber Director
March 24, 1995 /s/ Thomas M. Levine -------------------------- Thomas M. Levine Director
March 24, 1995 /s/ Steven E. May -------------------------- Vice President and Controller (Principal Accounting Officer)
INDEX TO EXHIBITS
The following exhibits to this report are filed herewith or, if marked with an asterisk (*), are incorporated herein by reference:
Note (1): Commission File No. 1-8490
Note (2): Indicates management contracts and compensation plans.