Item 1. Business.
Alamco, Inc. (the "Company" or "Alamco") is an Appalachian-based independent gas and oil producer actively engaged in the acquisition, exploitation, exploration, development and production of domestic gas and oil. Alamco's activities are conducted in West Virginia, Tennessee and Kentucky, with an 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 147.8 equivalent billion cubic feet ("EBCF") as of December 31, 1996, using a conversion of six thousand cubic feet of gas to one barrel of oil. As of December 31, 1996, Alamco had an average ownership interest of 86.3 percent in 1,203 gross wells and operated 94.7 percent of the wells in which it had 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. Alamco's executive offices are located at 200 West Main Street, Clarksburg, West Virginia 26301, and its telephone number is (304) 623-6671. The Company and its subsidiaries currently employ approximately 90 persons on a full time basis. The Company's Common Stock is listed on the American Stock Exchange ("AMEX") under the trading symbol "AXO".
RECENT DEVELOPMENTS
Alamco, Inc. announced on January 16, 1997, that its Board of Directors had retained Principal Financial Securities, Inc. to assist it in exploring strategic alternatives for increasing shareholder value, including the possibility of a sale or merger of part or all of the Company.
The Board noted that, while it had determined that these alternatives should be explored to see if they would yield a superior value for shareholders, the Board had not made any determination that the Company will be sold or merged or that such a transaction would be in the best interest of shareholders.
BUSINESS STRATEGY
Alamco's business strategy is to build stockholder value through the efficient growth of its gas and oil reserves and production in the Appalachian Basin while pursuing complementary business lines. To accomplish this strategy, the Company has focused on increasing its gas and oil reserves through development and exploratory drilling, property acquisitions, and infrastructure development, including the installation of pipelines in areas in Kentucky and Tennessee where successful exploration has occurred. Using this strategy, the Company's reserves have increased in each of the past nine years to estimated reserves of 147.8 EBCF at December 31, 1996. This compares favorably to estimated reserves of 137.1 EBCF, 128.0 EBCF and 88.0 EBCF as of December 31, 1995, 1994 and 1993, respectively.
The Company focuses its activities in the Appalachian Basin, which is geographically one of the largest and oldest gas and oil producing regions in the United States. Alamco and other operators in the Appalachian Basin have historically experienced high drilling success rates in the formations in the Basin, with wells generally producing for more than 25 years, although at low production volumes. The Company has been nationally recognized as a leader in finding reserves at a lower cost than its competitors and will continue to strive to keep its finding costs low in this phase of expansion of its gas and oil reserve base. Alamco 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. Exploration, coupled with development of new discoveries and infrastructure development in Kentucky and Tennessee, will further lay the groundwork for long-term expansion of Alamco's gas and oil reserves.
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. Upward revisions in prior years have been due to, among other things, the Company's effort to maximize productive capability through enhanced operating techniques and, thus, an increase in ultimate recoverable reserves by reducing reservoir abandonment pressures and increasing the well drainage area of its existing producing properties.
Alamco has diversified its business by entering into certain oil field- related service businesses. In addition to providing these services for itself, the Company has made the services available to others in the gas and oil industry. HAWG HAULING & DISPOSAL, INC. ("HAWG"), a brine hauling and disposal service, is a wholly-owned subsidiary of the Company and Phoenix-Alamco Ventures, a Limited Liability Company ("PAV"), owned jointly by the Company and Phoenix Energy Sales Company ("Phoenix"), is engaged in the marketing of Alamco's and other working interest owners' gas. Revenues generated by HAWG and PAV were approximately 2.0 percent of total revenues in 1996. In 1996, Alamco invested $2.3 million in a pipeline system in Tennessee to enable the Company to increase its flexibility in marketing gas and to improve gas sales prices. The Company plans to purchase and resell third-party gas in order to generate additional profits in the future.
Alamco pursues the acquisition of producing properties that will enhance the Company's revenue base without proportional increases in overhead costs. The Company focuses its attention on 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, Alamco will continue to evaluate the purchase of outside investors' interests in wells operated by the Company.
GAS AND OIL EXPLORATION AND DEVELOPMENT ACTIVITIES
At December 31, 1996, Alamco's proved reserves totalled 147.8 EBCF, representing a 10.7 EBCF increase from year-end 1995 reserves. Based on these reserve additions, the Company replaced 250 percent of the 6.9 EBCF it sold during 1996. Alamco invested $12,497,000 in gas and oil exploration and development activities during the year, including $2,351,000 in the construction of pipelines. 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 investment program.
DRILLING ACTIVITIES
A total of 20.4 EBCF was added to the Company's reserves as a result of the 1996 drilling program. Alamco invested $9,920,000 or 79.4 percent of its gas and oil exploration and development expenditures in the drilling of 35 gross (34 net) wells, of which 29 gross (28 net) wells were successful. Alamco drilled 14 gross wells in West Virginia, 15 gross wells in Kentucky and 6 gross wells in Tennessee.
All of the wells drilled in West Virginia were drilled to the deep Oriskany formation in the South Burns Chapel Field in Monongalia and Preston Counties.
Thirteen of the 15 wells drilled in Kentucky were located in the Company's South Key Rock Prospect. These wells produce from the Big Lime formation.
Four of the six wells drilled in Tennessee were drilled on the Company's Carden Prospect. Three of these wells produce gas from the Big Lime formation while the remaining one continues to be evaluated for the feasibility of commercial development of the Chattanooga Shale on the prospect.
A number of additional prospects have been identified on Company-held acreage in the South Burns Chapel Field in West Virginia, in both the Days Chapel Field and the Carden Prospect in Tennessee, and in the Key Rock Prospect in Kentucky. (See "Future Activities").
RECOMPLETION ACTIVITIES
Alamco did not invest in any recompletion projects during 1996, as compared to investments of $314,000 and $266,000 in 1995 and 1994, respectively. The Company believes its inventory of wells contains a significant number of recompletion candidates.
ACQUISITION ACTIVITIES
In 1996, Alamco invested $226,000, or 1.8 percent of its gas and oil development expenditures, in the acquisition of 20.9 net wells, as compared to investments of $1,384,000 and $6,234,000 in 1995 and 1994, respectively. The program involved the acquisition of outside investors' interests in wells operated by Alamco.
INFRASTRUCTURE DEVELOPMENT
To move the South Key Rock gas in Kentucky to market, the Company installed a pipeline into Tennessee to interconnect with a local gas utility's distribution system. Alamco invested $2,351,000, or 18.8 percent of its 1996 gas and oil development expenditures, to complete an additional 23 miles of pipeline which connects its Days Chapel Field in Tennessee with the same distribution system.
GAS AND OIL PRODUCTION AND SALES
In 1996, gas sales accounted for 92 percent of Alamco's total gas and oil sales. The average 1996 sales price received by the Company was $2.80 per MMBtu ($3.05 per MCF) for gas and $19.38 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, 1996, 1995 and 1994.
PRODUCTION AND SALES STATISTICS
Year Ended December 31, 1996 1995 1994
Net Production:
Gas (MCF) 6,368,052 5,363,664 4,404,187 Oil (BBL) 91,654 87,573 67,749
Equivalent (MCF)(a) 6,917,976 5,889,102 4,810,681
Average Production Per Day: Gas (MCF) 17,447 14,695 12,066
Oil (BBL) 251 240 186
Equivalent (MCF)(a) 18,953 16,135 13,182 Average Sales Price:
Per MCF of Gas $3.05 $2.10 $2.50
Per BBL of Oil $19.38 $15.90 $14.52 Average Cost of Production $0.97 $0.87 $0.78 ($/Mcfe)(b)
Average Cost of Production $0.31 $0.40 $0.31 Per Dollar of Sales
(a) Oil production is converted to gas equivalents at a rate of 6 MCF per barrel. (b) Restated for 1995 and 1994 to reflect revised expense classifications.
These classifications have been revised to reflect the change in the Company's focus from a drilling fund operator to a company which drills and operates wells primarily for its own account.
