SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
--------------------------
FORM 10-K
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994 OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
FOR THE TRANSACTION PERIOD FROM TO
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Commission File Number: 1-8490
ALAMCO, INC.
(Exact name of registrant as specified in its charter)
Delaware 55-0615701
(State or other jurisdiction (IRS Employer Identification No.)
of incorporation or organization)
200 West Main Street, Clarksburg, WV 26301
(Address of principal executive (Zip Code)
offices)
Registrant's telephone number, including area code (304) 623-6671
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock - Par Value $.10 per share American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ( X )
The aggregate market value of the voting stock held by non-affiliates of
the registrant, based on the closing sale price of such stock on the American
Stock Exchange as of March 1, 1995, is set forth below:
Aggregate Market Value of the
Registrant's Voting Stock Held By
Class of Stock Non-Affiliates
--------------------------------- ---------------------------------
Common Stock, $.10 par value $27,587,919
The number of shares outstanding of each of the registrant's Common Stock
as of March 1, 1995 is 4,660,064 shares.
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Page 1 of 64
Index to Exhibits begins on page 58
DOCUMENTS INCORPORATED BY REFERENCE
Registrant's definitive Proxy Statement in connection with its 1995 Annual
Meeting of Stockholders, which is to be filed not later than 120 days after
Registrant's fiscal year-end, is incorporated by reference in Part III of this
Report, except those portions of the Proxy Statement specifically not
incorporated by reference. The report of the Compensation Committee of the
Registrant's Board of Directors and the Registrant's Performance Graph to be
included within the definitive Proxy Statement shall not be deemed to be
"soliciting material" or to be "filed" with the Securities and Exchange
Commission or otherwise incorporated by reference in this Report.
PART I
Item 1. Business.
Alamco, Inc. (the "Company" or "Alamco") is an Appalachian-based
independent gas and oil producer actively engaged in the acquisition,
exploitation, development and production of domestic gas and oil. The Company's
activities are conducted in West Virginia, Tennessee and Kentucky, with emphasis
on producing natural gas for ultimate sale to customers in the Northeast gas
markets. Independent petroleum engineers estimate that the Company's proved
reserves totalled 128.0 equivalent billion cubic feet ("EBCF") as of
December 31, 1994, using a conversion of six thousand cubic feet of gas to one
barrel of oil. As of December 31, 1994, the Company had an average ownership
interest of 82 percent in 1,162 gross wells and operates 97 percent of the wells
in which it has an ownership interest.
Alamco, a Delaware corporation, was organized in 1981 as the successor of
a privately held entity, Allegheny Land And Mineral Company ("Allegheny"), which
had been engaged in the gas and oil business since 1956, and to certain
interests in various gas and oil programs sponsored and/or operated by
Allegheny. The Company's executive offices are located at 200 West Main Street,
Clarksburg, West Virginia 26301, and its telephone number is (304) 623-6671.
The Company currently employs approximately 94 persons on a full time basis.
The Company's Common Stock is listed on the American Stock Exchange ("AMEX")
under the trading symbol "AXO".
BUSINESS STRATEGY
The Company's business strategy is to economically increase its reserves
and its production and sale of gas and oil from existing and acquired properties
in the Appalachian Basin in order to maximize stockholders' return over the long
term. To accomplish this strategy, the Company will continue to focus on
increasing its gas and oil reserves through development and exploratory
drilling, property acquisitions, well recompletion and exploitation programs,
including remedial well enhancements. Using this strategy, the Company's
reserves have increased in each of the past four years. Estimated reserves of
128.0 EBCF at December 31, 1994, compares favorably to estimated reserves of
88.0 EBCF, 64.1 EBCF and 49.6 EBCF as of December 31, 1993, 1992 and 1991,
respectively.
The Company intends to continue to focus its activities in the Appalachian
Basin, which is geographically one of the largest and oldest gas and oil
producing regions in the United States. The Company and other operators in the
Appalachian Basin have historically experienced high drilling success rates in
the formations of the Basin, with wells generally producing for more than 25
years, although at low production volumes. The Company may expand its area of
operations into other producing basins if management believes such an expansion
is beneficial to the Company.
The Company develops reserves by drilling wells and recompleting
previously drilled wells to prove the existence of gas and oil reservoirs.
Drilling activities are currently carried out in West Virginia, Tennessee and
Kentucky. In certain situations, an alternative to drilling new wells is the
recompletion of existing wells. Recompletions may prove the existence of
additional quantities of natural gas and oil in formations which have not yet
been opened to production in existing wells. Recompletion projects are
attractive because they generally provide access to reserves at a cost which is
substantially lower than the cost of drilling a new well. The Company's
recompletion efforts are centered on its West Virginia properties.
The Company also intends to acquire additional producing properties to
increase its gas and oil reserves. The Company actively pursues the acquisition
of producing properties that will enhance the Company's revenue base without
proportional increases in overhead costs. The Company has directed its
attention to Appalachian Basin properties in which it will have a significant
ownership interest and will serve as operator. In addition to the acquisition
of properties owned and operated by third parties, the Company will continue to
evaluate the purchase of outside investors' interests in wells operated by the
Company.
Exploitation programs may add to the Company's reserves because of the
upward revision in the estimate of existing producing properties' reserves from
the prior year's reserve estimate. The upward revision is due to, among other
things, recognition of the Company's effort to maximize productive capability
through enhanced operating techniques and thus increase ultimate recoverable
reserves by reducing reservoir abandonment pressures and increasing the well
drainage area of its existing producing properties.
The Company has entered into certain oil field-related service businesses
in order to diversify its revenue base. In addition to providing these services
for itself, the Company intends to make these services available to others in
the gas and oil industry (See "Business-Brine Hauling and Disposal Services").
Accordingly, the Company has formed HAWG Hauling & Disposal, Inc. ("HAWG"), a
brine hauling and disposal service and Phoenix-Alamco Ventures, a Limited
Liability Company ("PAV"), which is engaged in the marketing of Alamco's and
other working interest owners' gas. HAWG is a wholly owned subsidiary of the
Company while PAV is owned jointly by the Company and Phoenix Diversified
Ventures, Inc. ("Phoenix"). Revenues generated by HAWG and PAV totalled
$215,000 in 1994.
GAS AND OIL DEVELOPMENT ACTIVITIES
At December 31, 1994, the Company's proved reserves totalled 128.0 EBCF,
representing a 40.0 EBCF increase from year-end 1993 reserves. Based on these
reserve additions, the Company replaced 933 percent of the 4.8 EBCF it sold
during 1994. Drilling and acquisition activities during the year added reserves
of 33.8 EBCF while 11.0 EBCF was added because of the Company's on-going
exploitation program and the net result of a well swap. The Company invested
$15,812,000 in gas and oil development activities during the year, including
$6,234,000 in producing property acquisitions. Internally generated cash flows
and amounts drawn from the Company's revolving credit facility with Bank One,
Texas, N.A. ("Bank One") funded the capital program.
DRILLING ACTIVITIES
A total of 16.1 EBCF was added to the Company's reserves as a result of
the 1994 drilling program. The Company invested $9,312,000 or 59 percent of the
Company's gas and oil development expenditures in the drilling of 46.7 net
wells, of which 38.0 net wells were successful. The Company drilled, for its
own account, 30 and 16 gross wells in West Virginia and Tennessee,
respectively. The Company also drilled one gross (0.7 net) well in Kentucky,
which was unsuccessful.
Of the total number of wells drilled in West Virginia, 15 were drilled in
the South Burns Chapel Field in Monongalia and Preston Counties, including 5
wells drilled to the deep Oriskany Formation. The remaining 10 wells were
drilled to shallower zones at a depth of less than 3,000 feet. Also in North
Central West Virginia, the Company drilled 15 shallow gas wells located in
various counties throughout the region.
The 38.0 net productive wells drilled in 1994 is an increase over the 26.0
and 4.5 net wells drilled in 1993 and 1992, respectively. The increase in
development drilling during 1994 and 1993 is due to, among other things, the
number of drilling prospects identified by the Company's geological staff and
the availability of funds to finance the drilling activity. A number of
additional prospects have been identified on Company-held acreage in the South
Burns Chapel Field in West Virginia, the Days Chapel Field in Tennessee and in
various counties in Kentucky. (See "Future Activities").
During 1994, the Company drilled 9 dry holes, all of which were
development wells and within a proved area of a gas or oil reservoir. The wells
did not contain sufficient reserves warranting further expenditures.
DRILLING SUMMARY
Gross Wells Net Wells
Pro- Dry Total Pro- Dry Total
ductive ductive
1994 38 9 47 38.0 8.7 46.7
1993 28 3 31 26.0 3.0 29.0
1992 5 - 5 4.5 - 4.5
RECOMPLETION ACTIVITIES
The Company invested $266,000 in recompletion projects during 1994 as
compared to $119,000 and $542,000 in 1993 and 1992, respectively. Two
recompletion attempts were successful and three attempts did not establish
economic quantities of gas and oil production. All of the recompletion attempts
were located in West Virginia. The Company believes its inventory of wells
contains a significant number of recompletion candidates.
RECOMPLETION SUMMARY
Gross Wells Net Wells
Pro- Dry Total Pro- Dry Total
ductive ductive
1994 2 3 5 2.0 3.0 5.0
1993 - 2 2 - 2.0 2.0
1992 11 1 12 9.8 1.0 10.8
ACQUISITION ACTIVITIES
In 1994, the Company invested $6,234,000 or 39 percent of its gas and oil
development expenditures in the acquisition of 172.6 net wells. The acquisition
activities added 17.7 EBCF to the Company's reserves. The program included the
acquisition of both properties owned and operated by third parties and outside
investors' interests in wells operated by the Company.
In two transactions, the Company acquired from third parties 69 wells
(63.4 net wells) and over 35,000 gross acres (31,000 net acres) in southeastern
Kentucky for $1.8 million in cash. The Company became the operator of the wells
effective on the purchase dates. The Company continues to seek other well
acquisitions and leases in these areas.
The Company acquired, effective as of January 1, 1994, all of the
interests held by a number of limited partnerships in 114 West Virginia gas
wells (91.2 net wells), 102 of which were already operated by the Company for
$3.8 million in cash. The Company also acquired outside investors' interests in
other Company-operated wells, none of which were individually significant. Also
in West Virginia, the Company acquired 2.5 net Oriskany wells in the South Burns
Chapel Field.
NET WELLS ACQUIRED
Third Party Outside Investors' Interest in
Operated Wells Company Operated Wells Total
1994 71.0 101.6 172.6
1993 -- 24.9 24.9
1992 1.0 64.2 65.2
In order to consolidate its operations geographically and to reduce the
administrative burdens associated with operating co-owned wells, the Company,
effective March 1, 1994, exchanged its interest in approximately 141 gross wells
in West Virginia for outside investors' interests in approximately 237 gross
wells located in West Virginia. The exchange has been treated as a like-kind
exchange and no gain or loss has been recognized on this transaction.
GAS AND OIL PRODUCTION AND SALES
For 1994, gas sales accounted for 92 percent of the Company's total gas
and oil sales. The average 1994 sales price received by the Company was $2.22
per MMBtu ($2.50 per MCF) for gas and $14.52 per barrel for oil. The following
table sets forth the Company's sales volumes and other information for each of
the years ended December 31, 1994, 1993, and 1992.
PRODUCTION AND SALES STATISTICS
Year Ended December 31,
1994 1993 1992
Net Production:
Gas (MCF) 4,404,187 3,197,056 2,949,238
Oil (BBL) 67,749 37,409 32,333
Equivalent (MCF)(a) 4,810,681 3,421,510 3,143,236
Average Production Per Day:
Gas (MCF) 12,066 8,759 8,080
Oil (BBL) 186 102 89
Equivalent (MCF)(a) 13,180 9,374 8,612
Average Sales Price:
Per MCF of Gas $2.50 $2.79 $2.81
Per BBL of Oil $14.52 $16.01 $18.00
Average Cost of Production:
Per MCF of Gas $0.60 $0.60 $0.62
Per BBL of Oil $3.67 $4.30 $3.44
Average Cost of Production
Per Dollar of Sales:
Gas $0.24 $0.21 $0.22
Oil $0.25 $0.27 $0.19
(a) Oil production is converted to gas equivalents at a rate of 6 MCF per
barrel.
WELL TENDING SERVICES
In the aggregate, the Company owns as of December 31, 1994, approximately
82 percent of all Company operated wells with the remaining 18 percent being
held by outside investors. The Company charges a monthly fee for well operation
services and each outside investor pays a proportional share based on his
ownership percentage. For most of 1994, the monthly fees were $323 per well for
gas wells and $392 per well for oil wells compared to monthly charges in 1993 of
$308 per well for most gas wells and $374 per well for most oil wells. In 1994,
about 159 wells were not subject to the monthly operating fee due to temporary
abandonments. The income which the Company generates from these fees, well
tending income, accounted for approximately 9.0 percent, 18.3 percent, and 20.3
percent of the Company's revenues in 1994, 1993 and 1992, respectively.
Effective March 1, 1994, the Company exchanged its interests in
approximately 141 gross wells for outside investors' interests in approximately
237 gross wells located in West Virginia. Well tending income was substantially
reduced because this like-kind exchange reduced the number of wells that the
Company operates for outside investors. The Company believes, however, that
this reduction in well tending income will be offset over time by the effect of
higher gas and oil revenues attributable to the Company's greater ownership
interest in the wells.
BRINE HAULING AND DISPOSAL SERVICES
The Company has a wholly-owned subsidiary, HAWG, a commercial brine
hauling and disposal service company. The service entails, for a fee, the
transportation of brine to a central processing facility and injection of the
brine into non-economic wells. The subsidiary accepts brine, which is produced
naturally with gas and oil, from wells operated by the Company as well as from
other operators in West Virginia. HAWG currently operates a restricted use,
non-public brine disposal facility and has plans for converting other wells for
disposal service if HAWG obtains commercial contract status. In 1994, HAWG
provided 0.5 percent of the Company's total revenues.