THIRD-PARTY WELL TENDING SERVICES
In the aggregate, as of December 31, 1996, Alamco owned approximately 89.5 percent of all Company operated wells, with the remaining 10.5 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 1996, the monthly fees were $351 per well for gas wells and $426 per well for oil wells compared to monthly charges in 1995 of $337 per well for most gas wells and $409 per well for most oil wells. In 1996, about 130 wells were not subject to the monthly operating fee due to temporary abandonments. The third party services revenue which the Company generates from these fees accounted for approximately 3.9 percent, 5.1 percent, and 9.0 percent of the Company's revenues in 1996, 1995 and 1994, respectively. Third party services revenue has decreased and is expected to continue to decrease as Alamco purchases the interests of outside investors in Company operated wells.
Effective March 1, 1994, Alamco exchanged its interests in approximately 141 gross wells for outside investors' interests in approximately 237 gross wells located in West Virginia. Third party services revenue was substantially reduced because this like-kind exchange reduced the number of wells that the Company operated for outside investors. Alamco believes, however, that this reduction in third party services revenue has been offset over time by the effect of higher gas and oil revenues attributable to the Company's greater ownership interest in the wells.
THIRD PARTY BRINE HAULING AND DISPOSAL SERVICES
HAWG, a wholly-owned subsidiary, is a commercial brine hauling and disposal service company originally formed to provide service for Company- operated wells. The service entails, for a fee, the transportation of brine to central processing facilities and injection of the brine into disposal wells. The subsidiary now 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 two commercial disposal wells and facilities in West Virginia and has preliminary plans to convert up to two additional wells in 1997. In 1996, HAWG provided 1.0 percent of Alamco's total revenues.
GAS MARKETING, GATHERING AND TRANSPORTATION
As a response to the changing gas marketing environment, in October 1993 the Company formed PAV with Phoenix, a gas marketing company. PAV provides gas marketing services to Alamco and other interest owners in certain Alamco operated wells. PAV has the exclusive right to market approximately 55 percent of Alamco's West Virginia gas supply. PAV seeks diversification for Alamco's gas sales to other marketing entities, local distribution companies and industrial users with a combination of short-term deals (less than a month), mid-term deals (one month to one year) and long-term deals (one year or more).
While Alamco's share of the profits from PAV have not been significant, the prices received for gas sales marketed through PAV have been on average above that which the Company would likely have otherwise received.
Alamco completed the installation of a 23 mile pipeline system and commenced sales of its Days Chapel Field volumes to a local distribution company in February 1997. This pipeline system connects most of its Kentucky and Tennessee wells and transports the gas to the utility, which is expected to result in higher sales prices than previously received by the avoidance of third-party gathering charges.
FUTURE ACTIVITIES
Alamco intends to use internally generated cash flows and amounts available under the Company's $30.0 million revolving bank credit facility to fund the exploration and development of its gas and oil reserves and property acquisitions. As of February 14, 1997, $9.3 million was available for borrowing under this credit facility.
Alamco's 1997 capital investment program will ultimately depend upon the market and prices received for natural gas, the success of its exploration and development prospects, and the ability of the Company to capitalize on acquisition opportunities that may arise during the year. The Company currently plans to spend approximately $6.0 million in 1997 to drill approximately 30 wells, recomplete an additional five wells and begin a pilot secondary recovery program for oil in the Company's Days Chapel Field in Tennessee. Approximately 16 development wells and one exploratory well will be drilled in Tennessee. Up to seven development wells and two exploratory wells will be drilled in Kentucky. The Company also plans to drill four development wells at its South Burns Chapel Field in West Virginia.
MARKETS AND CUSTOMERS
General.
Alamco 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 1996 gas and oil sales. Alamco sold 44.8 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 27.1 percent of the Company's total 1996 gas and oil sales.
West Virginia Production.
Alamco's West Virginia production in 1996 was approximately 80 percent of total Company gas sales.
PAV. In 1993, Alamco entered into a three year gas marketing agreement with PAV for all gas transported on the CNG Transmission Corporation ("CNG") pipeline system and all gas on the Columbia Gas Transmission Corporation ("Columbia") pipeline system, which primary term expired on November 1, 1996. The agreement is currently extended on a month-to-month basis. Volumes sold in 1996 through PAV on the CNG and the Columbia systems totalled approximately 2.8 BCF. The average price received from sales to PAV was $2.87 per MMBTU ($3.27 per MCF) in 1996.
Hope. Hope purchases all of the Company's production from the South Burns Chapel Field under two separate gas purchase agreements, with terms continuing through October 31, 1999. Both agreements were renegotiated effective November 1, 1995, and have price reopeners on October 31, 1998. Total volumes sold to Hope in 1996 were approximately 1.7 BCF at an average price of $2.89 per MMBtu ($2.89 per MCF). While the loss of this customer could have a material adverse effect on the Company, management believes alternative customers could be located.
Approximately 40 percent of the Company's production at South Burns Chapel is sold at a fixed price with the remaining 60 percent of the South Burns Chapel Field gas sold at prices tied to a monthly Appalachian index.
Other. Alamco sells its other West Virginia gas production to various purchasers that are not significant to the Company's revenue base.
Tennessee and Kentucky Production.
Alamco's Tennessee production in 1996 was approximately 5 percent of total Company gas sales. For nearly all of 1996, the Company sold the gas production from the Days Chapel Field to Equitable Resources Marketing Company on a month- to-month contract with market-sensitive pricing tied to Gulf Coast prices, less transportation and compression charges.
Beginning in February 1997, this gas was transported through the Company's new gathering system and sold to a local utility, Citizens Gas Utility District ("Citizens"). The contract, with a primary term through October 1997 and month- to-month thereafter, provides for pricing tied to a monthly Gulf Coast index. For discussion of the costs of Alamco's gathering line, see "Infrastructure Development" above.
Alamco's Kentucky production in 1996 was approximately 15 percent of total Company gas sales. All of Alamco's production from its Kentucky operations is sold on the spot market or under term contracts providing for fixed or market- sensitive prices, with approximately 5 percent of the Company's Kentucky production sold to one buyer under a contract with market-sensitive pricing which dedicates the gas for the life of the wells. The majority of the Kentucky volumes, approximately 85 percent, is sold to Citizens under the same gas contract as the Tennessee gas. See "Infrastructure Development."
Oil Sales.
Alamco'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 $19.38 per BBL in 1996.
Marketing Risks.
During the last several years, the gas industry has been affected by strong gas price volatility resulting from wide variances in demand due primarily to weather conditions and gas storage requirements. This volatility may continue in the future. As a result, the Company is unable to predict with certainty the future stability or direction of natural gas prices.
The availability of a ready market for Alamco'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 Alamco's results of operations.
COMPETITION
Alamco 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. Integrated and independent gas and oil companies, partnerships and drilling programs, some with financial and human resources substantially in excess of those available to the Company, compete with Alamco, actively bidding for desirable gas and oil properties. The ability of the Company to add to its reserves in the future will be dependent on its ability to exploit its current lease holdings and its ability to select and acquire suitable producing properties and prospects for future exploration and development.
Similarly, there is intense competition not only from other gas production entities, but also from other marketing firms, 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 at times caused an erosion of this premium. Colder than normal weather during the winter of 1995-1996, and in the early winter of 1996-1997 caused the price premium for Appalachian gas to reappear. However, prices have been extremely volatile for the last several months, and the price premium has again declined in early 1997.
REGULATION
General. The gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the industry is 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 gas and oil industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, Alamco 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 discharge of 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 and 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 gas and oil wastes may be classified as hazardous or semi-hazardous, which could impose substantial obligations on the Company. Alamco does not believe that its compliance with current environmental laws constitutes a material expense. The Company has retained the services of an independent environmental engineering firm to assist with compliance matters 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 Alamco'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. Alamco 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 Alamco's aggregate production expenses to date. Nevertheless, the Company is unable to predict the cost of continued 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, Alamco began operating its own salt water disposal well in 1992 to dispose of water from its own wells. In 1993, the Company formed HAWG, which is responsible for the transportation and disposal of the water. HAWG currently operates two commercial disposal wells and has permits for three additional disposal wells all of which are in West Virginia. HAWG has been expanding its marketing efforts in order to add customers to dispose of other producers' water. Revenues which Alamco received from HAWG in 1996 were, however, immaterial.
OPERATIONAL HAZARDS AND INSURANCE
Alamco'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 1996 due to environmental claims which were unreimbursed by insurance carriers were not material.
While Alamco 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 Alamco will be able to maintain adequate insurance in the future at rates it considers reasonable.
Item 2.
Item 2. Properties.
Alamco'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. Alamco's proved reserves for the years ended December 31, 1996, 1995 and 1994 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 (See Note 12 to the Company's Notes to Consolidated Financial Statements).
WELL COUNT
Alamco obtained gas and oil sales revenues from 1,133 wells as of December 31, 1996. The Company is the operator of an additional 61 wells that are currently temporarily abandoned and an additional 9 wells that are waiting on completion of pipeline construction. The majority of Alamco'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 877 of the Company's wells currently 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 in order to obtain production from the remaining formations.
A significant production horizon below 6,000 feet in Alamco'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 150 feet.
Alamco'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. The Tennessee exploratory drilling program found production in the Chattanooga Shale and the Company is still evaluating the long-term commerciality of the shale.
In Kentucky, Alamco's production is from numerous zones, including the Big Lime, Coniferous, Maxton and Knox formations. With the exception of certain wells at South Key Rock, these oil and gas reservoirs, like many other Appalachian formations, are characterized by low productive volumes with long producing lives.
The following table reflects the Company's ownership at December 31, 1996 in natural gas and oil wells.
Gross Wells Net Wells Gas Oil Total Gas Oil Total
West Virginia 980 59 1,039 827.8 55.3 883.1
Tennessee 15 67 82 14.6 63.4 78.0
Kentucky 58 24 82 54.3 22.6 76.9
Total 1,053 150 1,203 896.7 141.3 1,038.0
Note: Many of Alamco'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
Alamco's producing wells hold approximately 127,000 gross acres under lease which the Company believes includes a substantial number of promising development prospects. The prospects include continued development of the South Key Rock Prospect in Kentucky, the Carden Chattanooga Shale Prospect in Tennessee and the South Burns Chapel Field in West Virginia.
Also, at December 31, 1996, Alamco 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.
LEASE POSITION AT DECEMBER 31, 1996
Developed Acreage Undeveloped Acreage Gross Net Gross Net Acres Acres Acres Acres
West Virginia 77,067 64,383 17,489 16,262
Tennessee 6,636 6,636 56,827 56,827
Kentucky 42,837 42,837 39,753 39,753
Total 126,540 113,856 114,069 112,842
TITLE TO PROPERTIES
Substantially all of Alamco'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 its 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, Alamco'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 bank credit facility (Note 5). The Company's executive offices, approximately 25,000 square feet, were purchased in early 1996 for $561,000 using funds borrowed under the Bank One credit facility. Prior to the purchase, Alamco leased these same executive offices.
Item 3.
Item 3. Legal Proceedings.
Alamco 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 which is immaterial.
On April 18, 1996, the Company agreed with the United States Environmental Protection Agency ("EPA") to settle its outstanding administrative complaint issued by the EPA for an amount significantly less than the initial proposed penalty of nearly $124,000. The EPA issued the complaint on May 23, 1994 for alleged violations of the Clean Water Act resulting from an oil discharge at Alamco's Days Chapel Field in Claiborne County, Tennessee. The incident occurred in December 1993 when vandals severed locks securing the valves on the Alamco storage tanks and discharged approximately 174 barrels of oil into a local creek. The consent agreement and final order became effective October 27, 1996.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of Alamco's stockholders during the quarter ended December 31, 1996.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of the Company are as follows:
Name Age Position
John L. Schwager 48 President, Chief Executive Officer and Director
Executive Vice President, Chief Operating Richard R. Hoffman 46 Officer and Director
Bridget D. Furbee 37 Vice President of Administration and Legal Affairs
R. Mark Hackett 34 Vice President of Engineering
Mario L. Perri 47 Vice President of Land
Carl F. Starr 36 Vice President of Production
There were no family relationships among any of the directors and executive officers of the Company in 1996. However, the Company's Vice President of Land and Vice President of Engineering, both of whom were elected on January 1, 1997, are brothers-in-law.
John L. Schwager has been President and Chief Executive Officer of Alamco since October 1987. Mr. Schwager was elected a director in 1986.
Richard R. Hoffman became Alamco's Executive Vice President and Chief Operating Officer on December 13, 1990. Mr. Hoffman was elected a director in 1988.
Bridget D. Furbee has been Vice President, Administration and Legal Affairs of Alamco since May 1994. Ms. Furbee served as Manager, Gas Marketing and Legal Affairs from August 1992 through April 1994.
R. Mark Hackett has been Vice President of Engineering since January 1, 1997. Mr. Hackett served as Engineering Manager from March 1992 through December 1996.
Mario L. Perri has been Vice President of Land since January 1, 1997. Mr. Perri served as Land Manager from April 1982 through December 1996.
Carl F. Starr has been Vice President of Production since January 1, 1997. Mr. Starr was named Production Manager in February 1995 and since January 1989, was Superintendent of Production.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
Alamco'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 quarter in 1996 and 1995.
1996 1995 Quarter High Low High Low
First $10-1/8 $ 7-3/4 $ 6-3/8 $ 5-5/8
Second 11-5/8 9-1/4 8-3/4 6
Third 12-1/4 10-5/8 8-15/16 7-1/2
Fourth 12-1/4 10-7/8 8-1/2 7-5/8
As of February 1, 1997, there were approximately 1,261 record holders of the Company's voting Common Stock. Since its incorporation in 1981, Alamco has not declared or paid any dividends with respect to the Company's Common Stock. Alamco 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 credit agreement, the declaration and payment by Alamco 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.
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 years ended December 31, 1996, 1995 and 1994 are presented below.
RESULTS OF OPERATIONS
Year Ended December 31, 1996 vs. Year Ended December 31, 1995 - --------------------------------
Alamco reported net income of $2,671,000 for the year ended December 31, 1996, an increase of $1,392,000 or 108.8 percent, as compared to net income of $1,279,000 in 1995. Income from operations for 1996 increased $2,264,000, or 119.3 percent, to $4,162,000 as compared to $1,898,000 for 1995.
Total revenues of $23,065,000 in 1996 were $4,526,000 or 24.4 percent higher than total revenues of $18,539,000 in 1995.
Gas and oil sales totalled $21,226,000 in 1996, an $8,590,000, or 68.0 percent, increase over the same period last year. Substantially higher gas and oil prices contributed $6,100,000 and $319,000, respectively, and higher gas and oil sales volumes contributed $2,106,000 and $65,000, respectively, to the increase. Gas and oil sales volumes totalled 6,917,976 equivalent thousand cubic feet ("EMCF") and 5,889,102 EMCF for the years ending December 31, 1996 and 1995, respectively. Alamco received on average $3.05 per MCF and $19.38 per barrel ("BBL") in 1996, compared to $2.10 per MCF and $15.90 per BBL last year.
In the summers of 1996 and 1995, temporary shut-ins were caused by gas transporters for routine maintenance. The Company estimates revenues were adversely affected by $227,000 and $237,000 in 1996 and 1995, respectively, due to these reductions in volumes.
Third party service income decreased $63,000, or 6.7 percent, due principally to the reduction in the number of wells the Company operates for outside investors.
Other operating revenue increased $130,000 due to increased gas marketing revenue associated with higher sales revenues, increased transportation revenue and the recognition of deferred revenue due to a note receivable paid off in connection with the West Virginia Well Exchange in 1994 (Note 2).
Total expenses in 1996 were $18,903,000, an increase of $2,262,000, or 13.6 percent, over expenses of $16,641,000 in 1995.