GAS MARKETING
As a response to the changing gas marketing environment, the Company
formed PAV with Phoenix, a gas marketing company. PAV provides gas marketing
services to Alamco and other interest owners in Alamco operated wells. PAV has
the exclusive right to market most of Alamco's gas supply. PAV has been and
will be seeking diversification for Alamco's gas sales to other marketing
entities, local distribution companies and industrial users with a mixture of
short-term deals (less than a month), mid-term deals (one month to one year) and
long-term deals (one year or more). In 1994, PAV provided 1.0 percent of the
Company's total revenues.
While Alamco's share of the profits from PAV are not expected to be
significant, the prices received for gas sales marketed through PAV have been on
average above that which the Company would likely otherwise receive.
FUTURE ACTIVITIES
In the future, the Company intends to use internally generated cash flows
and amounts available under the Company's $25.0 million revolving credit
facility with Bank One to fund the development of its gas and oil reserves and
property acquisitions. As of March 22, 1995, $12.0 million was available for
borrowing under the credit facility.
The Company's 1995 capital investment program will ultimately depend upon
the market and prices received for natural gas and the ability of the Company to
capitalize on acquisition opportunities that may arise during the year. Until
gas prices improve, drilling activity will be limited to an estimated 5 to 10
wells in order to maintain leasehold positions, fulfill contractual commitments
and explore oil prospects. The Company will continue with its enhancement
program on existing wells, particularly the wells acquired last year in its
Kentucky acquisition program and where the Company has established a significant
acreage position. The Company's objective will be to maintain current
production and gas and oil reserve levels through well enhancements and limited
drilling activity while using excess cash flow to retire debt. The Company
plans to continue with its aggressive acreage acquisition strategy and will
position itself to increase both exploratory and development drilling when gas
prices recover. The Company remains committed to the acquisition of producing
properties at favorable prices.
MARKETS AND CUSTOMERS
General.
The Company operates exclusively in the gas and oil industry.
Sales through PAV and to Hope Gas, Inc. ("Hope") accounted for a
substantial portion of the Company's total 1994 gas and oil sales. The Company
sold 53.8 percent of its gas and oil sales through PAV to various marketers,
local distribution companies and commercial users. Additionally, sales to Hope
accounted for approximately 28.2 percent of the Company's total 1994 gas and oil
sales.
West Virginia Production.
PAV. In 1993, the Company entered into a three year gas marketing
agreement with PAV for nearly all gas transported on the Consolidated Natural
Gas Transmission Corporation ("CNG") pipeline system and all gas on the Columbia
Gas Transmission Corporation ("Columbia") pipeline system. Volumes sold in 1994
through PAV on the CNG and the Columbia systems totalled approximately 2.4 BCF.
The average price received from sales to PAV averaged $2.14 per MMBTU ($2.44 per
MCF) in 1994.
Hope. Hope purchases the Company's production from the South Burns Chapel
Field. The terms of the contract provide for Hope to purchase all of the gas
produced through November 1, 1999, at the monthly Appalachian index price.
Additionally, Hope pays to the Company a monthly demand charge for the Company's
ability to provide Hope with specified levels of gas supply. The pricing
provision is subject to renegotiation on April 1, 1996. This contract has
proven to be more favorable than spot market prices. However, Hope does have
the right, under certain conditions, to curtail gas purchases and did, in fact,
notify producers whose production flows directly into its system that it would
curtail all production from September 9, 1994 through October 18, 1994. The
Company was able to negotiate an interim purchase arrangement with Hope which
allowed the Company to produce and sell approximately 50 percent of its volumes
during most of the curtailment period. Since October 21, 1994, all of the
affected wells have been producing at unrestricted levels. The Company
estimates revenues were adversely affected by $250,000 due to this reduction in
volumes. Additionally, the Company sells other volumes of gas from the South
Burns Chapel Field to Hope under a market-sensitive pricing arrangement which is
subject to renegotiation on April 30, 1995. The Company believes the contract
will be extended under similar terms. The loss of this customer could have a
material adverse effect on the Company. However, the Company believes it would
be able to locate alternate customers in the event of such loss. Total volumes
sold to Hope in 1994 were approximately 1.4 BCF and averaged $2.50 per MMBTU
($2.50 per MCF).
Other. The Company sold gas from approximately 110 wells in its
Tallmansville, West Virginia field to CNG. CNG is permitted to recoup gas as a
result of a $3,800,000 prepayment made in 1989 for 1,565,000 MMBTU of gas. This
recoupment will take place under specified conditions until the earlier of full
recoupment or December 31, 1999, at which time the Company's obligation will be
fulfilled, whether or not the entire prepaid volumes have been recouped by CNG.
As of December 31, 1994, the Company had delivered approximately 1,120,000 MMBTU
of these prepaid volumes. Beginning March 1, 1994, the Company began selling
33.33 percent of the field's production through PAV with the remaining 66.67
percent of the production dedicated to CNG as recoupment. The Company intends,
however, in light of current depressed gas prices, to permit CNG to recoup 100
percent of the production beginning on or after March 1, 1995, and continuing
until gas prices improve or until the volumes are fully recouped. The Company's
remaining estimated share of the prepaid amount is included in deferred revenue.
The Company sells its other West Virginia gas production to various
purchasers that are not significant to the Company's revenue base.
Tennessee Production.
The Company is currently selling the gas production from its Tennessee
operations to Equitable Resources Marketing Company. This is a month-to-month
contract with market-sensitive pricing tied to Gulf Coast prices, less
transportation and compression charges. For 1994, the net-back price (reduced
for transportation) on volumes of approximately 180,000 MCF averaged $1.26 per
MMBTU ($1.49 per MCF). Tennessee production represents approximately 2.2
percent of total Company gas and oil sales.
Kentucky Production.
The Company's Kentucky production is currently approximately 1.2 percent
of total Company gas and oil sales. The Company is selling 60 percent of the
production from its Kentucky operations on the spot market or under short term
contracts providing for fixed or market-sensitive prices. Approximately 40
percent of the Company's Kentucky production is sold to one buyer under a
contract which dedicates the gas for the life of the wells, but which still
involves market-sensitive pricing. Company sales of Kentucky production
totalled 82,626 MCF and averaged $1.47 per MMBTU ($1.73 per MCF) in 1994.
Principal Transporters.
Most of the Company's gas is transported though the CNG, Hope, Columbia,
Texas Eastern, and Wiser Oil Company ("Wiser") pipeline systems which give the
Company access to major Northeastern markets. With the exception of the
Kentucky production, each of the Company's major gas production areas and leases
is in close proximity to at least one of those pipelines. A relatively minor
amount of the Company's gas is transported on other pipeline systems.
Oil Sales.
The Company's oil production is sold to various purchasers under
agreements at posted field prices. These sales, which accounted for 8 percent
of the Company's total gas and oil sales, averaged $14.52 per BBL in 1994.
Marketing Risks.
During the last several years, the gas industry has been adversely
affected by a surplus, which has tended to depress prices and has created
difficulty in estimating future prices. The Company is unable to predict with
certainty the future stability or direction of natural gas prices.
The availability of a ready market for the Company's gas and oil depends
on numerous factors beyond its control, including, among other factors, the
demand for and supply of gas and oil, the weather, the proximity of the
Company's natural gas reserves to pipelines, the capacity of such pipelines, the
cooperation of pipeline owners, general economic conditions, fluctuations in
seasonal demand and the effects of inclement weather and governmental
regulation. In addition, under certain gas purchase arrangements the Company is
subject to the risk of periodic reduced purchases or access to pipelines. Any
significant reduction or curtailment of production for an extended period of
time could have a material adverse effect on the Company's results of
operations.
Additionally, FERC Order 636, issued in 1992, appears to have resulted in
increased competition in the marketing of natural gas (see "Regulation").
COMPETITION
The Company operates in a highly competitive environment. Competition is
particularly intense with regard to the acquisition of producing properties and,
to a lesser extent, undeveloped acreage. Independent gas and oil companies,
partnerships and drilling programs with financial and human resources
substantially in excess of those available to the Company, compete with the
Company, actively bidding for desirable gas and oil properties.
Similarly, there is intense competition not only from other gas production
entities, but also from other marketing firms, both of which have the
capabilities to seek out and serve various customers. Although the Company has
historically enjoyed a price premium over Gulf Coast gas production (as do
others in the Appalachian Basin) due to the proximity of its production to major
Northeast markets, deregulation of the industry and the advent of open access
transportation on interstate pipelines have caused an erosion of this premium.
REGULATION
General. The oil and gas industry is extensively regulated by federal,
state and local authorities, with legislation affecting the industry under
constant review for changes and/or expansion, particularly with regard to
environmental issues. Numerous agencies, both federal and state, have issued
rules and regulations, some of which carry substantial penalties for failure to
comply, binding on the industry and its members. To date, these mandates have
had no material effect on the Company's capital expenditures, earnings or
competitive position. Inasmuch as new legislation affecting the oil and gas
industry is commonplace and existing laws and regulations are frequently amended
or reinterpreted, the Company is unable to predict the future cost or impact of
complying with such laws and regulations.
Environmental. The Company's operations are subject to various federal
and state statutes, rules and regulations regarding the control of discharging
materials into, or otherwise protecting the environment. These requirements
relate to drilling and production operations, activities in connection with
storage and transportation of gas and oil and facilities used for treating,
processing, injecting or handling the wastes therefrom. Additionally, in the
case of spills or other impermissible discharges of certain materials into the
environment, there are provisions for record keeping, notification and
reporting, as well as severe civil and criminal penalties for violations, and
potential liability for the costs of cleanup and any resultant damages.
Further, the possibility exists that certain oil and gas wastes may be
classified as hazardous or semi-hazardous, which could impose substantial
obligations on the Company. The Company does not believe that its compliance
with current environmental laws constitutes a material expense. (See Part I,
Item 3. Legal Proceedings.)
During 1994, the Company retained the services of an independent engineer
and an environmental engineering firm to assist with record keeping and
compliance matters and fully expects to continue using them for the foreseeable
future on an as-needed basis.
Federal Regulation. As a result of the Wellhead Decontrol Act of 1989,
all price controls for various classifications of gas were terminated as of
January 1, 1993. This has had no impact on the Company's gas sales since its
reserves were either previously deregulated or sold under contracts with
alternate pricing.
FERC Order 636, issued in 1992, generally required the unbundling or
separating of various components of pipelines services, i.e,, gathering,
transportation, storage and sales. Thus far, it appears to have resulted in
increased competition in the marketing of natural gas and could cause increased
costs for services the Company uses and decreased costs for services utilized by
producers in the Gulf Coast and Southwest regions.
Occupational and Safety Regulations. The Company is subject to the
requirements of the Occupational Safety and Health Act ("OSHA"), as well as
other state and local labor rules and regulations. The cost of compliance with
health and safety requirements has had no material impact on the Company's
aggregate production expenses to date. Nevertheless, the Company is unable to
predict the ultimate cost of compliance.
State Regulation. State regulatory authorities have established laws,
rules and regulations requiring, among other matters, permits for drilling and
recompletion operations, drilling and operating bonds or bank letters of credit,
and reports concerning operations. Further, there are statutes and regulations
governing the unitization or pooling of oil and gas leases, the spacing of wells
and plugging requirements for abandoned wells. To date, these requirements have
had no material effect on the Company's operations and the cost of compliance
has been minimal. Future regulations could, however, increase the cost of the
Company's production operations.
Brine Hauling and Disposal Services. In order to comply in an economical
manner with regulations governing the disposal of salt water, the Company began
operating its own salt water disposal well in 1992. In 1993, the Company formed
a new subsidiary, HAWG, which is responsible for the transportation and disposal
of the water. Additionally, HAWG received authority from the Public Service
Commission of West Virginia (the "PSC") in October 1993 to operate as a contract
carrier for the Company and other West Virginia producers. HAWG, in 1994,
applied to the PSC for approval to operate as a common carrier, which would
permit it to haul brine water commercially for any producer desiring such
service. The Company has not yet received approval from the PSC, but believes
that the PSC no longer has the authority to regulate the granting of such
certificates due to a federal law which went into effect on January 1, 1995.
However, since the PSC currently contends that it does have regulatory authority
over such issues, there may be continued delay in the start-up of the business
commercially.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
exploration for and production of gas and oil, such as blowouts, cratering,
abnormally pressured formations, explosions, uncontrollable flows of oil, gas or
well fluids into the environment, fires, pollution and other environmental
hazards and risks. These hazards could result in substantial losses to the
Company due to personal injury and loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage or
suspension of operations.
Expenditures made in 1994 due to environmental claims which were
unreimbursed were immaterial.
While the Company maintains levels of insurance which it believes to be
customary in the industry, the Company's insurance does not cover every
potential risk associated with the drilling and production of gas and oil
wells. The occurrence of a significant adverse event, the risks of which are not
fully covered by insurance, could have a material adverse effect on the
Company's financial condition and results of operations. Moreover, no assurance
can be given that the Company will be able to maintain adequate insurance in the
future at rates it considers reasonable.
Item 2. Properties.
The Company's properties consist essentially of the working and royalty
interests owned by the Company in various gas and oil leases which are located
in West Virginia, Tennessee and Kentucky. The Company's proved reserves for the
years ended December 31, 1994, 1993 and 1992 are presented below:
Year Ended December 31,
1994 1993 1992
Natural Gas (MMCF)
Developed 85,654 56,559 43,502
Undeveloped 33,971 26,059 15,328
Total Proved 119,625 82,618 58,830
Crude Oil (MBBL)
Developed 1,164 605 524
Undeveloped 235 292 357
Total Proved 1,399 897 881
These estimates are based primarily on the reports of independent
petroleum and geological engineers. Such reports are, by their very nature,
inexact and subject to changes and revisions. Proved developed reserves are
reserves expected to be recovered from existing wells with existing equipment
and operating methods. Proved undeveloped reserves are expected to be recovered
from new wells drilled to known reservoirs on undrilled acreage for which the
existence and recoverability of such reserves can be estimated with reasonable
certainty, or from existing wells where a relatively major expenditure is
required to establish production. No estimates of reserves have been included
in reports to any federal agency other than the Securities and Exchange
Commission and the Department of Energy (Note 15).