Production expenses were higher by $1,076,000, or 25.1 percent, due to the increased number of wells operated as a result of drilling and acquisitions and higher employee-related costs.
Production taxes of $1,323,000 in 1996 were higher by $502,000 from $821,000 in 1995 due to increased gas and oil sales revenue.
Alamco reported exploration expense of $572,000 in 1996 resulting primarily from the abandonment of the Hoffman Prospect in Kentucky. The exploration expense reported in 1995 of $1,172,000 included write-offs of the Douglas Prospect and the unsuccessful effort to acquire the oil and gas minerals underlying the Coopers Rock State Forest in Monongalia County, West Virginia. Both 1996 and 1995 exploration expense include certain departmental expenses for the evaluation of potential exploration prospects.
Third party service expense of $457,000 in 1996 was lower by $39,000 compared to 1995 when expense was $496,000 due to a slightly lower percentage of third-party operated wells.
General and administrative expenses for 1996 were higher by $274,000, or 7.6 percent, as compared to last year due to higher employee-related costs and legal expenses.
Option plan compensation expense was $1,653,000 in 1996 and $784,000 in 1995. The increase of $869,000 was due to higher Alamco stock prices and increased options granted (Note 11).
Depreciation, depletion and amortization expense was higher by $613,000 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 1996 was $755,000, a decrease of $433,000 over the same period last year due primarily to the increased interest capitalization for drilling projects. During 1996, interest incurred by the Company totalled $1,464,000, of which $709,000 was capitalized. In 1995 interest incurred was $1,360,000 of which $172,000 was capitalized.
Non-operating income in 1996 totalled $268,000, an increase of $76,000, as compared to $192,000 for 1995, due principally to higher interest income in 1996.
Alamco's provision for income tax totalled $1,759,000 in 1996 as compared to an income tax provision of $811,000 last year due to higher taxable income. The 1995 provision is comprised of the provision resulting from the Columbia settlement revenue of $1,627,000 and a tax benefit of $816,000 resulting from the 1995 loss from operations, excluding Columbia settlement revenue (Note 4).
Year Ended December 31, 1995 vs. Year Ended December 31, 1994 - --------------------------------
Alamco reported net income of $1,279,000 for the year ended December 31, 1995, a decrease of $396,000, or 23.6 percent as compared to net income of $1,675,000 in 1994. Income from operations for 1995 increased $226,000, or 13.5 percent, to $1,898,000 as compared to $1,672,000 for 1994.
Total revenues of $18,539,000 in 1995 were $4,868,000, or 35.6 percent, higher than total revenues of $13,671,000 in 1994.
Gas and oil sales totalled $12,636,000 in 1995, a $643,000, or 5.4 percent, increase over the same period in 1994. Higher gas and oil sales volumes, resulting principally from the acquisition of producing properties and the drilling of new wells, contributed $2,398,000 and $288,000, respectively, and higher oil prices contributed $120,000 to the increase but were offset by lower gas prices of $2,164,000. Gas and oil sales volumes totalled 5,889,102 EMCF and 4,810,681 EMCF for the years ending December 31, 1995 and 1994, respectively. Alamco received on average $2.10 per MCF and $15.90 per BBL in 1995, compared to $2.50 per MCF and $14.52 per BBL in 1994.
In July 1995, Hope informed the Company of a two week shut-in of production volumes for system maintenance. In October 1994, Hope requested temporary reductions in production volumes for approximately four weeks due to oversupply of gas. The Company estimates revenues were adversely affected $237,000 and $250,000 in 1995 and 1994, respectively, due to these reductions in volumes.
Alamco reported revenues of $4,164,000 in December 1995 from the settlement of claims with Columbia Gas Transmission Corporation ("Columbia"). (Note 4).
Third party service income decreased $289,000, or 23.4 percent, due principally to the reduction in the number of wells the Company operates for outside investors. Effective March 1, 1994, Alamco 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, Alamco 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 Alamco's greater ownership interest in the wells (Note 2).
Other operating revenue increased $350,000 due primarily to the recognition of income related to the transaction in which Alamco formed a partnership with an East Coast financial institution (Note 3).
Total expenses in 1995 were $16,641,000, an increase of $4,642,000, or 38.7 percent, from expenses of $11,999,000 in 1994.
Production expenses were higher by $1,288,000, or 42.9 percent, due primarily to the acquisitions made and new wells drilled during 1995.
Production taxes of $821,000 in 1995 were higher by $70,000 than 1994 expense of $751,000 due to higher gas and oil sales revenue.
Alamco reported exploration expense of $1,172,000 in 1995 resulting from the abandonment of the Douglas Prospect and a portion of the Hoffman Prospect in Kentucky after drilling two unsuccessful exploratory wells, the unsuccessful effort to acquire the oil and gas minerals underlying the Coopers Rock State Forest in Monongalia County, West Virginia and certain departmental expenses pertaining to the evaluation of prospects. Alamco did not drill any exploratory wells in 1994, but incurred $236,000 in exploration expense for the evaluation of prospects.
Third party service expense of $496,000 in 1995 was lower by $319,000 due to the exchanged interests discussed in third party service income.
General and administrative expenses for 1995 were higher by $60,000, or 1.7 percent, as compared to 1994 due to, among other things, higher employee-related costs.
Option plan compensation expense was $784,000 in 1995 and option plan compensation benefit was $41,000 in 1994. The increase of $825,000 was due to higher Alamco stock prices and increased options granted (Note 11).
Depreciation, depletion and amortization expense was higher by $748,000 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 1995 was $1,188,000, an increase of $1,034,000 over the same period in 1994 due primarily to the increased utilization of the Company's revolving credit facility. During 1995, interest incurred by the Company totalled $1,360,000, of which $172,000 was capitalized. In 1994 interest incurred was $471,000 of which $317,000 was capitalized.
Non-operating income in 1995 totalled $192,000, an increase of $37,000, as compared to $155,000 for 1994, due principally to higher interest income in 1995.
Alamco's provision for income tax totalled $811,000 in 1995 as compared to an income tax provision of $152,000 in 1994. The 1995 provision is comprised of the provision resulting from the Columbia settlement revenue of $1,627,000 and a tax benefit of $816,000 resulting from the 1995 loss from operations, excluding Columbia settlement revenue.
LIQUIDITY AND CAPITAL RESOURCES
Working Capital. At December 31, 1996, Alamco had working capital of $3,869,000, as compared to $610,000 at December 31, 1995. Because the Bank One credit facility agreement, as amended, calls for the payment of interest only until July 1, 1998, current liabilities on the Company's December 31, 1996 balance sheet do not include any principal payments relative to the Bank One credit facility.
Cash and cash equivalents totalled $1,744,000 at December 31, 1996. Of this amount, approximately $845,000 was available for general corporate purposes and the balance was held for third parties (Note 7). Operating activities provided a net $5,768,000 while investing activities used a net $13,996,000. Financing activities provided a net $6,675,000.
Revolving Credit Facility. Currently, Alamco has in place a $30 million revolving credit facility with Bank One (Note 5). As of February 7, 1997, $9.3 million was available for borrowing under the credit facility. The Company is required to pay interest only until July 1, 1998, at which time all principal and accrued interest are due and payable. Interest accrues and is paid monthly at a rate of Bank One's prime rate plus one-fourth of one percent.
Alamco is not prohibited from paying dividends to its stockholders under the Bank One credit agreement; however, certain other financial covenants, such as debt coverage and equity 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. Alamco's 1996 capital investments totalled $14,292,000, including $12,271,000 for the construction of the pipeline 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 exploration and development of its gas and oil reserves and property acquisitions. (See Part I, Item 1. "Business".)