WELL COUNT
The Company obtained gas and oil sales revenues from 1,162 wells as of
December 31, 1994. The majority of the Company's producing wells, located in
northern and central West Virginia, are shallow wells drilled to a depth of up
to 6,000 feet and are characterized by long producing lives with low volume
production from low permeability reservoirs with a thickness ranging from 10 to
40 feet. A typical shallow well will encounter commercial gas production from
between 4 and 10 separate and distinct production horizons. Approximately 929
of the Company's wells produce from one or more of these "blanket" formations
that cover large areas of northern and central West Virginia. Due to mechanical
and technical constraints, it is usually possible to produce only up to three to
five of these formations simultaneously, and, consequently, it is necessary
either to drill a twin well or recomplete the original well at a later date.
A significant production horizon below 6,000 feet in the Company's West
Virginia operations is the Oriskany/Huntersville Chert formation. Deeper wells
in this formation exhibit higher pressure and productivity than wells in the
shallow West Virginia formations and reservoirs have thicknesses of up to 125
feet.
The Company's Tennessee production is from the Big Lime formation, an oil
reservoir that also produces casinghead gas. Big Lime wells are typically
characterized by low production volumes (5 to 35 barrels of production per day)
from low pressure and low permeability reservoirs varying in thickness from 10
to 40 feet.
In Kentucky, the Company's production is from numerous zones, including
the Big Lime, Coniferous, Maxton and Knox formations. These oil and gas
reservoirs, like many other Appalachian formations, are characterized by low
productive volumes with long producing lives.
WELLS AT DECEMBER 31, 1994
Gross Wells Net Wells
Gas Oil Total Gas Oil Total
West Virginia 985 29 1,014 825.3 26.6 851.9
Tennessee 8 71 79 3.3 32.9 36.2
Kentucky 54 15 69 48.4 15.0 63.4
Total 1,047 115 1,162 877.0 74.5 951.5
Note: Many of the Company's wells produce both gas and oil. For purposes of
computing the above data, the gas well versus oil well designations were
made on the basis of the type of artificial lift installed on the well.
PROSPECTS
The Company's producing wells hold approximately 122,000 acres under lease
which the Company believes includes a substantial number of promising
development prospects. The prospects include new development well locations and
candidates for the recompletion of now depleted or nearly depleted existing
wells to formations in the respective wellbores that have not yet been opened to
production.
Also, at December 31, 1994, the Company held leases which have not yet
been explored for the existence of gas and oil reservoirs. The Company may
drill wells on the acreage to determine the existence of productive reservoirs,
sell the leases to another gas and oil operator or abandon the acreage upon the
expiration of the lease term.
LEASE POSITION AT DECEMBER 31, 1994
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
Acres Acres Acres Acres
West Virginia 74,735 62,844 15,850 14,018
Tennessee 5,596 3,039 5,353 5,353
Kentucky 41,968 41,968 32,087 22,087
Total 122,299 107,851 53,290 41,458
TITLE TO PROPERTIES
Substantially all of the Company's property interests are held pursuant to
leases from third parties. Title to properties is subject to royalty,
overriding royalty, carried, net profits, working and other similar interests
and contractual arrangements customary in the gas and oil industry, liens
incident to operating agreements, liens relating to amounts owed to the
operator, liens for current taxes not yet due and other encumbrances. The
Company believes that such burdens neither materially detract from the value of
such properties nor from the respective interests therein, or materially
interfere with their use in the operation of the business.
As is customary in the industry, little investigation of record title is
made at the time of lease acquisition (other than a preliminary review of local
records) in regard to undeveloped properties. Investigations, including a title
opinion of local counsel, are generally made prior to the consummation of an
acquisition of larger producing properties and before commencement of drilling
operations.
OTHER PROPERTY
In addition to gas and oil properties, the Company's property and
equipment includes field warehouses, service (workover) rigs and support
vehicles. All of the Company's assets collateralize its indebtedness under its
revolving credit facility with Bank One. See Note 6 to the Company's Notes to
Consolidated Financial Statements. The Company's executive offices are under
leases which expire on August 31, 1996.
Item 3. Legal Proceedings.
The Company is not at this date a party to any material pending legal
proceeding, other than ordinary, routine litigation incidental to the business
of the Company and its subsidiaries. See Management's Discussion and Analysis
of Financial Condition and Results of Operations and Note 4 for information
related to the Company's litigation claim against Columbia.
On May 23, 1994, the United States Environmental Protection Agency (the
"EPA") issued an administrative complaint against the Company for alleged
violations of the Clean Water Act resulting from an oil discharge at the
Company's Days Chapel Field in Claiborne County, Tennessee. The incident
occurred in December 1993 when vandals severed locks securing the valves on the
Company's oil storage tanks and discharged approximately 174 barrels of oil into
a local creek.
The EPA has proposed that penalties of nearly $124,000 be assessed against
the Company. However, the Company contends that the asserted penalties exceed
the statutorily authorized limits. Settlement negotiations are ongoing and the
Company believes that, due to meritorious defenses, any final penalties will be
substantially less than those proposed although no assurances can be given as to
the exact amount of any final penalties.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of the Company's stockholders
during the quarter ended December 31, 1994.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of the Company are as follows:
Name Age Position
John L. Schwager 46 President, Chief Executive Officer and Director
Executive Vice President, Chief Operating Officer
Richard R. Hoffman 44 and Director
Steven E. May 38 Vice President and Controller
Bridget D. Furbee 35 Vice President of Administration and Legal Affairs
No family relationship exists among any of the Company's executive officers or
directors.
John L. Schwager has been President and Chief Executive Officer of the
Company since October 1987. Mr. Schwager served as the Company's Executive Vice
President from May 1987 through October 1987 and Senior Vice President of
Operations from September 1984 through May 1987. Mr. Schwager was elected a
director in 1986.
Richard R. Hoffman became the Company's Executive Vice President and Chief
Operating Officer on December 13, 1990. Mr. Hoffman served as Senior Vice
President, Exploration and Production from November 1988 through December 12,
1990, Vice President, Production from November 1986 to November 1988 and Manager
of Production from October 1982 through October 1988. Mr. Hoffman was elected
as a director in 1988.
Steven E. May has been the Vice President and Controller of the Company
since December 13, 1990. From June 1989 through December 1990, he served as
Assistant Controller and from October 1987 through May 1989 as the Manager of
Corporate Planning and Data Processing of the Company. Mr. May joined the
Company in April 1985 as a Senior Production Engineer.
Bridget D. Furbee has been the Vice President, Administration and Legal
Affairs of the Company since May 1994. Ms. Furbee served as Manager, Gas
Marketing and Legal Affairs from August 1992 through April 1994, and Gas
Marketing/Office Administration Manager from January 1985 through July 1994.
Prior to January 1985, Ms. Furbee served the Company in various clerical
positions.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
The Company's Common Stock is listed on the American Stock Exchange under
the trading symbol "AXO". The following table sets forth for the periods
indicated the high and low sales price of the Common Stock for each quarters in
1994 and 1993.
1994 1993
Quarter High Low High Low
First 7-1/2 6-3/8 5-5/8 5
Second 7-3/4 6-1/8 7 5-1/4
Third 7-3/8 6-1/4 7-5/8 5-3/8
Fourth 6-3/4 5-1/2 7-3/4 6
As of March 1, 1995, there were approximately 1,445 holders of the
Company's voting Common Stock. Since its incorporation in 1981, the Company has
not declared or paid any dividends with respect to the Company's Common Stock.
The Company presently intends to retain its funds for operations and expansion
of its business and does not expect to pay any cash dividends in the foreseeable
future. While the Company is not currently prohibited in its credit agreement
with Bank One from paying cash dividends, certain financial covenants may,
however, restrict such payments in the future. Subject to the terms of the
agreement, the declaration and payment by the Company of any dividends on its
Common Stock in the future and the amount thereof will, nevertheless, depend
upon the Company's operating results, financial condition, cash requirements,
future prospects, and other factors deemed relevant by the Company's Board of
Directors.
During 1993, the Company consummated a public offering of 3,105,000 shares
of Common Stock, of which 2,071,404 newly issued shares were sold by the Company
and 1,033,596 shares were sold by PNC Bank ("PNC"). The sale of the stock by
PNC represents all of the shares issued to PNC by the Company as part of the
Company's 1988 debt restructuring.
Item 6. 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--Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Year Ended December 31,
------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
STATEMENT OF INCOME
DATA:
Revenues (a) $13,671 $11,900 $11,350 $9,653 $ 9,183
Income (loss) from
operations 1,625 2,074 1,181 (180) 493
Income before
extraordinary
items and change in
DD&A accounting
principle(d) 1,646 1,552 939 288 1,101
Extraordinary items (e) -- -- -- 404 854
Change in DD&A
accounting
principle (b) -- -- 1,058 -- --
------- ------- ------- ------ -------
Net income 1,646 1,552 1,997 692 1,955
------- ------- ------- ------ -------
Cash dividends -- -- -- -- --
BALANCE SHEET DATA:
Total assets (a) $56,058 $43,261 $40,237 $37,213 $35,229
Working capital 835 1,321 2,475 2,214 2,274
Total long-term debt
(c) and (f) 12,995 1,003 9,561 10,306 7,736
Stockholders' equity (f) 28,475 26,743 15,222 13,152 12,629
---------------------------
See pages 19 and 20 for Financial Ratios and Per Share Data and Notes to
Selected Financial Data.
Year Ended December 31,
------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
PER SHARE DATA:
Income (loss) from
operations: $.35 $ .60 $ .46 ($.07) $ .19
Income before
extraordinary
items and
change in DD&A
accounting principle (d) .35 .45 .37 .11 .43
Extraordinary items -- -- -- .16 .33
Change in DD&A
accounting
principle (b) -- -- .41 -- --
----- ----- ----- ----- -----
Net income $.35 $ .45 $ .78 $ .27 $ .76
----- ----- ----- ----- -----
FINANCIAL RATIO DATA:
Book value per share
(b) and (f) $6.12 $5.77 $5.94 $5.18 $4.88
Total debt to
stockholders' equity (f) .5 -- .6 .8 .6
Current ratio 1.2 1.2 1.5 1.5 1.4
SELECTED PRODUCTION DATA:
First Second Third Fourth
1994 Quarter Quarter Quarter Quarter
---- ------- ------- ------- -------
Production volumes
Gas (MMCF) 917 1,001 1,230 1,255
Oil (MBBL) 9 17 19 23
Average Product Price
Gas ($/MCF) $2.94 $2.60 $2.30 $2.30
Oil ($/BBL) $12.30 $14.68 $16.02 $14.08
1993
----
Production volumes
Gas (MMCF) 722 728 781 967
Oil (MBBL) 7 9 10 11
Average Product Price
Gas ($/MCF) $3.09 $2.79 $2.49 $2.79
Oil ($/BBL) $16.96 $17.64 $15.61 $14.46
Notes to Selected Financial Data:
(a) During 1994, the Company acquired a total of 172.6 net producing wells
from various third parties. In October 1991, the Company acquired
working and royalty interests in 88 wells from Phillips Petroleum.
(b) During 1992, the Company changed its method of computing unit-of-
production depreciation from a well-by-well basis to a depositional
group basis (Note 7).
(c) Included in long-term debt as of December 31, 1990, is $974,000 relative
to the estimated maximum future interest payments capitalized in
accordance with generally accepted Financial Accounting Standards No. 15
"Accounting by Debtors and Creditors for Troubled Debt Restructurings."
(d) In accordance with SFAS No. 15 the carrying values of the Company's
restructured debt at the time of the Company's 1988 debt restructuring
included the estimated maximum amounts of principal and interest
payable. Included in net income and non-operating income for the year
1990 is $675,000, relative to the reversal of capitalized interest.
This amount reflects the recognition of gains due to the elimination of
future interest payable from the carrying value of the Company's debt.
(e) In 1990 the Company recorded an extraordinary gain of $854,000 due to
the extinguishment of a note payable to a trade vendor. The Company
recorded an extraordinary gain of $404,000 after considering certain
expenses and income tax benefits associated with the extinguishment of
debt in 1991.
(f) In 1993, the Company consummated a stock offering in which 2,071,404 new
shares of common stock were issued. The Company used the proceeds from
the stock offering in 1993 to repay its then outstanding balance on the
revolving credit facility with Bank One.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Management's discussion and analysis of changes in the Company's financial
condition, including liquidity and capital resources, and results of operations
during the twelve-month periods ended December 31, 1994, 1993 and 1992 are
presented below.
RESULTS OF OPERATIONS
Year Ended December 31, 1994 vs.
Year Ended December 31, 1993
--------------------------------
The Company reported net income of $1,646,000 for the year ended
December 31, 1994, an increase of $94,000 or 6.1 percent as compared to net
income of $1,552,000 in 1993. Income from operations for 1994 decreased
$449,000, or 21.6 percent, to $1,625,000 as compared to $2,074,000 for 1993.
Total revenues of $13,671,000 in 1994 were $1,771,000 or 14.9 percent
higher than total revenues of $11,900,000 in 1993.
Gas and oil sales totalled $11,993,000 in 1994 which represents a
$2,489,000 increase over the same period last year. Higher gas and oil
sales volumes, resulting principally from the acquisition of producing
properties and the drilling of new wells, contributed $3,362,000 and
$486,000, respectively, to the increase and were offset by lower gas
prices of $1,258,000 and lower oil prices of $101,000. Gas and oil sales
volumes totalled 4,810,681 equivalent thousand cubic feet ("EMCF") and
3,421,510 EMCF for the years ending December 31, 1994 and 1993,
respectively. The Company received on average $2.50 per MCF and $14.52
per barrel ("BBL") in 1994, compared to $2.79 per MCF and $16.01 per BBL
last year.
In early September 1994, Hope informed the Company and other local
suppliers that its gas supply exceeded its sales market requirements,
which could create an imbalance with CNG, its pipeline transporter, and
requested a temporary reduction of production volumes for an unstated
period of time. The Company agreed to temporarily reduce its production
by approximately 50 percent beginning September 12, 1994. Since October
21, 1994, all of the affected wells have been producing at unrestricted
levels. The Company estimates revenues were adversely affected by
$250,000 due to this reduction in volumes.
Current gas futures prices indicate the Company will receive in 1995 lower
prices as compared to that received in the past three years. Based on the
foregoing, the Company does not expect that it will be required to reduce
the carrying value of its gas and oil properties during 1995.
Well tending income decreased $940,000 or 43.3 percent due principally to
the reduction in the number of wells the Company operates for outside
investors. Effective March 1, 1994, the Company exchanged its interests
in approximately 141 gross wells for outside investors' interests in
approximately 237 gross wells. In addition, on August 1, 1994, but
effective January 1, 1994, the Company acquired an outside owners'
approximately 80 percent interest in 114 gross wells. The Company
believes the reduction in well tending income, as a result of these
transactions, will be offset over time by the effect of higher gas and oil
revenues attributable to the Company's greater ownership interest in the
wells (Note 2).
Other operating revenue increased $222,000 due primarily to the
recognition of income relative to the transaction in which the Company
formed a partnership with an East Coast financial institution (Note 3).
The partnership is structured such that the financial institution will be
allocated IRC Section 29 tax credits as a result of production from
properties contributed by the Company to the partnership. The financial
institution initially paid the Company $1.0 million, less $100,000 for
certain expenses incurred by the financial institution. The Company
recognizes income from this transaction, as the tax credits are generated.
Total expenses in 1994 were $12,046,000, an increase of $2,220,000 or
22.6 percent from expenses of $9,826,000 in 1993.
Operating expenses were higher by $1,199,000 or 28.1 percent due primarily
to the significant property acquisitions made and new wells drilled during
1994 and higher employee-related expenses due principally to the expansion
of the Company's drilling operations in the past 12 months. Staff levels
have increased in those departments that identify and acquire drilling
prospects as well as the engineering staff which oversees the drilling of
the wells.
General and administrative expenses for 1994 were higher by $535,000 or
22.5 percent as compared to last year due to, among other things, higher
business franchise taxes due to the increase in the Company's equity as a
result of the 1993 stock offering. In addition, higher employee-related
costs as well as expenses associated with the Company's Stockholders'
Rights Plan contributed to the increase. Also, amounts paid to Bank One
were higher due to increased commitment fees and other fees which are
based upon the unused portion of the Company's credit facility.
Depreciation, depletion and amortization expense was higher by $717,000
due to, among other things, higher depletion expenses related to the
increased gas and oil investments and higher production levels. Higher
depreciation expenses associated with fixed assets also contributed to the
increase.
Interest expense for 1994 was $154,000, a decrease of $231,000 over the
same period last year due primarily to capitalization of interest expense
related to drilling activities. During 1994, interest incurred by the
Company totalled $471,000 of which $317,000 was capitalized.
Non-operating income in 1994 totalled $155,000, a decrease of $166,000, as
compared to $321,000 for 1993 due principally to the absence in 1994 of certain
asset sales and franchise tax adjustments.
The Company's provision for income tax totalled $134,000 in 1994 as
compared to $843,000 last year. The reduction of $709,000 is due to, among
other things, a change in the effective state tax rate to reflect new business
activities in states with lower tax rates and recently implemented tax planning
activities, an increase in the deductions associated with percentage depletion
and lower income from operations.
Year Ended December 31, 1993 vs.
Year Ended December 31, 1992
--------------------------------
The Company reported net income of $1,552,000 for the year ended
December 31, 1993, compared to net income of $1,997,000 in 1992, which includes
the cumulative effect, net of tax, of a depreciation, depletion and amortization
accounting change of $1,058,000. Income from operations totalled $2,074,000 for
1993 compared to $1,181,000 for 1992.
Total revenues of $11,900,000 were higher by $550,000 or 4.8 percent than
revenues of $11,350,000 in 1992.
Gas and oil sales of $9,504,000 in 1993 were higher by $649,000 or 7.3
percent than 1992 sales of $8,855,000. Higher gas and oil sales volumes,
resulting primarily from the positive results of drilling activities and
the increase in the Company's ownership interest in a significant number
of other wells operated by the Company, contributed $786,000 to the
increase. The effect of lower gas and oil sales prices of $137,000
partially offset the increase due to higher gas sales volumes.
Well tending income in 1993 totalled $2,172,000 and was $136,000 or 5.9
percent lower than 1992 well tending income of $2,308,000. The reduction
was due primarily to the purchase of certain outside investors' interests
in Company-operated wells and lower fees chargeable to outside investors.
Other revenue totalled $224,000 and was $37,000 higher than last year.
Total expenses in 1993 totalled $9,826,000, a decrease of $343,000 or 3.4
percent from 1992 expenses of $10,169,000.
Operating expenses totalled $4,262,000 for 1993 compared to $4,041,000 for
1992. The $221,000 or 5.5 percent increase was due to, among other
things, higher production-based taxes and higher employee-related
expenses.
General and administrative expenses totalled $2,373,000 and were $3,000
lower than 1992 expenses of $2,376,000. Higher employee-related expenses
and other items were essentially offset by lower legal expenses.
Depreciation, depletion and amortization expense totalled $2,806,000 for
1993 and was lower by $201,000 or 6.7 percent due primarily to additions
to the Company's gas and oil reserve base.
Interest expense for 1993 was $385,000, a decrease of $360,000 from 1992.
The decrease in interest expense reflects the repayment of the Company's
credit facility in 1993.
Non-operating income in 1993 was $321,000, an increase of $121,000 from
1992. The increase is due primarily to higher asset sales and certain franchise
tax adjustments.
Effective January 1, 1992, the Company adopted Statement of Financial
Accounting Standard No. 109 retroactively to the beginning of 1990. The Company
recorded an income tax provision of $843,000 and $442,000 in 1993 and 1992,
respectively. The tax provisions reflect the Company's alternative minimum tax
status.
Effective January 1, 1992, the Company changed the method used to
calculate depreciation, depletion and amortization of producing properties (Note
7). The cumulative effect of the change, net of taxes, was $1,058,000.
LIQUIDITY AND CAPITAL RESOURCES
Working Capital. At December 31, 1994, the Company had working capital of
$835,000, as compared to $1,321,000 at December 31, 1993. The $486,000
reduction in working capital is due to, among other things, lower accounts
receivables resulting from the lower price received by the Company for gas sales
in the latter part of 1994 as compared to last year and an increase in deferred
revenues as a result of an agreement with an East Coast financial institution
(Note 3). Because the Bank One credit facility agreement, as amended, calls for
the payment of interest only until July 1, 1996, current liabilities on the
Company's December 31, 1993, balance sheet do not include any principal payments
relative to the Bank One credit facility.
Cash and cash equivalents totalled $2,632,000 at December 31, 1994. Of
this amount, approximately $1,559,000 was available for general corporate
purposes and the balance was held for third parties (Note 8). Operating
activities provided a net $6,238,000 while investing activities used a net
$17,210,000 including $16,734,000 in property acquisitions, drilling of new
wells, and other capital investment activities. Financing activities provided a
net $11,139,000.
Revolving Credit Facility. Currently, the Company has in place a
$25.0 million revolving credit facility with Bank One (Note 6). The Company is
required to pay interest only until July 1, 1996, at which time all principal
and accrued interest is due and payable. Interest accrues and is paid monthly
at a rate of Bank One's prime rate plus three-fourths of one percent.
The Company is no longer prohibited from paying dividends to its
stockholders under the Bank One credit agreement, however, certain other
financial covenants may restrict the payment of cash dividends. The Company
presently intends to retain its funds for operations and expansion of its
business and does not expect to pay any cash dividends in the foreseeable
future.
Capital Expenditures and Commitments. The Company's 1994 capital
investments totalled $16,734,000, including $15,812,000 for the acquisition of
producing properties and drilling of new wells. These activities were funded
from internal sources and the Bank One revolving credit facility. In the
future, the Company intends to continue to use internally generated cash flows
and amounts available under the credit facility to fund the development of its
gas and oil reserves and property acquisitions. (See Part I, Item 1.
"Business".)
Most of the Company's capital spending is discretionary and the ultimate
level of spending will be dependent, among other things, on the Company's
assessment of the gas and oil business environment, the number of gas and oil
prospects, and gas and oil business opportunities in general. The level of the
Company's 1995 capital expenditures will to a great extent depend upon the gas
prices received by the Company. Based on current gas futures prices, which
indicate the Company will receive lower gas prices, as compared to that received
in the past three years, the Company plans to limit annual drilling activities
to an estimated five to ten wells in order to maintain leasehold positions,
fulfill contractual commitments and explore oil prospects. The Company will
continue with its enhancement program on existing wells, particularly the wells
acquired last year in Kentucky and where the Company has established a
significant acreage position. The Company's objective will be to maintain
current production and gas and oil reserve levels through well enhancements and
limited drilling activity while using excess cash flow, if any, to retire debt.
The Company plans to continue with its aggressive acreage acquisition strategy
and will position itself to increase both exploratory and development drilling
when gas prices recover. The Company remains committed to the acquisition of
producing properties at favorable prices.
CNG Agreement. The Company and other working interest owners are
obligated to make available 445,000 MMBtu of gas for delivery to CNG between
January 1, 1995 and December 31, 1999. The Company's estimated share of the
obligation is included in deferred revenue. (See Part I, Item 1. "Business -
Markets" and Note 13.)
Settlement of Columbia Litigation Claims. On June 8, 1992, the Company
settled its outstanding gas purchase contract claims against Columbia. Pursuant
to the settlement agreement, the Company, on behalf of itself and other interest
owners in the wells covered by the settlement, has an allowed claim in the
amount of $11,000,000 against Columbia, without security or priority, in
Columbia's bankruptcy reorganization proceedings. The Company's share of the
allowed claim is estimated to be approximately 55 percent, with the balance
going to the other interest owners in the wells covered by the settlement. The
timing and actual amount to be received by the Company and other interest owners
will be affected by the terms of Columbia's reorganization plan as finally
approved by the Bankruptcy Court and the amount of assets available to satisfy
Columbia's unsecured creditors. Because of the uncertainty as to the actual
amount which may be received, the Company's financial statements do not include
any benefits of the settlement. However, management believes that the ultimate
payment in respect of the Company's claim is likely to be substantial.
Section 29 Tax Credits. Effective August 11, 1994, the Company, through a
series of transactions, formed a partnership with a major East Coast financial
institution (the "Institution"). The partnership is structured such that the
Institution will be allocated IRC Section 29 tax credits as a result of
production from properties contributed by the Company to the partnership (Note
3). The institution initially paid $1.0 million (reduced by $100,000 for
certain expenses incurred by the Institution), and will pay additional amounts,
up to $4.0 million, in installments prior to December 31, 2002, upon achieving
certain production minimums and satisfying other conditions. As part of the
Section 29 tax credit transaction, the Company formed Alamco-Delaware, Inc.
("Aladel") as a Delaware Investment Holding Company.
Quarterly Financial Data (Unaudited)
------------------------------------
The following table sets forth selected historical quarterly financial
data (unaudited) with respect to the Company for the quarters indicated in 1994
and 1993. The Company's results of operations are subject to quarterly
variations due to, among other factors, weather conditions and other supply and
demand factors affecting the natural gas markets. Historically, the demand and
price paid for natural gas has increased in the cold winter months and decreased
in the warm summer months. Such quarterly data is not necessarily indicative of
the Company's future performance. Because of quarterly variations, the Company
believes that its results of operation should be viewed on an annual basis.
(in thousands, except per share data)
First Second Third Fourth
1994 Quarter Quarter Quarter Quarter
---- ------- ------- ------- -------
Sales and other operating
revenues $3,370 $3,208 $3,464 $3,629
Gross profit 1,347 1,128 1,161 1,051
Net income (1) 462 321 353 510
Net income per share $0.10 $0.07 $0.08 $0.10
First Second Third Fourth
1993 Quarter Quarter Quarter Quarter
---- ------- ------- ------- -------
Sales and other operating
revenues $2,985 $2,765 $2,717 $3,433
Gross profit 1,242 1,074 976 1,540
Net income 457 215 368 512
Net income per share (2) $0.18 $0.08 $0.09 $0.10
----------------------
(1) In the fourth quarter of 1994, the Company adjusted its provision for
income taxes by $256,000 to reflect a change in the effective state tax
rate. In addition, an increase in deductions associated with percentage
depletion and lower income from operations also reduced the income tax
provision.
(2) In the third quarter of 1993, the Company consummated a stock offering in
which 2,071,404 new shares were issued.
Item 8. Consolidated Financial Statements.
------- ----------------------------------
Index to Consolidated Financial Statements
------------------------------------------
Pages
-----
Independent Auditor's Report 28
Consolidated Statement of Income, for the
Years Ended December 31, 1994, 1993, and 1992 29
Consolidated Balance Sheet, as of December 31, 1994 and 1993 30-31
Consolidated Statement of Changes in Stockholders' Equity,
for the Years Ended December 31, 1994, 1993 and 1992 32
Consolidated Statement of Cash Flows for the
Years Ended December 31, 1994, 1993 and 1992 33-34
Notes to Consolidated Financial Statements 35-54
INDEPENDENT AUDITOR'S REPORT
To the Board of Directors and Stockholders
of Alamco, Inc.
We have audited the accompanying consolidated balance sheet of Alamco, Inc. and
subsidiaries as of December 31, 1994 and 1993, and the related consolidated
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects the consolidated financial position of Alamco, Inc. and
subsidiaries as of December 31, 1994 and 1993, and the consolidated results of
their operations and their consolidated cash flows for each of the three years
in the period ended December 31, 1994 in conformity with generally accepted
accounting principles.
As discussed in Note 7 to the consolidated financial statement, the Company
changed its method of computing depreciation, depletion and amortization in
1992.