Alamco's 1997 capital investment program will ultimately depend upon the market and prices received for natural gas, the success of its exploration and development prospects, and the ability of the Company to capitalize on acquisition opportunities that may arise during the year. The Company currently plans to spend approximately $6.0 million in 1997 to drill approximately 30 wells, recomplete an additional five wells and begin a pilot secondary recovery program for oil in the Company's Days Chapel Field in Tennessee. Approximately 16 development wells and one exploratory well will be drilled in Tennessee. Up to seven development wells and two exploratory wells will be drilled in Kentucky. The Company also plans to drill four development wells at its South Burns Chapel Field in West Virginia. The Company plans to continue with its aggressive acreage acquisition strategy and will position itself to increase both exploratory and development drilling. Alamco remains committed to the acquisition of producing properties at favorable prices.
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 Alamco 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.
In early November 1995, Alamco acquired from an industry partner for $1.35 million in cash, interests in 47 gross (30.7 net) oil and gas wells and the remaining 53 percent of the gas gathering system that it did not own in the Company's Days Chapel Field in Tennessee. This transaction increased the Company's ownership of the wells in the field from 48.4 percent to 83.0 percent. Alamco used funds available on its credit facility with Bank One to complete the transaction.
Alamco also acquired in November 1995 for $1.22 million, four partnerships' share of the Company's claim against Columbia (see Columbia Litigation Claim below). The Company used funds available on its credit facility with Bank One to complete the transaction.
Columbia Litigation Claim. In November 1995, Alamco received $7.6 million on its and other interest owners' behalf from Columbia under Columbia's Second Amended Plan of Reorganization, As Further Amended Dated July 17, 1995 (the "Plan"). This amount represents 68.875 percent of the combined $11 million claim against Columbia arising from the settlement of various gas purchase claims. The Plan provides for a potential additional distribution of up to 3.625 percent of the allowed claim in the future depending upon various contingencies. Alamco's share of the claim was approximately 74 percent (Note 4).
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 1996 and 1995. Alamco's results of operations are generally 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, Alamco believes that its results of operation should be viewed on an annual basis.
(in thousands, except per share data)
First Second Third Fourth 1996 Quarter Quarter Quarter Quarter ---- ------- ------- ------- -------
Sales and other operating revenues $6,624 $5,137 $4,745 $6,559 Gross profit 3,649 2,159 1,635 3,025 Net income (loss) (3) 1,298 (16) 281 1,108 Net income (loss) per share $0.27 $0.00 $0.06 $0.22
First Second Third Fourth 1995 Quarter Quarter Quarter Quarter ---- ------- ------- ------- -------
Sales and other operating revenues (2) $3,460 $3,530 $3,149 $8,400 Gross profit (2) 1,030 1,020 529 4,915 Net income (loss) (1)(2) (81) (412) (416) 2,188 Net income (loss) per share (1)(2) ($0.02) ($0.09) ($0.09) $0.47 - ----------------------
(1) Restated for the stock option plan compensation adjustments (Note 11).
(2) In the fourth quarter of 1995, Alamco recorded as revenue the proceeds from the Columbia Settlement of $4,164,000. The tax effect of this one- time event of $1,627,000 is included in the fourth quarter 1995 tax provision of $1,364,000. Absent the Columbia Settlement, revenues in the fourth quarter would have been $4,236,000 with a gross profit of $583,000, a net loss of $313,000, and a net loss per share of $.07.
(3) In the fourth quarter of 1996 Alamco's tax provision reflects a valuation allowance of $500,000 applicable to investment tax carryforwards, due to increasing uncertainty of the Company's ability to use all of the credits prior to their expiration.
Item 8.
Item 8. Consolidated Financial Statements. - ------- ----------------------------------
Index to Consolidated Financial Statements ------------------------------------------
Report of Independent Accountants
Consolidated Statement of Income, for the Years Ended December 31, 1996, 1995 and 1994
Consolidated Balance Sheet, as of December 31, 1996 and 1995
Consolidated Statement of Changes in Stockholders' Equity, for the Years Ended December 31, 1996, 1995 and 1994
Consolidated Statement of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT ACCOUNTANTS
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, 1996 and 1995, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
600 Grant Street Pittsburgh, Pennsylvania February 21, 1997
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Years Ended December 31, 1996, 1995 and 1994 (In thousands, except share data) ==============================================================================
1996 1995 1994 ---- ---- ---- Revenues: Gas and oil sales $21,226 $12,636 $11,993 Agreements with gas purchasers 33 4,164 -- Third party services 880 943 1,232 Other revenue 926 796 446 ------- ------- ------- Total revenues 23,065 18,539 13,671 ------- ------- -------
Expenses: Production expense 5,361 4,285 2,997 Production taxes 1,323 821 751 Exploration 572 1,172 236 Third party services 457 496 815 General and administrative 3,898 3,624 3,564 Option plan compensation 1,653 784 (41) Depreciation, depletion, and amortization 4,884 4,271 3,523 Interest 755 1,188 154 ------- ------- -------
Total expenses 18,903 16,641 11,999 ------- ------- -------
Income from operations 4,162 1,898 1,672
Other nonoperating income, net 268 192 155 ------- ------- -------
Income before income tax 4,430 2,090 1,827
Income tax provision 1,759 811 152 ------- ------- -------
Net income $ 2,671 $ 1,279 $ 1,675 ======= ======= =======
Net income per share $0.54 $0.27 $0.36 ===== ===== =====
Weighted average number of shares outstanding 4,920,131 4,679,703 4,645,154 ========= ========= =========
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1996 and 1995 (In thousands) ==============================================================================
ASSETS 1996 1995 ------ ---- ----
Current assets: Cash and cash equivalents $ 1,744 $ 3,297 Accounts receivable 6,253 3,116 Due from partnerships and programs 90 72 Inventories and other current assets 375 368 Deferred taxes 207 138 ------- -------
Total current assets 8,669 6,991 ------- -------
Property and equipment: Gas and oil producing properties (Successful Efforts Method) 87,991 78,076 Other property and equipment 8,621 5,740 ------- -------
96,612 83,816 Less accumulated depreciation, depletion and amortization 35,581 32,201 ------- -------
61,031 51,615
Other assets 998 1,294 ------- -------
Total assets $70,698 $59,900 ======= =======
(Continued)
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1996 and 1995 (In thousands, except share data) ==============================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY 1996 1995 ------------------------------------ ---- ----
Current liabilities: Current portion of long-term debt and capital lease obligations $ 34 $ 33 Accounts payable 853 1,026 Cash compensation under stock option plan 529 355 Accrued expenses and other 1,002 962 Accrued production and property taxes 636 583 Due working interest and royalty owners 1,746 3,309 Deferred revenue -- 113 ------- -------
Total current liabilities 4,800 6,381 ------- -------
Long-term debt and capital lease obligations, less current portion 20,752 13,674 Due working interest and royalty owners 322 325 Deferred revenue -- 29 Deferred taxes 10,330 8,566 Other long-term liabilities 508 429 ------- -------
Total liabilities 36,712 29,404 ------- ------- 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; 15,000,000 shares authorized; 4,846,697 and 4,762,898 shares issued and outstanding, respectively, including treasury stock 481 476 Additional paid-in capital 32,074 31,245 Common stock issuable under options 1,415 948 Retained earnings (deficit) 722 (1,949) ------- ------- 34,692 30,720
Less treasury stock, 94,589 and 62,405 shares of common stock, respectively 706 224 ------- -------
Total stockholders' equity 33,986 30,496 ------- -------
Total liabilities and stockholders' equity $70,698 $59,900 ======= =======
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, 1996, 1995 and 1994 (In thousands, except share data) ============================================================================== Common Common Addi- Stock Treasury Stock tional Retained Issuable Stock ---------------- Paid-in Earnings Under ----------- Shares Dollars Capital (Deficit) Options Shares Dollars ------ ------- ------- ------- ------- ------ ------- Balance January 1, 1994 4,703,677 $470 $30,954 ($4,903) $ 521 72,792 $215
Issuance of treasury stock -- -- 36 -- -- (10,370) (34)
Issuance of common stock 4,903 -- 32 -- -- -- --
Acquisition of treasury stock -- -- -- -- -- 938 7
Exercise of stock options 4,133 1 10 -- -- -- --
Public stock offering- additional costs -- -- (20) -- -- -- --
Stock option compensation -- -- (17) -- (14) -- --
Net income -- -- -- 1,675 -- -- -- --------- ----- ------ ------ ------ ------- ----- Balance December 31, 1994 4,712,713 471 30,995 (3,228) 507 63,360 188