/s/ Coopers & Lybrand L.L.P.
600 Grant Street
Pittsburgh, Pennsylvania
March 3, 1995
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Years Ended December 31, 1994, 1993 and 1992
(In thousands, except share data)
===============================================================================
1994 1993 1992
---- ---- ----
Revenues:
Gas and oil sales $11,993 $ 9,504 $ 8,855
Well tending income 1,232 2,172 2,308
Other revenue 446 224 187
------- ------- -------
Total revenues 13,671 11,900 11,350
------- ------- -------
Expenses:
Operating 5,461 4,262 4,041
General and administrative 2,908 2,373 2,376
Depreciation, depletion, and
amortization 3,523 2,806 3,007
Interest 154 385 745
------- ------- -------
Total expenses 12,046 9,826 10,169
------- ------- -------
Income from operations 1,625 2,074 1,181
Other nonoperating income 155 321 200
------- ------- -------
Income before income tax 1,780 2,395 1,381
Provision for income taxes 134 843 442
------- ------- -------
Income before
cumulative effect of DD&A
accounting change 1,646 1,552 939
Cumulative effect of DD&A accounting
change, net of tax -- -- 1,058
------- ------- -------
Net income $ 1,646 $ 1,552 $ 1,997
======= ======= =======
Per share data:
Income before
cumulative effect of DD&A
accounting change $0.35 $0.45 $0.37
Cumulative effect of DD&A
accounting change -- -- 0.41
----- ----- -----
Net income $0.35 $0.45 $0.78
===== ===== =====
Weighted average number of shares
outstanding 4,645,154 3,438,594 2,555,654
========= ========= =========
Accompanying notes are an integral part of the consolidated financial
statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1994 and 1993
(In thousands)
===============================================================================
ASSETS 1994 1993
------ ---- ----
Current assets:
Cash and cash equivalents $ 2,632 $ 2,465
Accounts receivable, net of allowance of
$9-1994; $127-1993; 2,693 3,975
Due from partnerships and programs 140 158
Inventories and other current assets 428 261
------- -------
Total current assets 5,893 6,859
------- -------
Property and equipment:
Gas and oil producing properties
(Successful Efforts Method) 71,782 60,181
Other property and equipment 5,270 4,944
------- -------
77,052 65,125
Less accumulated depreciation,
depletion and amortization 28,487 29,647
------- -------
48,565 35,478
Other assets 1,600 924
------- -------
Total assets $56,058 $43,261
======= =======
(Continued)
Accompanying notes are an integral part of the consolidated financial
statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1994 and 1993
(In thousands, except share data)
===============================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY 1994 1993
------------------------------------ ---- ----
Current liabilities:
Current portion of long-term debt and capital
lease obligations $ 106 $ 283
Accounts payable 1,325 847
Accrued expenses 1,398 979
Due working interest and royalty owners 1,064 2,738
Deferred revenue 1,165 691
------- -------
Total current liabilities 5,058 5,538
------- -------
Long-term debt and capital lease obligations 12,889 720
Due working interest and royalty owners 888 1,404
Deferred revenue 333 674
Deferred taxes 8,011 7,810
Other long-term liabilities 404 372
------- -------
Total liabilities 27,583 16,518
------- -------
Commitments and contingencies
Stockholders' equity:
Preferred stock, par value $1.00 per share;
1,000,000 shares authorized, none issued -- --
Common stock, par value $0.10 per share;
7,500,000 and 6,400,000 shares
authorized, respectively;
4,712,713 and 4,703,677 shares issued
and outstanding, respectively 471 470
Additional paid-in capital 31,039 30,981
Accumulated deficit since September 30,
1985 quasi-reorganization (2,847) (4,493)
------- -------
28,663 26,958
Less treasury stock, at cost, 63,360 and 72,792
shares of common stock, respectively 188 215
------- -------
Total stockholders' equity 28,475 26,743
------- -------
Total liabilities and stockholders' equity $56,058 $43,261
======= =======
Accompanying notes are an integral part of the consolidated financial
statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
Years Ended December 31, 1994, 1993 and 1992
(In thousands)
===============================================================================
Accumulated
Class A Additional Deficit
Common Common Paid-in Since Treasury
Stock Stock Capital 9/30/85 Stock
----- ----- ------- ------- -----
Balance January 1, 1992 $157 $103 $21,155 ($8,042) $221
Issuance of treasury stock -- -- 3 -- (64)
Exercise of stock options -- -- 6 -- --
Net income -- -- -- 1,997 --
---- ---- ------- ------- ----
Balance December 31, 1992 157 103 21,164 (6,045) 157
Acquisition of treasury stock -- -- -- -- 129
Issuance of treasury stock -- -- 10 -- (86)
Public stock offering 310 (103) 9,741 -- --
Exercise of stock options 3 -- 66 -- 15
Net income -- -- -- 1,552 --
---- ---- ------- ------ ----
Balance December 31, 1993 470 -- 30,981 (4,493) 215
Issuance of treasury stock -- -- 36 -- (34)
Issuance of common stock -- -- 32 -- --
Acquisition of treasury stock -- -- -- -- 7
Exercise of stock options 1 -- 10 -- --
Public stock offering-
additional costs -- -- (20) -- --
Net income -- -- -- 1,646 --
---- ---- ------- ------ ----
Balance December 31, 1994 $471 $ -- $31,039 ($2,847) $188
==== ==== ======= ====== ====
Accompanying notes are an integral part of the consolidated financial
statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1994, 1993 and 1992
(In thousands)
===============================================================================
1994 1993 1992
---- ---- ----
Cash flows from operating activities:
Net income $1,646 $1,552 $1,997
Adjustments to reconcile net income to
net cash provided by (used in)
operating activities:
Depreciation, depletion and
amortization 3,523 2,806 3,007
Deferred taxes 201 744 144
Cumulative effect of DD&A accounting
change -- -- (1,058)
Gain on asset sales (76) (141) (74)
Issuance of stock for employee
benefits and compensation expense 102 86 69
Other factors, net 12 13 17
Increase (decrease) in cash from
changes in:
Accounts receivable 1,282 (275) (379)
Due from partnerships and programs 18 97 184
Due working interest and royalty
owners (1,674) (340) 561
Inventories and other current assets (167) (105) 39
Accounts payable and accrued expenses 897 438 74
Deferred revenue 474 231 268
------ ------ ------
Net cash provided by
operating activities 6,238 5,106 4,849
------ ------ ------
Cash flows from investing activities:
Proceeds from disposal of fixed assets 278 150 133
Payment for the acquisition of
producing properties (6,234) -- --
Capital expenditures (10,500) (6,685) (2,715)
Investment in limited partnership (290) -- --
Other assets (464) (161) (678)
------ ------ ------
Net cash used in investing
activities (17,210) (6,696) (3,260)
------ ------ ------
(Continued)
Accompanying notes are an integral part of the consolidated financial
statements.
ALAMCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1994, 1993 and 1992
(In thousands)
===============================================================================
1994 1993 1992
---- ---- ----
Cash flows from financing activities:
Borrowings under line of credit $13,300 $ 500 --
Payment on line of credit (1,000) -- --
Principal payments on long-term debt
and capital lease obligations (320) (9,098) $ (759)
Acquisition of treasury stock (7) (144) (5)
Net proceeds from public offering of
common stock -- 9,948 --
Additional costs of public offering
of common stock (20) -- --
Proceeds from exercise of stock options 11 69 9
Other liabilities (825) (1,012) (53)
------ ------ ------
Net cash provided by (used in)
financing activities 11,139 263 (808)
------ ------ ------
Net increase (decrease) in cash and
cash equivalents 167 (1,327) 781
Cash and cash equivalents -
beginning of period 2,465 3,792 3,011
------ ------ ------
Cash and cash equivalents -
end of period $2,632 $2,465 $3,792
====== ====== ======
Supplemental disclosure of cash flow
information:
Cash paid during the year for:
Interest $216 $373 $732
Income taxes 55 180 308
Supplemental Schedule of Non-Cash
Investment and Financing Activities:
Fixed assets acquired under capital
lease -- $27 --
Like-kind exchange of property $3,270 -- --
Accompanying notes are an integral part of the consolidated financial
statements.
1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. These consolidated financial statements
include the combined accounts of Alamco and its subsidiaries, Aladel, HAWG and
PAV. Aladel and HAWG are wholly owned subsidiaries of the Company. All sig-
nificant intercompany balances have been eliminated in consolidation.
Revenue Recognition. Royalties, overrides and working interest revenues
are recognized based on production. No material difference would result if
revenues were recognized based on sales. Well tending income is recognized as
revenue as services are performed.
Cash and Cash Equivalents. The Company considers certificates of deposit,
U.S. government securities and other short-term securities with maturities of
three months or less as cash and cash equivalents.
Fair Value of Financial Instruments. The following methods and assumptions
were used by the Company in estimating the fair value of each class of financial
instruments for which it is practicable to estimate that value.
For cash and cash equivalents, receivables, and payables, the carrying
amounts approximate fair value because of the short maturity of these instru-
ments. For long-term debt, including current maturities, the fair value of the
Company's long-term debt approximates historically recorded cost since interest
rates approximate market.
Off-Balance Sheet Risk. In accordance with industry practice, the Company
has gas and oil sales contracts with commitments to sell minimum quantities of
gas and oil, primarily at market prices, for varying periods.
Gas and Oil Producing Properties. The Company uses the successful efforts
method of accounting for gas and oil producing properties. Under the successful
efforts method, certain expenditures, such as geological and geophysical costs,
exploratory dry hole costs, delay rentals, and other costs directly related to
exploration are recognized currently as expenses. All direct costs relating to
property acquisitions, successful exploratory wells, all development costs, and
support equipment and facilities are capitalized and depreciated, depleted or
amortized using the units-of-production method (Note 7). Production overhead
and other costs are expensed as incurred. Gas and oil producing properties also
include well equipment covered by capital lease obligations. Amortization of
the lease assets is included in depreciation, depletion and amortization
expense. Interest costs incurred in the drilling of wells are capitalized and
amortized using the units-of-production method. The Company capitalized
interest costs of $317,000 in 1994 and none in the years 1993 and 1992.
Interest incurred during 1994 totalled $471,000.
The Company compares the carrying value of its gas and oil producing
properties to the estimated future cash flow from such properties, less
applicable income taxes (the "ceiling") in order to determine whether the
carrying value of such properties should be reduced. No adjustment was
necessary as of December 31, 1994, 1993, or 1992.
On September 30, 1985, as a part of the Company's quasi-reorganization to
revalue its assets and liabilities, the carrying value of gas and oil producing
properties was reduced to an estimated fair value. The quasi-reorganization was
implemented to reflect the impaired ability at that time to fully recover the
investments in gas and oil properties.
Other Property and Equipment. Other property and equipment are stated at
cost, except that the carrying values of property and equipment were reduced to
estimated fair value as of the quasi-reorganization. Depreciation of other
property and equipment is computed using the straight-line method over estimated
useful lives of three to forty years, without considering the recoverable value
of equipment salvageable from the wells.
On an annual basis, the Company estimates the costs of future
dismantlement, restoration, reclamation and abandonment of its gas and oil
producing properties. Concurrently, the Company evaluates the estimated salvage
value of equipment recoverable upon abandonment. At December 31, 1994, the
Company's estimate of equipment salvage values is in excess of the costs of
future dismantlement, restoration, reclamation and abandonment.
Costs of individual gas and oil wells determined to be uneconomical are
charged to accumulated depreciation, depletion and amortization, with no gain or
loss being recognized until the depositional group in which the well is included
is abandoned. When other property and equipment are retired or otherwise
disposed of, the cost and related accumulated depreciation are removed from the
accounts, and any gain or loss is reflected in income for the period. The cost
of maintenance and repairs is expensed as incurred; significant renewals and
betterments are capitalized.
Intangible Assets. Intangible assets, which are reported in other assets
on the Company's balance sheet, consist of a non-compete and a consulting
agreement arising from the acquisition of 62 wells in Southeastern Kentucky
(Note 2). The values assigned to intangible assets are being amortized on a
straight line basis over the life of the agreements which range from four to
five years.
Covenant not to compete . . . . . . $312,000
Consulting agreement . . . . . . . . 390,000
Less accumulated amortization . . . (78,000)
--------
$624,000
========
Income Taxes. The Company accounts for certain income and expense items
differently for financial reporting purposes than for purposes of computing
income taxes currently payable. These differences arise primarily due to when
certain income and expense items are recognized for financial reporting and tax
purposes and are generally referred to as temporary differences. Provisions for
deferred taxes are made in recognition of such temporary differences.
Common Stock Designation. In consideration of the Company's public stock
offering, in 1994, the Board of Directors authorized that the number of
authorized shares of the Class A Common Stock be decreased from 1,100,000 shares
to zero. The Board further authorized that the shares previously designated as
Class A Common Stock be restored to the status of authorized but unissued shares
of the Company's common stock.
Income Per Share. Income per share amounts are computed by dividing the
income before the cumulative effect of DD&A accounting change and net income by
the weighted average number of shares outstanding in 1994, 1993 and 1992.
Reclassifications. Reclassifications have been made to certain amounts
previously reported in the consolidated financial statements, principally with
respect to the Consolidated Statement of Cash Flows for the year ended
December 31, 1993.
2 - PROPERTY ACQUISITIONS AND WELL SWAP
On March 31, 1994, the Company exchanged its interests (the "Well
Exchange") in 141 gross wells for outside investors' interests in 237 gross
wells. The exchange was effective March 1, 1994. The exchange has been treated
as a like-kind exchange and no gain or loss has been recognized on this
transaction.
In a separate transaction, the Company received a note in exchange for the
sale of operating rights in a number of wells. Further, the Company sold its
wholly-owned subsidiary, Interstate Resources, Inc. ("IRI"), in exchange for a
note. The sale of the Company's operating rights and IRI were to the same non-
affiliated party and combined into a single interest bearing note in the
principal amount of $272,000. The gain resulting from the sale of operating
rights and sale of IRI will be deferred and recognized as principal payments are
received.
On July 18, 1994, the Company acquired certain gas and oil properties and
intangible assets located in Southeastern Kentucky for $2.5 million in cash
(Note 1). The Company acquired 62 wells (56.4 net wells) together with 34,000
gross acres (30,000 net acres) and became the operator of the wells.
On August 1, 1994, the Company acquired all of the interest held by a
number of limited partnerships in 114 West Virginia gas wells (91.2 net wells),
of which 102 were already operated by the Company (the "West Virginia
Acquisition"). The Company acquired these wells for a net $3.8 million in cash.
Also, on August 1, 1994 the Company acquired seven wells and 1,275 acres in
Whitley County, Kentucky, for $185,000. The Company became the operator
effective as of the purchase date.
The Company also acquired 2.5 net wells producing from the Oriskany
formation in the South Burns Chapel Field for $500 effective as of July 1, 1994.
These transactions have been accounted for under the purchase method and,
accordingly, the operating results for the transactions have been included in
the Company's consolidated operating results from the dates of the respective
acquisitions forward.
As the West Virginia Acquisition and the Well Exchange represent a
substantial majority of the assets acquired during the year, the following
summary, prepared on a pro forma basis, combines the consolidated results of
operations as if the two transactions had been consummated as of January 1,
1994.
The pro forma results are not necessarily indicative of what actually would
have occurred if the acquisitions had been in effect for the entire periods
presented. In addition, they are not intended to be a projection of future
results and do not reflect any synergies that might be achieved from combined
operations.
1994
(Unaudited and in
thousands of dollars)
Revenues $14,340
Expenses 12,457
Income from operations 1,883
Net income 1,814
Net income per share $ 0.39
3 - SECTION 29 TAX CREDITS
The Company currently produces approximately 800,000 MMBtu per year of
natural gas that is eligible for a tax credit of $1.00 per MMBtu under Internal
Revenue Code ("IRC") Section 29. The tax credit applies to natural gas produced
from "nonconventional" fuel sources, as defined, including gas production from
Devonian Shale formations in certain West Virginia counties where the Company
has production operations. In addition to producing from certain
nonconventional fuel sources, the production must have been from wells drilled
between December 31, 1979 and December 31, 1992, and the gas must be sold before
December 31, 2002. The tax credit is allowed to reduce a taxpayer's regular tax
liability but may not be used to reduce a taxpayer's alternative minimum tax
("AMT") liability. The credits also must be used in the tax year in which they
are generated.
The Company is currently, and is projected to be in the future, an AMT
taxpayer and therefore is unable to fully use the tax credits to reduce its tax
liability. In this regard, through a series of transactions, the Company formed
a partnership with a large East Coast financial institution (the"Institution").
The partnership is structured such that the Institution will be allocated IRC
Section 29 tax credits as a result of production from properties contributed by
the Company to the partnership. The Institution initially paid $1.0 million
(reduced by $100,000 for certain expenses incurred by the Institution), and will
pay additional amounts, up to $4.0 million, in installments prior to December
31, 2002, upon achieving certain production minimums and satisfying other
conditions. The Company estimates that this transaction, which was effective
August 11, 1994, will allow it to realize $0.65 for each $1.00 in available
Section 29 tax credits generated by the producing properties.
As of August 11 1994, the effective date of the transaction, the Company
recognized $1.0 million in deferred revenues and will recognize income from this
transaction as the required gas production levels are achieved. In 1994 the
Company recognized $249,000 in income relative to this transaction.
Accordingly, as of December 31, 1994, the Company's balance sheet includes
$751,000 in deferred revenues, of which $676,000 is current.
4 - SETTLEMENT OF COLUMBIA LITIGATION CLAIMS
On June 8, 1992, the Company settled its outstanding gas purchase contract
claims against Columbia. Pursuant to the settlement agreement, the Company, on
behalf of itself and other interest owners in the wells covered by the
settlement, has an allowed claim in the amount of $11,000,000 against Columbia,
without security or priority, in Columbia's bankruptcy reorganization
proceedings. The Company's share of the allowed claim is estimated to be
approximately 55 percent, with the balance going to the other interest owners in
the wells covered by the settlement. The timing and actual amount to be
received by the Company and other interest owners will be affected by the terms
of Columbia's reorganization plan as finally approved by the Bankruptcy Court
and the amount of assets available to satisfy Columbia's unsecured creditors.
Because of the uncertainty as to the actual amount which may be received, the
Company's financial statements do not include any benefits of the settlement.
However, management believes that the ultimate payment in respect of the
Company's claim is likely to be substantial.
5 - PUBLIC STOCK OFFERING
On July 29, 1993, the Company consummated a public offering at a price to
the public of $5.50 per share for 2,700,000 shares of Common Stock, of which
2,000,000 shares were sold by the Company and 700,000 shares were sold by PNC.
The Company's net proceeds from this sale approximated $10.2 million before
considering expenses associated with the stock offering. The Company used
approximately $8.6 million of the net proceeds to repay its revolving credit
facility loan balance with Bank One.
On August 18, 1993, the underwriters exercised their option to purchase at
a price to the public of $5.50 per share an additional 405,000 shares, of which
the first 333,596 shares were sold by PNC and the remaining 71,404 shares were
newly issued shares sold by the Company. The aggregate 1,033,596 shares sold by
PNC represented all of the non-voting Class A Common Stock issued to PNC by the
Company as part of the 1988 debt restructuring. Upon the sale of the 1,033,596
shares in the stock offering, the shares automatically converted to voting
Common Stock on a one-for-one basis.
6 - LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
The Company has a $25.0 million revolving credit facility with Bank One
which calls for the payment of interest only until July 1, 1996 at which time
all outstanding principal and interest amounts are due. Interest accrues and is
paid monthly at a rate of Bank One's prime rate plus three-fourths of one
percent. During 1993, using a portion of the 1993 stock offering, the Company
repaid all amounts outstanding under the Bank One credit facility. As of
December 31, 1994 the aggregate amount of borrowing under the Bank One revolving
credit facility was $12,800,000. Bank One's prime interest rate on December 31,
1994, was 8.5 percent.
The credit facility is subject to semiannual borrowing base revisions (in
March and September of each year) to be made in accordance with borrowing base
recalculations performed by Bank One. Revisions could result in the extension
of credit and repayment terms or, in the case of erosion of the borrowing base,
the reduction of outstanding principal amounts or the amount of the credit
facility. Based on the latest Bank One recalculation, performed in September
1994, the borrowing base is sufficient to allow full utilization of the maximum
$25.0 million credit facility.
In addition to interest payments, the Company is required to pay a
commitment fee equal to the difference between the facility amount and the
amount borrowed multiplied by one-half of one percent prorated into quarterly
payments. The agreement also contains covenants which, among other things,
require that the Company maintain specified levels of cash flow, stockholders'
equity and ratio of current assets to current liabilities. The credit facility
is collateralized by all of the Company's assets including the Company's gas and
oil reserves.
Included in 1994 long-term debt is one installment sales obligation of
$27,000 to McJunkin Corporation ("McJunkin"). Interest on this obligation,
which is scheduled to be satisfied during the first quarter of 1995, is paid
monthly at 8.7% per annum.
Long-term debt at December 31, 1994 also included five note obligations to
PNC in the aggregate remaining amount of $146,000 relative to the settlement of
certain investor-related lawsuits. The terms of the obligations vary by note;
however the largest of the five notes, in the original principal amount of
$263,000, requires quarterly payments. Interest accrues on the notes at PNC's
prime rate, except for three notes aggregating $193,500 in original principal on
which interest payments are not required.
The aggregate maturities of long-term debt for each of the next five years
and thereafter are as follows (in thousands):
1995 $ 106
1996 12,832
1997 20
1998 19
1999 and thereafter 18
------
$12,995
======
The Company also leases certain equipment used in the production of gas and
oil under three lease programs with McJunkin. These equipment leases are for
varying terms with purchase options at the end of the lease term. In addition,
as part of a 1988 restructuring with McJunkin, the leases were amended to permit
the Company to extend the leases for varying periods with rentals due with
respect to the extension periods to be paid from a 2-1/2 percent working
interest of the Company on the wells where the leased equipment is situated.
The Company has extended the lease periods for all three programs. Since rental
payments due under such extensions are contingent upon the proceeds of gas and
oil production, such payments will be expensed as incurred. There are no future
minimum lease payments due.
Gas and oil properties related to capital leases total $2,328,000 and are
fully amortized, as adjusted for the quasi-reorganization effected September 30,
1985.
7 - ACCOUNTING CHANGE
Effective January 1, 1992, the Company changed the method used to calculate
depreciation, depletion and amortization ("DD&A") of producing gas and oil
properties from an individual well basis to an aggregation of wells by a common
geological depositional system. The cumulative effect of the pre-tax accounting
change was $1,763,000 and increased net income by $1,058,000 in 1992, which
includes the effect on prior years, net of tax. The effect of the change during
1992 increased income from operations by $17,000.
8 - CASH AND CASH EQUIVALENTS
Cash and cash equivalents totalled $2,632,000 at December 31, 1994. Of
this amount, approximately $1,559,000 was available for general corporate
purposes and the balance was held for third parties, including $207,000 in gas
and oil sales proceeds held for eventual distribution to outside working
interests and royalty owners, $646,000 representing the outside interests'
estimated share of cash prepaid by CNG for future gas deliveries, and $220,000
withheld from outside working interests' proceed distributions to be utilized
for future ad valorem tax payments (Note 9). The Company's cash balance at
December 31, 1994 includes $2,340,000 invested in commercial paper, U.S.
Government and Agency Securities and Bankers' Acceptances, the annualized annual
percent of return of which was 5.5 percent at December 31, 1994.
9 - PLUGGING AND AD VALOREM TAX FUNDS
The Company retains a portion of outside investors' monthly gas and oil
production proceeds to be utilized for future well plugging and abandonment
costs and ad valorem tax payments. The funds, totalling $662,000 at
December 31, 1994, are invested in securities issued or guaranteed by the United
States Treasury in accounts segregated from those of the Company. Interest
earned on the funds accrues to the benefit of the working interest owners.
Included in other assets is $442,000 for future ad valorem payments and plugging
and abandonments. Corresponding amounts recorded in assets are included in
liabilities.
10 - INCOME TAXES
The following table details the components of the Company's income tax
expense for the year 1992 through 1994.
1994 1993 1992
---- ---- ----
(In thousands)
Federal:
Current ($67) $ 99 $298
Deferred 397 618 46
---- ---- ----
Total Federal 330 717 344
---- ---- ----
State:
Deferred (196) 126 98
____ ____ ____
Total $134 $843 $442
==== ==== ====
Reconciliations of the income tax provision (benefit) computed at the
statutory rate and the provision for income taxes as shown on the Statement of
Income are summarized below:
Year Ended December 31,
--------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Tax provision computed at statutory rate $592 $814 $470
State taxes 104 126 83
Change in effective state tax rate (255) -- --
Use of percentage depletion (321) (103) (122)
Other 14 6 11
---- ---- -----
Provision (benefit) for income taxes $134 $843 $442
==== ==== =====
The change in effective state tax rate reflects the Company's new business
activities in states with lower tax rates and recently implemented tax planning
activities.
The components of the net deferred tax liability are as follows:
December 31,
----------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Depreciation, depletion and amortization $12,293 $10,668 $9,694
Accounts receivable write-off (30) (31) (33)
Future litigation payments (72) (126) (161)
Sale of partnership interest (293) -- --
Net operating loss carryforwards (1,704) (490) (306)
AMT credits (746) (837) (699)
ITC carryforwards (1,394) (1,371) (1,409)
Other (43) (3) (20)
------- ------ ------
Net deferred tax liability $8,011 $ 7,810 $7,066
======= ====== ======
The Company's investment tax credit carryforwards expire between the years
1996 and 2000.
Prior to August 1994, the Company owned interests in 504 gas wells which
qualified for Devonian Shale tax credits. These credits which approximate $1.00
per MMBtu of qualified gas produced in 1994 can be applied to reduce regular
income taxes payable only in the years the gas is produced. Effective
August 11, 1994, the Company formed a partnership with a large East Coast
financial institution structured such that the Institution will be allocated
substantially all of the Devonian Shale tax credits previously allocated to the
Company (see Note 3). No Devonian Shale tax credits were used by the Company in
years 1994, 1993 or 1992.
During 1992, the Company changed its method of computing income taxes to
reflect adoption of Statement 109 retroactive to January 1, 1990. The adoption
of Statement 109 resulted in the recognition of approximately $4.7 million of
net deferred tax liabilities in 1989. Statement 109 requires recognition of
deferred tax liabilities and assets for the expected future tax consequences of
events that have been included in the financial statements or tax returns.
Under this method, deferred tax liabilities and assets are determined based on
the differences between the financial statement and tax bases of assets and
liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse.
11 - STOCKHOLDERS RIGHTS PLAN
On November 30, 1994, the Board of Directors of the Company adopted a
Preferred Stock Purchase Rights Plan (the "Rights Plan"). Under the Rights
Plan, the Board declared a dividend of one preferred share purchase Right for
each outstanding share of Alamco Common Stock. In the event that any entity
acquires 15% or more of the outstanding shares of Common Stock of the Company,
the Rights will become exercisable subject to the terms of the Rights Plan and
will entitle each holder of a Right (other than the acquiring person or group)
under certain circumstances to purchase that number of shares of Alamco Common
Stock having a market value equal to two times the exercise price of the Right.
Rights were distributed to stockholders of record at the close of business
on December 12, 1994. The Rights will trade with the Company's Common Stock
until the Rights become exercisable and no separate certificates will be issued
until that time. The rights will expire on December 12, 2004. The Rights Plan
is designed to enable the Company and its Board to develop and preserve long-
term value for stockholders and to protect stockholders in the event an attempt
is made to acquire control of the Company through certain coercive or unfair
tactics or without a bona fide offer at fair value to all of the stockholders of
the Company.