Issuance of treasury stock -- -- 36 -- -- (10,370) (34)
Acquisition of treasury stock -- -- -- -- -- 9,415 70
Issuance of common stock 4,585 -- 35 -- -- -- --
Exercise of stock options 45,600 5 133 -- -- -- --
Stock option compensation -- -- 46 -- 441 -- --
Net income -- -- -- 1,279 -- -- -- --------- ----- ------ ------ ------ ------- ----- Balance December 31, 1995 4,762,898 476 31,245 (1,949) 948 62,405 224
Issuance of treasury stock -- -- 77 -- -- (12,929) (34)
Acquisition of treasury stock -- -- -- -- -- 45,113 516
Issuance of common stock 2,541 -- 29 -- -- -- --
Exercise of stock options 81,258 5 66 -- -- -- --
Stock option compensation -- -- 657 -- 467 -- --
Net income -- -- -- 2,671 -- -- -- --------- ----- ------ ------ ------ ------- ----- Balance December 31, 1996 4,846,697 $481 $32,074 $722 $1,415 94,589 $706 ========= ===== ======= ===== ====== ======= ===
Accompanying notes are an integral part of the consolidated financial statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1996, 1995 and 1994 (In thousands) =============================================================================
1996 1995 1994 ---- ---- ----
Net income $2,671 $1,279 $1,675 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 4,884 4,271 3,523 Deferred taxes 1,695 689 219 Provision for common stock issuable under options 1,124 487 (31) Dry hole costs 108 641 -- Gain on asset sales (115) (31) (76) Issuance of stock for employee benefits and compensation expense 140 105 102 Other factors, net 5 7 1 Increase (decrease) in cash from changes in: Accounts receivable (3,137) (423) 1,282 Due from partnerships and programs (18) 68 18 Due working interest and royalty owners (1,563) 2,245 (1,674) Inventories and other current assets (7) 60 (167) Accounts payable and accrued expenses (80) (152) 897 Cash compensation under stock option plan 174 165 (5) Deferred revenue (113) (1,052) 474 ------ ------ ------
Net cash provided by operating activities 5,768 8,359 6,238 ------ ------ ------
Cash flows from investing activities: Proceeds from disposal of fixed assets 156 156 278 Payment for the acquisition of producing properties -- (1,384) (6,234) Capital expenditures (14,292) (6,547) (10,500) Investment in limited partnership -- (5) (290) Other assets 140 155 (464) ------ ------ ------
Net cash used in investing activities (13,996) (7,625) (17,210)
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1996, 1995 and 1994 (In thousands) =============================================================================
1996 1995 1994 ---- ---- ----
Cash flows from financing activities:
Borrowings under line of credit agreement $8,100 $6,800 $13,300 Payments on line of credit (1,000) (6,000) (1,000) Additions to long-term debt 13 -- -- Principal payments on long-term debt and capital lease obligations (40) (95) (320) Acquisition of treasury stock (516) (70) (7) Additional costs from public offering of common stock -- -- (20) Proceeds from exercise of stock options 71 138 11 Other liabilities 47 (842) (825) ------ ------ ------
Net cash provided by (used in) financing activities 6,675 (69) 11,139 ------ ------ ------ Net (decrease) increase in cash and cash equivalents (1,553) 665 167 Cash and cash equivalents - beginning of period 3,297 2,632 2,465 ------ ------ ------
Cash and cash equivalents - end of period $1,744 $3,297 $2,632 ====== ====== ======
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest $717 $1,323 $148 Income taxes $250 $232 $55
Supplemental schedule of non-cash investment and financing activities:
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, Alamco-Delaware, Inc. ("Aladel") and HAWG HAULING & DISPOSAL, INC. ("HAWG"). Aladel and HAWG are wholly owned subsidiaries of the Company. All significant intercompany balances have been eliminated in consolidation.
Nature of Operations. Alamco, Inc. is an Appalachian-based independent gas and oil producer actively engaged in the acquisition, exploitation, exploration, development and production of domestic gas and oil. The Company's activities are conducted in West Virginia, Tennessee and Kentucky, with an emphasis on producing natural gas for ultimate sale to customers in the northeast gas markets.
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. Cash and cash equivalents are held on deposit with various financial institutions. No collateral or other security is provided on these deposits, other than $100,000 of deposit insurance provided by the Federal Deposit Insurance Corporation.
Fair Value of Financial Instruments. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. 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 certain quantities of gas and oil for varying periods.
Use of Estimates. Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
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. 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 $709,000 in 1996, $172,000 in 1995, and $317,000 in 1994. Interest incurred was $1,464,000 in 1996, $1,360,000 in 1995 and $471,000 in 1994.
In 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS No. 121"). This statement, which is effective for financial statements for years beginning after December 15, 1995, was adopted by the Company in 1995. The Company has evaluated the impact of SFAS 121 by comparing the carrying value of its long- lived assets, consisting of gas and oil producing properties, other property and equipment, and intangibles, to the estimated future cash flow from such assets in order to determine whether the carrying value of such properties should be reduced. No adjustments to carrying values of assets were necessary as of December 31, 1996 or 1995.
Other Property and Equipment. Other property and equipment are stated at cost. 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, 1996 the Company's estimate of equipment salvage value 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. 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 and consists of the following:
December 31, --------------------------- 1996 1995 ---- ----
Covenant not to compete $312,000 $312,000 Consulting agreement 390,000 390,000 Less accumulated amortization (390,000) (234,000) -------- -------- $312,000 $468,000 ======== ========
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. 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. Deferred tax expense (credit) is the result of changes in deferred tax assets and liabilities.
Stock-Based Compensation. Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," encourages, but does not require companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to continue to account for stock- based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. Accordingly, compensation cost for fixed stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock. Compensation cost for variable options is measured at the exercise date and is adjusted based on the quoted market price of the Company's stock at the end of the reporting period. Refer to Note 11.
Income Per Share. Primary earnings per share is based on the weighted average number of common and common equivalent shares outstanding. Common equivalent shares are included in the calculation beginning in 1996. They were not significant in previous years. Primary and fully diluted earnings per share are the same.
Reclassifications. Certain amounts have been reclassified in the 1995 and 1994 consolidated financial statements to conform with the 1996 presentation. These amounts have been reclassified to reflect the change in the Company's focus from a drilling fund operator to a company which drills and operates wells primarily for its own account.
2 - PROPERTY ACQUISITIONS AND WELL SWAP
In early November 1995, the Company acquired from an industry partner, for $1.35 million in cash, interests in 47 gross (30.7 net) oil and gas wells and the remaining 53 percent of the gas gathering system that it did not own in the Company's Days Chapel Field in Tennessee. This transaction increased the Company's ownership of the wells in the field from 48.4 percent to 83.0 percent. The Company used funds available under its credit facility with Bank One to complete the transaction.
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 in 1994, 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 was deferred and was recognized as principal payments were 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 interests 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 1994, the following summary, prepared on a pro forma basis, presents the consolidated results of operations as if the two transactions had been consummated as of January 1, 1994.
(Unaudited and in thousands of dollars, except per share amount) ------------------------
Revenues $14,340 Expenses 12,410 Income from operations 1,930 Net income 1,843 Net income per share $0.40
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 $1.04 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 order to receive benefit from these credits which would otherwise expire unused, 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, has allowed it to realize a cash benefit of $0.65 for each $1.00 in available Section 29 tax credits generated by the producing properties.
The Company recognizes income from this transaction as the required gas production levels are achieved. The Company recognized income of $608,000 in 1996, $645,000 in 1995 and $249,000 in 1994 relative to this transaction.