12 - SALES CONCENTRATION
During 1994, gas sales to PAV, Hope and CNG accounted for 53.8 percent,
28.2 percent and 5.3 percent, respectively, of the Company's gas and oil sales.
In 1993 sales to Hope, CNG, Phoenix and Enron accounted for 25.2 percent, 24.1
percent, 14.4 percent and 14.2 percent, respectively, of the Company's gas and
oil sales. During 1992 a substantial portion of the Company's revenues was
derived from the sale of gas to CNG and gas marketers purchasing gas transported
on the Columbia pipeline system (see Part I, Item 1. "Business"). Sales to CNG
and the gas marketers approximated 51 percent and 17 percent in 1992.
13 - COMMITMENTS AND CONTINGENCIES
CNG Agreement. In November 1989, CNG made a $3,800,000 prepayment for
1,565,000 MMBtu of gas to be produced from the Company's Tallmansville
production area. CNG has the right, within certain specified limitations, to
take deliveries of this gas up to December 31, 1999. As of December 31, 1994,
CNG has taken delivery of 1,120,000 MMBtu of Tallmansville gas for which it has
prepaid. The Company recognizes its proportionate share of this deferred
revenue as volumes are recouped in accordance with the CNG Agreement.
14 - STOCK OPTIONS AND BENEFIT PLANS
Employee Stock Option Plans. Stock options have been granted to Company
employees through two stock option plans, the 1992 Employees' Stock Option Plan
(the "1992 Stock Option Plan") and the 1982 Employees' Stock Option Plan (the
"1982 Stock Option Plan").
The 1992 Stock Option Plan was established March 20, 1992, and provides for
the grant to officers and other key management employees of the Company of stock
options covering an aggregate of up to 100,000 shares of the Company's Common
Stock. Options may be designated as either non-qualified stock options or
incentive stock options, the latter of which must be exercised sequentially in
grant date order. The Compensation Committee of the Company's Board of
Directors administers the 1992 Stock Option Plan. The exercise price for each
option granted must be equal to the fair market value per share of the Company's
Common Stock on the date of the granting of the options (except when incentive
stock options are granted to any person who owns more than 10% of the total
combined voting power of all classes of stock of the Company, the exercise price
of each option will be at least 110% of the fair market value of the Common
Stock). At December 31, 1994, there were 35,500 shares available for future
grants.
The 1982 Stock Option Plan provided for the grant of stock options to
officers and other employees of the Company for up to 65,000 shares of the
Company's Common Stock. As of November 8, 1992, no additional options may be
granted from the 1982 Stock Option Plan. Options are designated as either non-
qualified stock options or incentive stock options. Information with respect to
the options granted under each plan follows:
1982 EMPLOYEES' 1992 EMPLOYEES'
STOCK OPTION PLAN STOCK OPTION PLAN
----------------- -----------------
Option Option
Number of Price Range Number of Price Range
Shares Per Share* Shares Per Share*
------ ---------- ------ ----------
Outstanding at January 1, 1992 49,000 $1.25--3.15 --
Granted 4,000 2.625 17,500 $4.875
Exercised -- --
Canceled 2,500 1.875-2.50 --
------ ------
Outstanding at December 31, 1992 50,500 1.25--3.15 17,500 4.875
------ ------
Granted -- 36,000 6.75
Exercised 17,100 1.25--2.50 --
Canceled -- --
------ ------
Outstanding at December 31, 1993 33,400 1.875-3.15 53,500 4.875-6.75
------ ------
Granted -- 18,500 6.75
Exercised -- --
Canceled 19,900 1.875-3.15 7,500 4.875
------ ------
Outstanding at December 31, 1994 13,500 1.875-3.15 64,500 4.875-6.75
------ ------
Exercisable at December 31, 1994 13,500 1.875-3.15 18,665 4.875-6.75
------ ------
------------------------
*Reflects the option price range applicable to only those installments included
in the total number of shares with respect to which the options are or were
exercisable.
Non-Qualified Stock Options. At December 31, 1994, non-qualified stock
options granted outside of any stockholder-approved plan totalled 370,100 shares
of Common Stock and were held by 10 employees. At December 31, 1994, 225,433
shares were exercisable with the remaining stock options becoming exercisable at
various dates between March 1995 and November 1996. The stock option exercise
prices range from $1.875 to $6.75 per share.
The 1992 Equity Compensation Plan for Outside Directors. The 1992 Equity
Compensation Plan for Outside Directors (the "1992 Outside Directors' Plan") was
established March 20, 1992 and provides for a maximum number of 75,000 shares of
Common Stock from the Company's authorized and unissued shares of Common Stock
and/or treasury shares to be available for issuance, subject to adjustments in
certain instances. Outside Directors receive 50 percent of their annual
retainer in the form of Common Stock and may elect to receive any or all of the
remaining cash balance of their retainer in the form of Common Stock.
Outside Directors' Stock Option Plan. The 1982 Outside Directors' Stock
Option Plan (the "Outside Directors' Plan") provided for the automatic grant of
options of the Company's Common Stock to non-employee Directors of the Company.
As of November 9, 1991, stock options may not be granted under the Outside
Directors' Plan. Information with respect to the Outside Directors' Plan is
presented below.
Number of Option Price Range
Shares Per Share*
-------- -----------------
Outstanding at January 1, 1992 10,400 $2.50--$50.00
------
Granted --
Exercised --
Canceled 2,400 2.50--50.00
------
Outstanding at December 31, 1992 8,000
------
Granted --
Exercised 2,800 2.50---5.60
Canceled 400 50.00
------
Outstanding at December 31, 1993 4,800 2.50--32.50
------
Granted --
Exercised --
Canceled 400 32.50
------
Outstanding at December 31, 1994 4,400 2.50-3.875
------
Exercisable at December 31, 1994 4,400 2.50-3.875
------
------------------------
*Reflects the option price range applicable to only those installments included
in the total number of shares with respect to which the options are or were
exercisable.
Employee Savings and Protection Plan. Effective October 1, 1987, the
Company instituted a 401(k) Plan titled the Alamco, Inc. Employee Savings and
Protection Plan. In addition to employee contributions, the Company contributed
cash and stock of approximately $110,000, $97,000 and $87,000 in 1994, 1993 and
1992, respectively.
15 - SUPPLEMENTAL INFORMATION RELATED TO GAS AND OIL PRODUCING ACTIVITIES
(Unaudited)
Costs incurred by the Company in gas and oil property acquisition,
exploration, and development are presented below:
Year Ended December 31,
---------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Costs (capitalized or expensed) for:
Property acquisition $ 6,740 $ 592 $ 806
Exploration -- -- --
Development 9,578 5,479 1,451
------ ------ ------
$16,318 $6,071 $2,257
------ ------ ------
Property acquisition costs include costs incurred to purchase, lease, or
otherwise acquire a property. Exploration costs include the costs of geological
and geophysical activity, dry holes, and drilling and equipping exploratory
wells. Development costs include costs incurred to gain access to and prepare
development well locations for drilling, to drill and equip development wells
and to provide facilities to extract, treat, gather, and store gas and oil, and
depreciation of support equipment used in development activities.
Aggregate capitalized costs for the Company related to gas and oil
exploration and production activities, with applicable accumulated depreciation,
depletion and amortization, are presented below:
1994 1993
----------------------
-----------------------
Accumu- Accumu-
lated lated
Cost DD&A Net Cost DD&A Net
---- ---- --- ---- ---- ---
(In thousands)
Proved developed
properties $71,782 $25,880 $45,902 $60,181 $27,325 $32,856
Pipelines and processing
equipment 1,734 562 1,172 2,014 525 1,489
Vehicles, machinery and
equipment consisting
principally of assets
used in gas and oil
producing activities 1,913 1,024 889 1,516 855 661
Buildings used in gas
and oil producing
activities 206 84 122 160 87 73
------- ------- ------- ------- ------- -------
$75,635 $27,550 $48,085 $63,871 $28,792 $35,079
------- ------- ------- ------- ------- -------
The results of operations for gas and oil producing activities are
presented below:
Year Ended December 31,
---------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Gas and oil sales revenues $11,993 $9,504 $8,855
------ ------ ------
Expenses:
Production 3,287 2,259 1,987
Depreciation, depletion and amortization 2,790 2,734 2,933
Exploration -- -- --
------ ------ ------
6,077 4,993 4,920
------ ------ ------
Results of operations for gas and oil
producing activities before provision
for income taxes 5,916 4,511 3,935
Provision for income tax 887 677 590
------ ------ ------
Results of operations for gas and oil
producing activities $5,029 $3,834 $3,345
------ ------ ------
Production expenses include those costs incurred to operate and maintain
productive wells and related equipment and include costs such as labor, repairs
and maintenance, materials, supplies, fuel consumed and other production taxes.
Depreciation, depletion and amortization expense includes those costs associated
with capitalized acquisition, exploration, and development costs including the
depreciation applicable to support equipment. Exploration expenses would
include the cost of exploratory dry holes, the geological and geophysical costs
associated with undeveloped properties and write-offs or amortization of lease
acquisition and other costs associated with undeveloped properties. The
provision for income taxes is computed considering the Company's status as an
alternative minimum tax payor.
The increase in the results of operations for gas and oil producing
activities between 1994 and 1993 resulted from higher gas and oil sales revenues
due primarily to the Company's successful 1994 acquisition and drilling
programs. The increase between 1993 and 1992 reflects higher 1993 gas and oil
sales revenues primarily due to the Company's successful 1993 capital investment
program.
Estimates of net proved reserves of gas and oil for the Company, all of
which are within the United States, are as follows:
Year Ended December 31,
--------------------------------------------------
1994 1993 1992
------------ ----------- -----------
MCF BBL MCF BBL MCF BBL
--- --- --- --- --- ---
(In thousands)
Proved reserves,
beginning of year 82,617 897 58,830 881 45,751 644
Extensions, discoveries
and other additions 13,529 435 23,727 142 6,400 85
Acquisitions 16,888 131 988 5 2,788 11
Revisions of previous
estimates 10,995 4 2,269 (94) 6,840 173
Production (4,404) (68) (3,197) (37) (2,949) (32)
------- ----- ------ --- ------ ---
Proved reserves,
end of year 119,625 1,399 82,617 897 58,830 881
------- ----- ------ --- ------ ---
Proved developed
reserves 85,654 1,164 56,560 605 43,502 524
------- ----- ------ --- ------ ---
These estimates are based primarily on the reports of independent petroleum
and geological engineers. Such reports are, by their very nature, inexact and
subject to changes and revisions. Proved reserves are the estimated quantities
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved reserves increased in 1994 due to the success of
the Company's acquisition and development drilling programs. Proved reserves
increased in 1993 because of the success of the 1993 drilling program. Reserves
were also added due to the inclusion of several additional drilling prospects on
existing company acreage and on acreage leased in 1993. The estimates include
only those amounts considered to be proved reserves and do not include
additional amounts that may result from new discoveries in the future. Proved
developed reserves are those reserves that are expected to be recovered through
existing wells with existing equipment and operating methods.
The estimated future net cash flow and the present value of the proved
reserves before taxes are presented below.
Proved Proved Total
Developed Undeveloped Proved
--------- ----------- ------
(In thousands)
Estimated future net cash
flow attributable to
production during
1995 $ 8,752 $(1,950) $ 6,802
1996 8,820 (914) 7,906
1997 8,166 203 8,369
1998 7,648 307 7,955
1999 and thereafter 93,391 43,080 136,471
________ _______ _______
Total 126,777 40,726 167,503
Present value of future
cash flow 58,349 9,862 68,211
Estimated future net cash flow represents future cash inflows generated by
the sale of the proved reserves less estimated production and future development
cost. For production from wells under fixed priced gas purchase contracts, the
gas price used is the contractual gas price for the term of the contract. The
gas price used is $2.20 per MCF and the oil price used is $15.13 per barrel.
Production costs are based on those in effect at December 31, 1994. The
estimated future net cash flow is based on a large number of estimates and
arbitrary assumptions. Reserve quantities cannot be measured with precision and
their estimation requires many judgmental determinations and frequent
revisions. No assurance of levels of gas and oil prices and costs can be given
nor can assurance be given that proved reserves will be developed within the
periods indicated. Present value is calculated by discounting estimated future
net revenue by 10 percent.
Summarized in the following table is information for the Company with
respect to the standardized measure of discounted future net cash flows relating
to proved oil and gas reserves. Estimated future net cash flow represents
future cash inflows generated by the sale of the proved reserves less estimated
production and future development cost. Future income tax expenses are computed
by applying the statutory rate and tax laws applicable to the future pre-tax net
cash flows for each year, less the tax basis of the properties, and giving
effect to permanent differences and net operating loss, investment tax credit,
and percentage depletion carryforwards which exist as of the end of each year.
In addition, 504 of the Company's gas wells qualify for Devonian Shale tax
credits under Section 29 of the Internal Revenue Code. These tax credits, which
in 1994, 1993 and 1992, are approximately $1.000, $.977, and $0.953,
respectively, per MMBtu, of qualified gas produced, must be used in the year in
which they originated and cannot be carried forward or back. During 1994, the
Company entered into a transaction which allocated substantially all of its
Devonian Shale tax credits to a third party (Note 3). Therefore, no Devonian
Shale tax credits were included in the 1994 tax calculation. For 1993 and 1992,
Devonian Shale tax credits expected to be generated from qualified wells were
reflected as reductions of future income tax expense on gas and oil producing
activities.
Year Ended December 31,
--------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Future cash inflows $275,745 $225,423 $151,876
Future production and development costs (108,241) (82,499) (62,520)
Future income tax expense (42,915) (33,874) (18,527)
-------- -------- --------
Future net cash flows 124,589 109,050 70,829
10% annual discount for estimated timing
of cash flows (77,184) (65,395) (39,673)
-------- -------- --------
Standardized measure of discounted
future net cash flows $ 47,405 $ 43,655 $ 31,156
-------- -------- --------
Approximately 93.4 percent of the Company's reserves are natural gas
reserves, the price for which has declined since year-end 1994. A recalculation
of the standardized measure of discounted future net cash flows using prices at
February 28, 1995 results in a decrease of $6.6 million to $40.8 million. The
following table summarizes the principal sources of change in the standardized
measure of discounted future cash flows:
Year Ended December 31,
--------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Sales and transfers of gas and oil
produced, net of production costs $(8,706) $(7,245) $(6,868)
Net changes in prices, production and
development costs, and quality
estimates 26,825 48,702 22,426
Addition of proved undeveloped reserves 16,039 17,590 6,206
Development costs incurred during the
period (9,578) (5,479) (1,451)
Accretion of discount 6,540 3,967 2,961
Net change in income taxes (9,041) (15,347) (4,978)
Other, including changes in the discount
other than due to accretion (18,329) (29,689) (13,023)
------- ------- -------
$ 3,750 $12,499 $ 5,273
------- ------- -------
It is necessary to emphasize that the data presented above should not be
viewed as necessarily representing the expected cash flow from, or current value
of, existing proved reserves since the computations are based on a large number
of estimates and arbitrary assumptions. Reserve quantities cannot be measured
with precision and their estimation requires many judgmental determinations and
frequent revisions. The required projection of production and related
expenditures over time requires further estimates with respect to pipeline
availability, rates of demand, and governmental control, among other factors.
Furthermore, actual prices and costs are likely to be substantially different
from the current prices and costs utilized in the computation of reported
amounts. In addition, the reported data are applicable only to gas and oil
reserves classified as proved; no amounts are included with respect to
additional reserves that may become proved in the future. Any analysis or
evaluation of the reported amounts should give specific recognition to the
computational methods utilized and the limitations inherent therein.
Item 9. Changes In and Disagreements With Accountants on Accounting and
---------------------------------------------------------------
Financial Disclosure
--------------------
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
--------------------------------------------------
Incorporated by reference from the Company's Proxy Statement to be filed
not later than 120 days after the Company's 1994 fiscal year end.
Item 11. Executive Compensation
----------------------
Incorporated by reference from the Company's Proxy Statement to be filed
not later than 120 days after the Company's 1994 fiscal year end. The Report of
the Compensation Committee of the Board of Directors is not incorporated by
reference herein.
Item 12. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
Incorporated by reference from the Company's Proxy Statement to be filed
not later than 120 days after the Company's 1994 fiscal year end.
Item 13. Certain Relationships and Related Transactions
----------------------------------------------
Incorporated by reference from the Company's Proxy Statement to be filed
not later than 120 days after the Company's 1994 fiscal year end.
PART IV
Item 14. Exhibits and Reports on Form 8-K
--------------------------------
(a) 1. and 2. Financial Statements
--------------------
Financial Statements included in this report:
Alamco, Inc., a Delaware corporation
Independent Auditor's Report
Consolidated Statement of Income for the
Years Ended December 31, 1994, 1993 and 1992
Consolidated Balance Sheet as of December 31, 1994 and 1993
Consolidated Statement of Changes in Stockholders' Equity for the
Years Ended December 31, 1994, 1993 and 1992
Consolidated Statement of Cash Flows for the
Years Ended December 31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements
Signatures
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf of the undersigned, thereunto duly authorized.
ALAMCO, INC.
(Registrant)
By: /s/ John L. Schwager
----------------------------------
John L. Schwager, President, Chief Executive
Officer, Principal Executive Officer and
Principal Financial Officer
Dated: March 24, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Signature and Title
---- -------------------
/s/ John L. Schwager
March 24, 1995 --------------------------
John L. Schwager
President, Chief Executive
Officer, Principal Executive Officer,
Principal Financial Officer and
Director
March 24, 1995 /s/ Robert S. Maust
--------------------------
Robert S. Maust
Director
March 24, 1995 /s/ James B. Gehr
--------------------------
James B. Gehr
Director
March 24, 1995 /s/ Richard R. Hoffman
--------------------------
Richard R. Hoffman
Executive Vice President, Chief
Operating Officer and Director
March 24, 1995 /s/ Stephen L. Barr
--------------------------
Stephen L. Barr
Director
March 24, 1995 /s/ James H. Weber
--------------------------
James H. Weber
Director
March 24, 1995 /s/ Thomas M. Levine
--------------------------
Thomas M. Levine
Director
March 24, 1995 /s/ Steven E. May
--------------------------
Vice President and
Controller (Principal Accounting
Officer)
INDEX TO EXHIBITS
The following exhibits to this report are filed herewith or, if marked with an
asterisk (*), are incorporated herein by reference:
Exhibit Prior Filing or Subsequential
No. Description Page No. Herein
3.1 Certificate of Incorporation, as amended Filed herewith
3.2 By-laws, as amended Filed herewith
4.1 Form of Rights Agreement dated as of November Exhibit 4.1 to Current Report on Form 8-K
30, 1994 between Alamco, Inc. and Chemical dated November 30, 1994* (1)
Bank
4.2 Certificate of Designations, Preferences and Exhibit 4.2 to Current Report on Form 8-K
Rights of Series A Preferred Stock of Alamco, dated November 30, 1994* (1)
Inc.
10.1 Gas Purchase Agreement between Phillips Exhibit 10.2 to Annual Report on Form 10-K,
Petroleum Company and Hope Gas, Inc. dated for Year Ended December 31, 1991* (1)
November 1, 1989
10.2 Letter Agreement between the Company and Hope Exhibit 10.27 to Amendment No. 1 to
Gas, Inc. dated May 19, 1992 Registration Statement on Form S-2 filed on
July 15, 1993 at Registration No. 33-64234*
10.3 Letter Agreement between the Company and Hope Filed herewith
Gas, Inc. dated November 10, 1994
10.4 Letter Agreement between the Company and Hope Filed herewith
Gas, Inc. dated November 23, 1994
10.5 Memorandum of Agreement dated August 19, 1992, Exhibit 10.28 to Amendment No. 1 to
between the Company, Phillips Petroleum Registration Statement on Form S-2 filed on
Company and Hope Gas, Inc. July 15, 1993 at Registration No. 33-64234*
10.6 Marketing Agreement between the Company and Exhibit 10.2 to Quarterly Report on Form 10-
Phoenix-Alamco Ventures, a West Virginia Q for Quarter ended September 30, 1993* (1)
limited liability company dated October 28,
1993
10.7 Letter Agreement between the Company and CNG Exhibit 10.8 to Annual Report on Form 10-K
Transmission Corporation dated March 23, 1993 for Year Ended December 31, 1993* (1)
10.8 Gas Purchase Agreement between the Company and Exhibit 10.2 to Quarterly Report on Form 10-
Access Energy Corporation dated April 1, 1993 Q, for Quarter Ended March 31, 1993*(1)
10.9 Stock Option Agreement dated December 13, 1990 Exhibit A to Exhibit 10.4 to Annual Report
between the Company and John L. Schwager on Form 10-K, for Year Ended December 31,
1990* (1) (2)
10.10 Amendment No. 1 dated April 15, 1992 to Stock Exhibit 4.5 to Registration Statement on
Option Agreement referred to in Exhibit 10.9 Form S-8 filed May 22, 1992 at Registration
No. 33-47194* (2)
10.11 Employment Agreement between the Company and Exhibit 10.9 to Annual Report on Form 10-K,
John L. Schwager dated December 17, 1992 for Year Ended December 31, 1992* (1) (2)
10.12 First Amendment to Employment Agreement dated Exhibit 10.11 to Annual Report on Form 10-K,
January 1, 1994 referred to in 10.11 for Year Ended December 31, 1993* (1) (2)
10.13 Stock Option Agreement dated November 11, 1993 Exhibit 4.3 to Registration Statement on
between the Company and John L. Schwager Form S-8 filed February 18, 1994 at
Registration No. 33-75500* (2)
10.14 Nonstatutory Stock Option Agreement dated Exhibit 4.3 to Registration Statement on
November 1, 1994 between the Company and John Form S-8 filed November 16, 1994 at
L. Schwager Registration No. 33-86452* (2)
10.15 Employment Agreement between the Company and Filed herewith (2)
John L. Schwager dated January 1, 1995
10.16 Employment Agreement between the Company and Exhibit 10.4 to Annual Report on Form 10-K,
Richard R. Hoffman dated July 1, 1991 for Year Ended December 31, 1991* (1) (2)
10.17 First Amendment to Employment Agreement dated Exhibit 10.16 to Annual Report on Form 10-K
January 1, 1994 referred to in 10.16 for Year Ended December 31, 1993* (1) (2)
10.18 Second Amendment to Employment Agreement dated Exhibit 10.17 to Annual Report on Form 10-K
January 1, 1994 referred to in 10.16 for Year Ended December 31, 1993* (1) (2)
10.19 Employment Agreement between the Company and Filed herewith (2)
Richard R. Hoffman dated January 1, 1995
10.20 Stock Option Agreement dated November 11, 1993 Exhibit 4.4 to Registration Statement on
between the Company and Richard R. Hoffman Form S-8 filed February 18, 1994 at
Registration No. 33-75500* (2)
10.21 Employment Agreement between the Company and Exhibit 10.5 to Annual Report on Form 10-K,
Steven E. May dated July 1, 1991 for Year Ended December 31, 1991* (1) (2)
10.22 Nonstatutory Stock Option Agreement dated Exhibit 4.4 to Registration Statement on
November 1, 1994 between Alamco, Inc. and Form S-8 filed November 16, 1994, at
Steven E. May Registration No. 33-86452* (2)
10.23 Employment Agreement between the Company and Filed herewith (2)
Bridget D. Furbee dated January 1, 1995
10.24 Restructuring Agreement with McJunkin Exhibit 28.03 to Report on Form 8-K dated
Corporation November 21, 1988* (1)
10.25 Credit Agreement between the Company and BANK Exhibit 10.15 to Annual Report on Form 10-K,
ONE, Texas, N.A. dated March 27, 1991 for Year Ended December 31, 1990, as amended
by the Form 8 dated April 3, 1991* (1)
10.26 First Amendment to Credit Agreement referred Exhibit 10.14 to Registration Statement on
to in 10.25 Form S-2 filed on June 10, 1993 at
Registration No. 33-64234*
10.27 Second Amendment to Credit Agreement referred Exhibit 19.1 to Quarterly Report on Form 10-
to in 10.25 Q for Quarter Ended March 31, 1993* (1)
10.28 Third Amendment to Credit Agreement referred Exhibit 10.1 to Quarterly Report on Form 10-
to in 10.25 Q for Quarter Ended September 30, 1993* (1)
10.29 Fourth Amendment to Credit Agreement among Exhibit 10.1 to Quarterly Report on Form 10-
Alamco, Inc., Alamco-Delaware, Inc. and BANK Q for Quarter Ended September 30, 1994* (1)
ONE, Texas, N.A.
10.30 Alamco, Inc. 1982 Employees' Stock Option Plan Exhibit 4.1 to Registration Statement on
Form S-8 filed October 9, 1987 at
Registration No. 33-17841* (2)
10.31 Alamco, Inc. 1982 Outside Directors' Stock Exhibit 4.2 to Registration Statement on
Option Plan Form S-8 filed October 9, 1987 at
Registration No. 33-17841* (2)
10.32 Alamco, Inc. 1992 Employees' Stock Option Plan Exhibit 4.3 to Registration Statement on
Form S-8 filed May 22, 1992 at Registration
No. 33-47193* (2)
10.33 Alamco, Inc. 1992 Equity Compensation Plan for Exhibit 4.3 to Registration Statement on
Outside Directors Form S-8 filed
May 22, 1992 at Registration No. 33-47195*
(2)
10.34 The First National Bank of Morgantown, N.A. Exhibit 10.19 to Annual Report on Form 10-K,
401(k) Trust Agreement for Year Ended December 31, 1992* (1) (2)
10.35 Alamco, Inc. Savings and Protection Plan, Exhibit 10.20 to Annual Report on Form 10-K,
effective as of October 1, 1987, as amended for Year Ended December 31, 1992* (1) (2)
and restated as of January 1, 1991
10.36 Amendment to the Alamco, Inc. Savings and Exhibit 10.21 to Annual Report on Form 10-K,
Protection Plan dated June 23, 1992 for Year Ended December 31, 1992* (1) (2)
10.37 Second Amendment to the Alamco, Inc. Savings Exhibit 10.32 to Annual Report on Form 10-K,
and Protection Plan effective January 1, 1993 for Year Ended December 31, 1993* (1) (2)
10.38 Third Amendment to the Alamco, Inc. Savings Filed herewith (2)
and Protection Plan effective January 1, 1993
10.39 Form of Nonstatutory Stock Option Agreement Exhibit 4.3 to Registration Statement on
dated March 8, 1991, as amended by Amendment Form S-8 filed May 22, 1992 at Registration
No. 1 dated April 15, 1992 (for options No. 33-47192* (2)
granted to Richard R. Hoffman and Steven E.
May)
10.40 Form of Indemnification Agreement (for Exhibit 10.25 to Registration Statement on
directors/officers to which John L. Schwager, Form S-2 filed on June 10, 1993 at
Richard R. Hoffman, Stephen L. Barr, James B. Registration No. 33-64234*
Gehr, Robert S. Maust and James H. Weber are
parties)
10.41 Form of Indemnification Agreement (for Exhibit 10.26 to Registration Statement on
officers only to which Steven E. May and Form S-2 filed on June 10, 1993 at
Bridget D. Furbee are parties) Registration No. 33-64234*
21 Subsidiaries of the Company:
HAWG Hauling & Disposal, Inc., a
West Virginia corporation
Alamco-Delaware, Inc., a
Delaware corporation
Phoenix-Alamco Ventures, a
West Virginia limited liability
24.1 Independent Auditors Consent dated March 3, Filed herewith
1995
24.2 Independent Petroleum Engineers Consent dated Filed herewith
March 8, 1995
27 Financial Data Schedule Filed herewith
Note (1): Commission File No. 1-8490
Note (2): Indicates management contracts and compensation plans.