4 - SETTLEMENT OF COLUMBIA LITIGATION CLAIMS
The Company received in November 1995 the proceeds from the settlement of its contract rejection claims from Columbia. The initial distribution was the result of the confirmation by the U.S. Bankruptcy Court of Columbia's Plan of Reorganization on November 15, 1995. The Company received proceeds of $7.6 million, of which its share was $5.6 million. The Company recognized revenue of $4,164,000 in the fourth quarter of 1995, net of claims purchased from other owners, and after tax income of $2,537,000 ($0.54 per share).
The Company could receive an additional settlement distribution from Columbia of up to 3.625 percent of its original claim of $11,000,000 with the Company's share of revenue being $295,000 and after tax income of $180,000 ($0.04 per share). The timing and amount of this additional recovery is contingent upon Columbia settling various outstanding claims with other gas producers.
5 - LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
The Company has a $30.0 million revolving credit facility with Bank One which calls for the payment of interest only until July 1, 1998, 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 one-fourth of one percent. As of December 31, 1996, the aggregate amount of borrowing under the Bank One revolving credit facility was $20.7 million. Bank One's prime interest rate on December 31, 1996, was 8.25 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 1996, the borrowing base is sufficient to allow full utilization of the maximum $30.0 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.
The aggregate maturities of long-term debt and capital lease obligations for each of the next five years and thereafter are as follows (in thousands):
1997 $ 34 1998 20,735 1999 17 2000 0 2001 and thereafter 0 -------
$20,786 =======
6 - CASH AND CASH EQUIVALENTS
Cash and cash equivalents totalled $1,744,000 at December 31, 1996. Of this amount, approximately $845,000 was available for general corporate purposes and the balance was held for third parties, including $637,000 in gas and oil sales proceeds held for eventual distribution to outside working interests and royalty owners, $135,000 representing the outside interests' estimated share of Columbia settlement proceeds, and $128,000 withheld from outside working interests' proceed distributions to be utilized for future ad valorem tax payments (Note 7). The Company's cash balance at December 31, 1996 includes $1,396,000 invested in commercial paper, U.S. Government and Agency Securities and Bankers' Acceptances, with an annualized 5.04 percent return.
7 - 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 $450,000 at December 31, 1996, 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 $322,000 for future plugging and abandonments. Corresponding amounts recorded in assets are included in liabilities.
8 - INCOME TAXES
The following table details the components of the Company's income tax expense for the year 1994 through 1996.
1996 1995 1994 ---- ---- ---- (In thousands)
Federal: Current $ 64 $107 ($67) Deferred 1,546 592 433 ------ ---- ----
Total Federal 1,610 699 366 ------ ---- ----
State: Current -- 15 -- Deferred 149 97 (214) ------ ---- ----
Total State 149 112 (214) ------ ---- ----
Total $1,759 $811 $152 ====== ==== ====
Reconciliations of the income tax provision 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, -------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Tax provision computed at statutory rate $1,506 $676 $610
State taxes 222 139 104
Change in effective state tax rate -- -- (255)
Sale of partnership interest 48 249 --
Use of percentage depletion (558) (1,029) (321)
Valuation allowance 500 750 --
Other 41 26 14 ------ ------ ----
Provision for income taxes $1,759 $811 $152 ====== ====== ====
The 1994 change in effective state tax rate reflected a change in the Company's business activities in states with lower tax rates.
The deferred tax assets of $207,000, $138,000 and $74,000 for 1996, 1995 and 1994, respectively, relate to accrued cash compensation resulting from stock options (Note 11).
The components of the net deferred tax liability are as follows:
December 31, -------------------------- 1996 1995 1994 ---- ---- ----
(In thousands)
Depreciation, depletion and amortization $14,605 $12,400 $12,293 Option plan compensation (552) (370) (198) Accounts receivable write-off (30) (30) (30) Future litigation payments (34) (39) (72) Sale of partnership interest (293) (374) (293) Net operating loss carryforwards (2,303) (1,553) (1,704) AMT credits (907) (821) (746) ITC carryforwards (1,353) (1,375) (1,394) Other (53) (22) (43) Valuation allowance 1,250 750 -- ------- ------ ------
Net deferred tax liability $10,330 $8,566 $7,813 ======= ====== ======
The Company's investment tax credit carryforwards expire between the years 1997 and 2000. The Company has recorded a valuation allowance applicable to these credits because the ability to use all of them is uncertain.
Statement of Financial Accounting Standards 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.
9 - SALES CONCENTRATION
The following table illustrates the Company's gas and oil sales concentration with purchasers greater than 10 percent:
Purchasers 1996 1995 1994 ---------- ---- ---- ----
PAV 44.8% 44.2% 53.8% Hope 27.1% 28.9% 28.2%
Phoenix-Alamco Ventures, a Limited Liability Company ("PAV"), which is owned jointly by the Company and Phoenix Energy Sales Company, is engaged in the marketing of Alamco's and other working interest owners' gas. PAV achieves diversification for Alamco's gas sales by executing contracts with numerous other marketing entities, local distribution companies and industrial users with contracts of various durations.
10 - 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.
11 - STOCK OPTIONS AND BENEFIT PLANS
Stock Option Plans. Stock options have been granted to Company employees and outside directors under the 1992 Employees' Stock Option Plan, the 1982 Employees' Stock Option Plan, the 1982 Outside Directors' Stock Option Plan, the 1996 Stock Option Plan for Non-Employee Directors and non-qualified stock options granted outside of any stockholder approved plans.
Stock options have been and may be granted at not less than market prices on the dates of grant. Vesting occurs over various periods. An option may not be exercised within one year from date of grant and no option will be exercisable after ten years from the date granted. The 1992 and 1982 Employee Plans provide for the grant of either non-qualified stock options or incentive stock options.
As a result of exercises of non-qualified stock options in 1996, Alamco reviewed its accounting for stock options and concluded that certain options should have been treated as variable awards rather than fixed awards. An employee tax reimbursement feature included in the option agreements requires that variable award accounting be followed. Under variable award accounting, periodic changes in the differences between the market price of the Company's Common Stock and the exercise prices of outstanding non-qualified stock options should be recognized as non-cash compensation expense. The variable award accounting has been reflected retroactively in the accompanying financial statements as a correction of an error and the 1994 and 1995 financial statements have been restated. The Company's Board of Directors has established that no further options will be granted that are subject to variable award accounting.
The Company has adopted the disclosure-only provision of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation". Accordingly, only compensation cost for non-qualified options granted under variable option plans has been recognized. Had compensation cost for the Company's stock options been determined based on the fair value at the grant date for awards in 1996 and 1995 consistent with the provisions of SFAS No. 123, the Company's net earnings (in thousands) and earnings per share would have been as follows:
1996 1995 ---- ----
Net earnings - as reported $2,671 $1,279
Net earnings - pro forma $2,680 $1,276
Earnings per share - as reported $0.54 $0.27
Earnings per share - pro forma $0.55 $0.27
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1996 and 1995: dividend yield of 0%; expected volatility of 28%; average risk-free interest rate of 6.38% in 1996 and 7.5% in 1995; and average expected terms of 5.5 years.
The transactions for shares under options were:
1996 1995 1994 ---- ---- ---- Outstanding, beginning of year: Number 437,900 452,500 465,033
Weighted average exercise price $5.62 $5.19 $4.95
Granted: Number 138,000 35,000 18,500
Weighted average exercise price $11.41 $8.00 $6.75
Exercised: Number 130,226 45,600 4,133
Weighted average exercise price $4.90 $3.00 $2.73
Expired or forfeited: Number -0- 4,000 26,900
Weighted average exercise price -0- $6.75 $2.61
Outstanding, end of year: Number 445,674 437,900 452,500
Weighted average exercise price $7.63 $5.62 $5.19
Exercisable, end of year: Number 278,178 313,904 260,003
Weighted average exercise price $5.74 $5.04 $4.24
Shares reserved for future options, end of year 216,500 154,500 35,500
Weighted average fair value of options granted using the Black-Scholes option-pricing model $4.49 $3.34 --
The following tables summarize certain stock option information at December 31, 1996:
Options outstanding: Weighted Weighted average average Range of Number remaining exercise Exercise prices Outstanding term price - --------------- ----------- ----- -----
$1.88 - $3.15 66,774 4.25 $2.92 3.38 800 4.85 3.38 3.75 800 2.85 3.75 3.88 800 3.85 3.88 4.88 17,500 5.85 4.88 6.75 186,000 6.96 6.75 8.00 35,000 8.86 8.00 11.13 30,000 9.72 11.13 11.25 40,000 9.85 11.25 11.63 68,000 9.50 11.63 ------- ---- -----
Total 445,674 7.47 $7.63 ======= ==== =====
Options exercisable: Weighted average Range of Number exercise Exercise prices Exercisable price -------------- ----------- -----
$1.88 - $3.15 66,774 $2.92 3.38 800 3.38 3.75 800 3.75 3.88 800 3.88 4.88 17,500 4.88 6.75 179,835 6.75 8.00 11,669 8.00 ------- -----
Total 278,178 $5.74 ======= =====
The 1992 Equity Compensation Plan for Outside Directors. The 1992 Equity Compensation Plan for Outside Directors 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 stock 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. In 1996, 2,541 shares were issued to Directors at a market price of $11.63 per share leaving 51,448 shares available for issuance at December 31, 1996.
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 $129,000, $117,000 and $110,000 in value in 1996, 1995 and 1994, respectively.
12 - 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, --------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Costs (capitalized or expensed) for:
Property acquisition $ 778 $1,281 $ 6,740 Exploration 572 1,172 236 Development 9,920 5,476 9,578 ------- ------ ------- $11,270 $7,929 $16,554 ======= ====== =======
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:
1996 1995 ---------------------- ----------------------- Accumu- Accumu- lated lated Cost DD&A Net Cost DD&A Net ---- ---- --- ---- ---- --- (In thousands)
Proved developed properties $87,991 $32,879 $55,112 $78,076 $28,996 $49,080
Pipelines and processing equipment 4,249 802 3,447 1,924 671 1,253
Vehicles, machinery and equipment consisting principally of assets used in gas and oil producing activities 2,496 1,271 1,225 2,068 1,380 688
Buildings used in gas and oil producing activities 121 11 110 224 99 125 ------- ------- ------- ------- ------- -------
$94,857 $34,963 $59,894 $82,292 $31,146 $51,146 ======= ======= ======= ======= ======= =======
The results of operations for gas and oil producing activities are presented below:
Year Ended December 31, --------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Gas and oil sales revenues $21,226 $12,636 $11,993 ------- ------- ------- Expenses: Production (a) 6,684 5,106 3,748 Depreciation, depletion and amortization 3,764 3,596 2,790 Exploration 572 1,172 236 ------- ------- ------- 11,020 9,874 6,774 ------- ------- ------- Results of operations for gas and oil producing activities before provision for income taxes 10,206 2,762 5,219
Provision for income tax 1,531 414 783 ------- ------- ------- Results of operations for gas and oil producing activities $8,675 $2,348 $4,436 ======= ======= =======
(a) Amounts for 1995 and 1994 have been restated (Note 1).
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 operation for gas and oil producing activities between 1996 and 1995 resulted from higher gas prices and increased production from the Company's successful acquisition and drilling programs.
The decrease in the results of operations for gas and oil producing activities between 1995 and 1994 resulted from lower gas and oil sales revenues due primarily to lower gas prices partially offset by the Company's successful acquisition and drilling programs.
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, -------------------------------------------------- 1996 1995 1994 ------------ ----------- ----------- MCF BBL MCF BBL MCF BBL --- --- --- --- --- --- (In thousands)
Proved reserves, beginning of year 127,293 1,636 119,625 1,399 82,617 897 Extensions, discoveries and other additions 19,263 185 11,534 2 13,529 435 Acquisitions -- -- 3,242 376 16,888 131 Sales of reserves in place (297) -- -- -- -- -- Change in participation by area of mutual interest partner (4,504) -- -- -- -- -- Revisions of previous estimates 408 265 (1,744) (53) 10,995 4 Production (6,368) (92) (5,364) (88) (4,404) (68) ------- ----- ------- ----- ------- ----- Proved reserves, end of year 135,795 1,994 127,293 1,636 119,625 1,399 ------- ----- ------- ----- ------- -----
Proved developed reserves 114,462 1,573 97,169 1,405 85,654 1,164 ------- ----- ------- ----- ------- -----
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 1996 and 1995 due to substantially higher gas and oil prices and the success of the Company's acquisition and development drilling programs. 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
1997 $ 19,774 $ (982) $ 18,792 1998 18,729 (481) 18,248 1999 18,208 1,596 19,804 2000 17,092 2,762 19,854 2001 and thereafter 240,823 58,563 299,386 -------- ------- --------
Total $314,626 $61,458 $376,084 ======== ======= ========
Present value of future cash flow $133,024 $18,056 $151,080
Estimated future net cash flow represents future cash inflows generated by the sale of the proved reserves at year-end prices 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 average gas price used is $3.48 per MCF and the average oil price used is $22.11 per barrel. Production costs are based on those in effect at December 31, 1996. 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.
Year Ended December 31, --------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Future cash inflows $555,224 $344,066 $275,745 Future production and development costs (179,140) (137,973) (108,241) Future income tax expense (99,552) (52,524) (42,915) -------- -------- --------
Future net cash flows 276,532 153,569 124,589
10% annual discount for estimated timing of cash flows (165,846) (90,378) (77,184) -------- -------- -------- Standardized measure of discounted future net cash flows $110,686 $ 63,191 $ 47,405 ======== ======== ========
Approximately 92 percent of the Company's reserves are natural gas reserves, the price for which has been very volatile since year-end 1996. The following table summarizes the principal sources of change in the standardized measure of discounted future cash flows:
Year Ended December 31, --------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Sales and transfers of gas and oil produced, net of production costs ($14,542) ($8,442) ($8,706) Net changes in prices, production and development costs, and quality estimates 175,862 41,458 26,825 Addition of proved undeveloped reserves 22,459 11,049 16,039 Sales of reserves in place (21) -- -- Change in participation by area of mutual interest partner (3,847) -- -- Development costs incurred during the period (9,920) (5,476) (9,578) Accretion of discount 9,038 7,718 6,540 Net change in income taxes (47,028) (9,609) (9,041) Other, including changes in the discount other than due to accretion (84,506) (20,912) (18,329) ------- ------- ------- $47,495 $15,786 $ 3,750 ======= ======= =======
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 1996 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 1996 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 1996 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 1996 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, 1996, 1995 and 1994 Consolidated Balance Sheet as of December 31, 1996 and 1995 Consolidated Statement of Changes in Stockholders' Equity for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statement of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements
(b) The following report on Form 8-K was filed during the quarter ended December 31, 1996.
(1) Form 8-K dated December 20, 1996, pursuant to which the Company reported in Item 5 of Form 8-K that it had restated results of operations for the nine months ended September 30, 1996 and the four years ended December 1992, 1993, 1994 and 1995 to reflect non-cash adjustments in the Company's accounting for nonqualified stock options as a result of the employee tax reimbursement feature included in the option arrangements.
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: February 27, 1997
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 February 27, 1997 -------------------------- John L. Schwager President, Chief Executive Officer, Principal Executive Officer, Principal Financial Officer and Director
February 27, 1997 /s/ Robert S. Maust -------------------------- Robert S. Maust Director
February 27, 1997 /s/ Richard R. Hoffman -------------------------- Richard R. Hoffman Executive Vice President, Chief Operating Officer and Director
February 27, 1997 /s/ Stephen L. Barr -------------------------- Stephen L. Barr Director
February 27, 1997 /s/ James H. Weber -------------------------- James H. Weber Director
/s/ Thomas M. Levine February 27, 1997 -------------------------- Thomas M. Levine Director
INDEX TO EXHIBITS
The following exhibits to this report are filed herewith or, if marked with an asterisk (*), are incorporated herein by reference: