CONFORMED COPY
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
- - ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
Commission File Number 0-7246
- - Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transaction period from
to
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
Nevada 95-2636730
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
103 East Main Street, Bridgeport, West Virginia 26330
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code (304) 842-3597
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Petroleum Development Corporation Common Stock, $.01 par value
(Title of class)
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 and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will 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. [ ]
As of March 15, 1996, 7,394,522 shares of the Registrant's Common Stock were
issued and outstanding, and the aggregate market value of such shares held by
non-affiliates of the Registrant on such date was $14,789,044 (based on the
last traded price of $2.00).
DOCUMENTS INCORPORATED BY REFERENCE
Document Form 10-K Part III
Proxy Items 11 and 12
<PAGE>
PART I
Item 1. Business
General
Petroleum Development Corporation is a Nevada corporation which was
formed in 1955 and commenced gas and oil operations in 1969. The Company
and its subsidiaries are engaged in the leasing of natural gas and oil
mineral rights, the development of these rights by drilling exploratory and
development gas and oil wells, the production and sale of gas and oil from
these wells, the operation of gas and oil wells for a fee, the marketing of
natural gas for itself and other producers, and the distribution of natural
gas to residential, commercial and industrial customers.
The Company typically develops its oil and gas properties in
conjunction with outside investors through partnerships, joint ventures, or
similar arrangements. These arrangements allow the Company to reduce the
risk of its development investments through increased diversification. In
addition the Company is compensated for its management of the development
process through payments for services rendered to the investor partners and
through an increased share in the revenues produced by the developed
properties.
Prior to 1984, virtually all of the outside investment capital was
contributed by unaffiliated partnerships and joint ventures. Beginning in
1984 the Company began sponsoring as the managing general partner drilling
partnerships which have invested their proceeds in Company development
projects. Currently a majority of the investment in Company development
programs originates from this source, however, a majority of the wells
operated by the Company continue to be associated with non-affiliated
investors.
In order to facilitate the marketing of natural gas from the wells
operated by PDC, the Company constructs and operates gas gathering systems
which interconnect to industrial customers, interstate pipeline company
facilities, and/or local distribution utilities. The Company receives
gathering fees for the use of these systems.
Gas and oil produced by wells are primarily marketed by the Company,
although gas brokers are occasionally used to assist with the sales.
The Company has an Ohio subsidiary, Paramount Natural Gas Company
(PNG), which commenced operations in October of 1992 as a regulated Ohio
distribution utility. The company acquired the pipeline assets of Paramount
Transmission Corporation (PTC), another Ohio subsidiary of the Company. PTC
focused its efforts on the acquisition and marketing of Ohio gas production.
Exploration and Development Activities
Prospect Generation and Leasing
PDC's staff of professional geologists is responsible for identifying
areas with potential for economic production of natural gas and oil. To
further this end the Company has collected and continues to collect logs,
core data, production information and other raw data available from state
and private agencies, other companies and individuals actively drilling in
the region. From this information the geologists develop models of the
subsurface structures and stratigraphy which are used to predict areas with
above average prospects for economic development.
On the basis of these models the geologists instruct the land
department to obtain available gas and oil leaseholds in these prospective
areas. These leases are then obtained, if possible, by the Company's land
department or contract landmen under the direction of the Company's land
manager. In most cases, these leases are obtained for a lease bonus and
annual rental payments changing to a 12.5% royalty on gross production
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revenue. In some instances additional overriding royalty payments may be
made to third parties or royalty owners with particularly attractive
prospects. As of December 31, 1995, the Company had a total leasehold
inventory of approximately 89,300 gross acres and 87,400 net acres. See
"Properties - Oil and Gas Leases".
Drilling Activities
When prospects have been identified and leased, the Company develops
these properties by drilling exploratory or development wells. Typically
the Company will act as driller-operator for these prospects, entering into
contracts with partnerships, including Company sponsored partnerships, and
other entities that are interested in exploration or development of the
prospects. The Company generally retains an interest in each well it
drills. This arrangement is beneficial to all parties, which benefit from
the diversification of risk. See "Financing of Exploration and Development
Activities".
The Company enters into a development agreement with each of its
investor partners, wherein the Company agrees to assign rights in the
property to be drilled to the partnership or other entity which thereby
becomes owner of a working interest in the property. The Company also
agrees to supervise and manage all drilling activities on the property and
to supply, either directly or through subcontractors, all necessary drilling
and related services and equipment. All work associated with drilling,
completing and connecting wells is performed under the direct supervision of
the Company. However, much of the work, including drilling, fracturing,
logging and pipeline construction is performed by subcontractors
specializing in those operations, as is common in the industry. Because the
prices paid to the Company by its investor partners are frequently fixed
before the wells are drilled, the Company is subject to risk that prices of
goods or services used in the development process could increase, rendering
its contracts with its investor partners less profitable or unprofitable.
In addition, problems encountered in the process can substantially increase
development costs, sometimes without recourse for the Company to recover its
costs from its partners. To minimize these risks, the Company seeks to lock
in its costs in advance of drilling and when possible at the same time it is
committing to its investor partners. A large part of the materials and
services used by the Company in the development process is acquired through
competitive bidding by approved vendors. The company also negotiates rates
and costs for services and supplies when conditions indicate that such an
approach is warranted.
The Company's development contracts with its investor partners are
negotiated with each partner and have historically taken many different
forms. Generally the agreements can be classified as "turnkey", in which a
specified amount is paid for drilling and another amount for completion;
"cost-plus", in which the Company is reimbursed for its actual cost of
drilling plus some additional amount for overhead and profit, or a "footage
based" rate whereby the Company receives drilling and completion payments
based on the depth of the well. As part of its compensation for its
services, the Company also generally receives some interest in the
production from the well in the form of an overriding royalty interest,
working interest or other proportionate share of revenue or profits.
Development Agreements with Partnerships sponsored by the Company
provide for a combination of several of the aforementioned payment options.
Basic drilling and completion operations are performed on a footage-based
rate, with leases and gathering pipelines being contributed at Company cost.
The Company also purchases a working interest in the properties.
The majority of the activity currently being pursued by the Company is
focused on the development of natural gas production in West Virginia,
eastern Ohio, and western Pennsylvania. During 1995 the Company was one of
the most active drilling companies in the state of West Virginia. Despite
the level of activity, the Company was able to maintain a high level of
environmental sensitivity and was selected for the fourth year in a row by
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the West Virginia Department of Environmental Protection for the state's top
award for the quality of the environmental and reclamation work in its
drilling activities. As a matter of corporate policy and commitment, the
Company attempts to minimize the adverse environmental impact of all its
operations.
The sale of natural gas requires that wells be connected by pipeline to
gas markets. Over the years the Company has developed extensive gathering
systems in its areas of operations. The Company also continues to construct
new trunklines as necessary to provide for the marketing of gas being
developed from new areas, and to enhance or maintain its existing systems.
The Company is paid a transportation fee for gas which is moved through
these pipeline systems. In many cases the Company has been able to receive
higher gas prices as a result of its ability to move gas to more attractive
markets through this pipeline system, to the benefit of both the Company and
its investor partners.
Acquisitions of Producing Properties
In addition to drilling new wells, the Company continues to pursue
opportunities to purchase existing producing wells from other producers and
interests in the wells it operates. Generally, outside interests purchased
include a majority interest in the wells and well operations.
In 1994 the Company purchased the Pond Fork Field with 57 operating gas
wells in Boone County, West Virginia. The wells added 1.9 Bcf of proved
producing reserves to the Company's 1994 total. In addition, the Company
purchased various royalty, overriding royalty or working interests from
investor partners and outside parties.
Production Operations
The Company currently operates approximately 850 wells in the
Appalachian Basin. On average, the Company has an approximate 25% ownership
interest in the wells it operates, with the balance belonging to investor
partners. The Company employs engineers, supervisors and welltenders who
are responsible for the day to day operation of the wells and pipeline
systems. Currently these wells produce an aggregate of about 15.8 million
cubic feet of gas per day, including the Company's share of about 3.7
million cubic feet per day. The Company's share of oil production is about
11,000 barrels per year. See "Properties - Production"
The Company is paid a monthly operating charge for each well it
operates. The rate is competitive with rates charged by other operators in
the area. The charge covers monthly operating and accounting costs,
insurance and other recurring costs. The Company may also receive
additional compensation for special non-recurring activities like reworks
and recompletions.
Oil and Gas Marketing
In West Virginia, the Company markets the gas from its own and its
investor partner interests as a part of the services provided under the
basic monthly operating charge. This gas is marketed to gas utilities,
pipelines and industrial and commercial customers, either directly through
the Company's gathering system, or utilizing transportation services
provided by regulated interstate pipeline companies. Generally the Company
negotiates its own contacts with customers. However, occasionally the
services of outside gas brokers or marketers are used.
In Ohio, the Company's subsidiary, Paramount Transmission Company
(PTC), purchases gas from local producers and gas brokers and sells gas to
industrial and commercial customers utilizing open access transportation
services provided by interstate pipelines and the Company's subsidiary,
Paramount Natural Gas Company (PNG), which is a regulated Ohio distribution
utility. PNG, which was formed in 1992, acquired the pipeline system
previously operated by PTC. The majority of PNG's throughput is
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attributable to gas transported for PTC and industrial customers, for a
transportation tariff, with the balance being sales to residential,
commercial and industrial customers.
The Company produces oil from wells in Tennessee, Ohio and West
Virginia. All of the oil produced is sold on a spot basis to local refinery
customers. See "Market for Oil and Gas".
Financing of Exploration and Development Activities
The Company conducts drilling activities for its own account and for
other investors. Prior to 1984, most of the Company's drilling funds came
from unaffiliated partnerships, companies and individuals. In 1984 the
Company began sponsoring private limited partnerships, and in 1989 the
Company began to register public drilling programs with the Securities and
Exchange Commission. Because of the Company's success with its own
partnerships, and declining sales nationwide of unaffiliated partnerships,
most drilling and development funds now come from partnerships in which the
Company serves as Managing General Partner. However, because wells produce
for a number of years, the Company continues to serve as operator for a
large number of unaffiliated parties.
The level of the Company's drilling and development activity is
dependent upon the amount of subscriptions in its public drilling
partnerships and investment from other partnerships or other joint venture
partners. Funds received pursuant to drilling contracts were $13,619,000 in
1995, $14,858,000 in 1994 and $15,872,400 in 1993. While funds were
received by the Company pursuant to drilling contracts in the years
indicated, the Company recognizes revenues from drilling operations on the
percentage of completion method as the wells are drilled, rather than when
funds are received.
The Company believes that investments in drilling activities, whether
through Company-sponsored partnerships or other sources, are influenced by
the favorable treatment which such investments enjoy under the Federal
income tax laws.
As a result of rules associated with the registration and sale of
public drilling programs, the operating margin on drilling activities
associated with the Company's current partnerships is less than it has
typically realized in activities with non-affiliated entities. Such
constraints are expected to continue in the future, and the Company expects
to realize less revenue and profit than it might realize from an equivalent
amount of activity for non-affiliated partnerships or other investors.
The Company invests in drilling activities through a 20% investment in
the partnerships it sponsors, and through direct working interest
investments. Certain conflict of interest provisions in joint venture and
partnership agreements limit the Company's ability to benefit
disproportionately from discoveries made through partnership activities.
Company investments in drilling activities are funded from internally
generated funds.
Market for Oil and Gas
The market for the Company's oil and gas depends upon a number of
factors including the availability of other domestic production, crude oil
and natural gas imports, the proximity of oil and gas pipelines and general
fluctuations in the supply and demand for oil and gas.
For nearly a decade the United States has experienced an oversupply of
natural gas. This oversupply was caused primarily by a decrease in market
demand and unusually warm weather conditions. Seasonal variations exist to
the extent that the demand for natural gas is somewhat lower during the
summer months than during the winter season.
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Generally, the Company has been and expects to continue to be able to
produce and market gas from its wells without curtailment by providing gas
to purchasers at competitive prices. Open access transportation on the
country's interstate pipeline system has greatly increased the range of
potential markets. Whenever feasible the Company allows for multiple market
possibilities from each of its gathering systems, while seeking the best
available market for its gas at any point in time.
Natural gas is sold by the Company under contracts ranging from month
to month spot to a 3 year term. Virtually all of the Company's contracts
have pricing tied to a market index, so the price of the gas moves to remain
competitive with other available gas supplies. As a result the revenue from
the sale of gas will suffer if market prices decline or benefit if they
increase. The provisions of the Company's gas contracts are believed by the
Company to be customary in the industry.
The Company's sales of natural gas are to various customers, of which
Hope Gas, Inc. accounted for 39.7% of the Company's revenues from oil and
gas sales (7.4% of total revenues) in 1995. Hope Gas, Inc. is a regulated
gas distribution company. In general, the prices it pays for gas, and the
producers from which it purchases gas, are influenced by the state and
federal agencies that regulate them. Natural gas sales to one industrial
customer accounted for 23.8% of oil and gas sales (4.4% of total revenues)
in 1995. No other single purchaser of the Company's natural gas accounted
for 10% or more of the Company's revenues from oil and gas sales in 1995.
Gas produced by the Company sold at December 31, 1995 at prices per Mcf
ranging from $1.71 to $4.16, depending upon the location, the date of the
sales contract and whether the gas was sold in interstate or intrastate
commerce. The weighted net average price of gas sold by the Company in 1995
was $1.75 per Mcf at the wellhead.
The Company is presently able to sell all the oil which it can produce
under existing sales contracts with petroleum refiners and marketers. The
Company's crude oil production is sold to purchasers at or near the
Company's wells under short-term purchase contracts at prices and in
accordance with arrangements which are customary in the oil industry. None
of the Company's oil production is sold under long-term contracts. The
Company does not refine any of its oil production.
No single purchaser of the Company's crude oil accounted for 10% or
more of the Company's revenues from oil and gas sales in 1995.
Oil produced by the Company sold at December 31, 1995 at prices ranging
from $14.75 to $17.50 per barrel, depending upon the location, quality of
oil and governmental price controls. In 1995, the weighted net average
price per barrel of oil sold by the Company was $15.80.
Governmental Regulation
The Company's business and the oil and gas industry in general are
highly regulated. The Company's services to investor partnerships include
taking the steps necessary to comply with applicable regulations.
Local Regulation. All of the Company's oil and gas production is from
properties in states in which drilling activities and well operations are
regulated by state authorities. These regulations, among other things,
require the Company to obtain permits to build roads and drill wells and
impose land restoration and minimum spacing requirements. See also
"Environmental Matters".
Paramount Natural Gas Company, which is an Ohio public utility, is
subject to regulation by the Public Utilities Commission of Ohio in
virtually all of its activities, including pricing and supply of services,
addition of and abandonment of service to customers, design and construction
of facilities, and safety issues.
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Federal Regulations. Pricing of gas sold by the Company is now fully
deregulated from Federal Price controls, and no proposals currently exist to
reimpose controls.
All of the interstate pipelines which the Company uses to transport gas
from wells to markets are regulated by the Federal Energy Regulatory
Commission (FERC). Over the past few years FERC has changed regulations on
these interstate pipeline systems, forcing them, among other things, to
offer open access transportation service, to unbundle the various services
they provide to allow customers to pay only for those services which they
use, and to change the structure of the rates which they charge. These
policy changes have not yet been fully determined or implemented, and it is
impossible at this time to predict the impact on the Company's business.
Also, the Company cannot determine to what extent future operations and
earnings of the Company may be affected by new legislation, new regulations
or changes in existing regulations.
Environmental Matters
The petroleum industry is subject to numerous federal and state
environmental statutes, regulations and other pollution controls. In
general, the Company is and will continue to be subject to present and
future environmental statutes and regulations, and in the future the cost of
its drilling and exploration and other activities may materially increase as
a result.
The Company's expenses relating to preserving the environment during
1995 were not significant in relation to operating costs and the Company
expects no material change in 1996. Environmental regulations have had no
materially adverse effect on the Company's petroleum operations to date, but
no assurance can be given that environmental regulations will not, in the
future, result in a curtailment of production or otherwise have a materially
adverse effect on the Company's operations or financial condition.
Competition
The Company competes with many other companies in the search for and
acquisition of oil and gas properties and leases for exploration and
development, and also competes with other companies in its activities as
drilling contractor. Many of these companies have substantially greater
financial, technical and other resources than the Company. Competition
among petroleum companies for favorable oil and gas prospects can be
expected to continue. It is anticipated that the cost of acquiring oil and
gas properties will increase appreciably. The Company is not a significant
factor in the oil and gas industry.
Likewise, the Company competes with a number of other companies which
offer interests in drilling partnerships with a wide range of investment
objectives and program structures. Competition for investment capital for
both public and private drilling programs is intense.
Other Industry Factors
Oil and gas drilling operations are subject to hazards such as fire,
explosion, blowouts, cratering and oil spills, each of which could result in
substantial damage to oil and gas wells, producing facilities, other
property and the environment or in personal injury. Although the Company
maintains liability insurance in an amount which it considers adequate, the
nature of these risks is such that liabilities could exceed policy limits in
which event the Company could incur significant costs that could have a
materially adverse effect upon its financial condition.
Employees
As of December 31, 1995, the Company had 65 employees. The Company's
employees are not covered by a collective bargaining agreement. The Company
considers relations with its employees to be excellent.
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Item 2. Properties
Drilling Activity
The following table summarizes the Company's drilling activity for the
past five years. There is no correlation between the number of productive
wells completed during any period and the aggregate reserves attributable to
those wells.
Exploratory Wells Drilled
Total Productive Gas Dry
Drilled Net Drilled Net Drilled Net
1991 - - - - - -
1992 - - - - - -
1993 3 .75 - - 3 .75
1994 - - - - - -
1995 - - - - - -
Total 3 .75 - - 3 .75
Development Wells Drilled
Total Productive Gas Dry
Drilled Net Drilled Net Drilled Net
1991 53 10.64 49 9.85 4 .79
1992 80 15.86 73 14.47 7 1.39
1993 56 10.00 49 8.75 7 1.25
1994 75 13.76 71 13.00 4 .76
1995 72 13.40 64 11.80 8 1.60
Total 336 63.66 306 57.87 30 5.79
The term "exploratory well" means a well drilled with the hope of
greatly extending the limits of an already developed pool or in search of an
undiscovered pool of oil or gas. A "development well" is one drilled to
extend the limits of an already developed pool, or within a proved area of
an oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive. A "dry well (hole)" is an exploratory or a development well
found to be incapable of producing either oil or gas in sufficient
quantities to justify completion as an oil or gas well.
A "drilled" well is a well for which the Company supervised drilling
activity or in which it has a working interest. A "net" well is deemed to
be held when the sum of the fractional working interests owned by the
Company in wells equals one.
Production
The following table shows the Company's net production in barrels
("Bbls") of crude oil and in thousands of cubic feet ("Mcf") of natural gas
and the costs and weighted average selling prices thereof, for the periods
indicated.
Year Ended December 31,
1995 1994 1993 1992 1991
Production (1):
Oil (Bbls) 11,000 11,000 10,000 16,000 12,205
Natural Gas (Mcf) 1,336,000 1,195,000 965,000 948,000 867,208
Equivalent
Barrels (2) 233,667 210,167 170,833 174,000 156,740
Average sales price
per equivalent
barrel (3) $10.86 $12.40 $12.88 $13.20 $12.55
Average production
cost (lifting cost) per
equivalent barrel(4) $ 3.16 $ 3.50 $ 3.40 $ 2.87 $ 3.26
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(1) Production as shown in the
table, which is net after the royalty interests of others, is determined by
multiplying the gross production volume of properties in which the Company
has an interest by the percentage of the leasehold or other property interest
owned by the Company.
(2) The ratio of energy content of oil and gas (six Mcf of gas equals
one barrel of oil) was used to obtain a conversion factor to convert natural
gas production into equivalent barrels of oil.
(3) The average sales price per barrel of oil sold by the Company was
$15.80 in 1995, $14.41 in 1994, $16.62 in 1993, $18.21 in 1992, and $17.52
in 1991, and the average sales price per Mcf of gas was $1.75 in 1995, $2.01
in 1994, $2.24 in 1993, $2.41 in 1992, and $2.16 in 1991.
(4) The average production cost per Mcf of gas based on the relative
energy content of six Mcf of gas equals one barrel of oil was $.53 in 1995,
$.58 in 1994, $.57 in 1993, $.48 in 1992, and $.54 in 1991. Production
costs represent oil and gas operating expenses as reflected in the financial
statements of the Company plus depreciation of support equipment and
facilities.
Summary of Productive Wells. The table below gives the number of the
Company's productive gross and net wells at December 31, 1995.
WELLS
Gas Oil
Location Gross Net Gross Net
Ohio 16 5.50 9 2.02
Tennessee 1 .57 60 21.80
Pennsylvania 26 3.51 - -
West Virginia 726 234.53 51 41.42
Total 769 244.11 120 65.24
Reserves
All of the Company's oil and gas reserves are located in the United
States.
"Proved reserves" are those quantities of crude oil and natural gas
which, upon analysis of geologic and engineering data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs on leases held by the Company under existing economic and
operating conditions. The Company's approximate net proved reserves were
estimated by the Company to be 91,000 barrels of oil and 24,660,000 Mcf of
gas at December 31, 1993 and 79,000 barrels of oil and 32,225,000 Mcf of gas
at December 31, 1994 and 140,000 barrels of oil and 33,829,000 Mcf of gas at
December 31, 1995.
"Proved developed reserves" are proved reserves which are expected to
be recovered through existing wells with existing equipment and operating
methods. The Company's approximate net proved developed reserves were
estimated by the Company to be 91,000 barrels of oil and 20,181,000 Mcf of
gas at December 31, 1993 and 79,000 barrels of oil and 27,746,000 Mcf of gas
at December 31, 1994 and 140,000 barrels of oil and 29,326,000 Mcf of gas at
December 31, 1995.
No major discovery or other favorable or adverse event which would
cause a significant change in estimated reserves is believed by the Company
to have occurred since December 31, 1995. Reserves cannot be measured
exactly as reserve estimates involve subjective judgment. The estimates
must be reviewed periodically and adjusted to reflect additional information
gained from reservoir performance, new geological and geophysical data and
economic changes.
The standardized measure of discounted future net cash flows
attributable to the Company's proved oil and gas reserves giving effect to
future estimated income tax expenses, was estimated by the Company to be
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$14,018,000 as of December 31, 1993, $14,445,000 as of December 31, 1994 and
$21,060,000 as of December 31, 1995. The values expressed are estimates
only, and may not reflect realizable values or fair market values of the oil
and gas ultimately extracted and recovered. The standardized measure of
discounted future net cash flows may not accurately reflect proceeds of
production to be received in the future from the sale of oil and gas
currently owned and does not necessarily reflect the actual costs that would
be incurred to acquire equivalent oil and gas reserves.
Substantially all of the Company's oil and gas reserves have been
mortgaged or pledged as security for bank loans to the Company. See Note 3
of Notes to Consolidated Financial Statements.
For additional information concerning oil and gas reserves and
activities, see Notes 15, 16 and 17 of Notes to Consolidated Financial
Statements.
The Company has not filed any estimates (on a consolidated basis) of
its oil and gas reserves with, nor were such estimates included in any
reports to, any Federal or foreign governmental agency other than the
Securities and Exchange Commission within the 12 months prior to the date of
this filing.
Oil and Gas Leases
The following table sets forth, as of December 31, 1995, the acres of
developed and undeveloped oil and gas properties in which the Company had an
interest, listed alphabetically by state.
<TABLE>
<S> <S> <S> <S> <S>
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
Ohio 1,200 800 1,400 1,400
Pennsylvania 100 100 4,500 4,500
Tennessee 5,400 5,400 - -
West Virginia 50,700 49,300 26,000 25,900
57,400 55,600 31,900 31,800
</TABLE>
"Undeveloped acreage" is that leasehold acreage on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether or not such
acreage contains proved reserves.
A "gross" acre is an acre in which the Company owns a working interest.
A "net" acre is deemed to exist when the sum of the fractional working
interests owned by the Company in gross acres equals one.
As is customary in the oil and gas industry, only a perfunctory title
examination is conducted at the time the properties believed to be suitable
for drilling operations are acquired by the Company. Prior to the
commencement of drilling operations, a title examination is conducted and
curative work is performed with respect to defects which the Company deems
to be significant. A title examination has been performed with respect to
substantially all of the Company's producing properties. The Company
believes that the title to such properties is good and indefeasible in
accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions stated in the opinion of counsel employed in the
various areas in which the Company conducts its exploration activities
which, in the Company's judgment, are not so material as to detract
substantially from the use of such property. Also, no single property
represents a material portion of the Company's holdings.
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The properties owned by the Company are subject to royalty, overriding
royalty and other outstanding interests customary in the industry. The
properties are also subject to burdens such as liens incident to operating
agreements, current taxes, development obligations under oil and gas leases,
farmout arrangements and other encumbrances, easements and restrictions.
The Company does not believe that any of these burdens will materially
interfere with the use of the properties.
Item 3. Legal Proceedings
Legal Proceedings
The Company is party to various legal actions in the normal course of
business which would not materially affect the Company's operations.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the
fourth quarter of the fiscal year covered by this report.
PART II
Item 5. Market for the Company's Common Stock and Related Security Holder
Matters
The common stock of the Company is traded in the over-the-counter
market under the symbol PETD. The following table sets forth, for the
periods indicated, the high and low bid quotations per share of the
Company's common stock in the over-the-counter market, as reported by the
National Quotation Bureau Incorporated. These quotations represent inter-
dealer prices without retail markups, markdowns, commissions or other
adjustments and may not represent actual transactions.
<TABLE> <S> <S> <S>
High Low
1994
First Quarter 2 9/16 1 9/16
Second Quarter 2 1/4 1 3/4
Third Quarter 2 1/16 1 5/8
Fourth Quarter 1 13/16 1 1/16
1995
First Quarter 1 3/8 7/8
Second Quarter 1 9/16 1 1/16
Third Quarter 1 3/8 1
Fourth Quarter 1 5/8 31/32
</TABLE>
As of December 31, 1995, there were approximately 2,341 record holders
of the Company's common stock.
The Company has not paid any dividends on its common stock and
currently intends to retain earnings for use in its business. Therefore, it
does not expect to declare cash dividends in the foreseeable future.
Further, the Company's Credit Agreement restricts the payment of dividends.
-11-
<PAGE>
Item 6. Selected Financial Data (1)
<TABLE>
<S> <S> <S> <S> <S> <S>
Year Ended December 31,
1995 1994 1993 1992 1991
Revenues
Oil and gas well
drilling
operations $13,941,000 $15,190,200 $12,073,500 $14,930,700 $11,070,200
Oil and gas sales 4,150,600 4,361,300 4,471,200 4,867,300 3,567,200
Well operations
income 3,750,900 3,730,300 3,843,100 2,935,900 2,694,500
Other income 504,000 524,400 97,600 432,600 507,000
Total $22,346,500 $23,806,200 $20,485,400 $23,166,500 $17,838,900
Costs and Expenses
(excluding
interest and
depreciation,
depletion and
amortization) $18,042,300 $20,559,500 $17,116,700 $18,826,000 $14,931,000
Interest Expense $ 319,700 $ 300,200 $ 55,500 $ 54,000 $ 56,400
Depreciation,
Depletion and
Amortization $ 2,152,100 $ 1,848,200 $ 1,717,400 $ 1,671,600 $1,505,500
Income before
extraordinary
item $ 1,481,500 $ 921,600 $ 1,320,800 $ 1,748,100 $ 869,700
Extraordinary item
net of income
taxes - - 269,000 - -
Net Income $ 1,481,500 $ 921,600 $ 1,589,800 $ 1,748,100 $ 869,700
Primary earnings
per common and
common equivalent
share
Income before
extraordinary item $ .13 $ .08 $ .11 $.16 $.08
Net income $ .13 $ .08 $ .14 $.16 $.08
Fully diluted
earnings per
common and common
equivalent share
Income before
extraordinary item $ .12 $ .08 $ .11 $.14 $.07
Net income $ .12 $ .08 $ .14 $.14 $.07
Average Common and
Common Equivalent
Shares Outstanding
During the Year 11,606,690 11,990,497 11,563,648 11,190,709 11,059,031
December 31,
1995 1994 1993 1992 1991
Total Assets $40,620,100 $38,325,300 $36,412,900 $34,631,500 $32,040,300
Working Capital $(1,519,700) $(1,613,700) $ 289,000 $ (590,100) $ (997,100)
Long-Term Debt,
excluding current
maturities $ 2,500,000 $ 3,100,000 $ 3,167,300 $ 3,968,900 $5,354,000
Stockholders'
Equity $19,920,900 $18,380,500 $17,235,700 $15,347,100 $13,264,000
</TABLE>
(1) See Consolidated Financial Statements elsewhere herein.
-12-
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
1995 Compared with 1994
Total revenue decreased 6.1% from $23,806,200 to $22,346,500 in 1995.
Revenues relating to the Company's drilling activities decreased $1,249,200
due to a slight decrease in drilling and completion activities in 1995
compared to 1994. Overall oil and gas sales decreased 4.8% in 1995 compared
to 1994 as a result of lower average gas sales prices offset by increased
volumes of natural gas sold.
Costs and expenses decreased 9.7% from $22,707,900 to $20,514,100
principally as a result of decreased drilling activity. Cost of oil and gas
well drilling operations decreased $2,345,700 as a result of the decrease in
drilling and completion activities referred to above. General and
administrative expenses decreased 11.0% as a result of a general company
wide cost cutting program. Depreciation, depletion, and amortization
increased 16.4% in 1995 compared to 1994 as a result of an increase in the
Company's investment in natural gas wells and increased production levels.
The foregoing resulted in income before income taxes of $1,832,400
compared to $1,098,300 in 1994. Net income for 1995 was $1,481,500 compared
to net income of $921,600 in 1994.
1994 Compared with 1993
Total revenue increased 16.2% from $20,485,400 to $23,806,200 in 1994.
Revenues relating to the Company's drilling activities increased $3,116,700
due to an increase in drilling and completion activities in 1994 compared to
1993. Overall oil and gas sales decreased slightly in 1994 compared to 1993
as a result of lower average gas sales prices offset for the most part by
increased volumes of gas sold. Other income increased by $426,800 in 1994
compared to 1993 as a result of management fee income from the Company's
1994 public drilling program.
Costs and expenses increased 20.2% from $18,889,600 to $22,707,900
principally as a result of increased drilling activity. Cost of oil and gas
well drilling operations increased $3,188,700 as a result of the increase in
drilling and completion activities referred to above. General and
administrative expenses increased 16.2% as a result of corporate public
relations costs incurred by the Company in 1994 along with generally higher
personnel costs. Depreciation, depletion, and amortization increased 7.6%
in 1994 compared to 1993 as a result of an increase in the Company's
investment in natural gas wells and increased production levels. Interest
expense increased to $300,200 in 1994 from $55,000 in 1993 principally due
to a loan agreement executed in November, 1993. Under a prior debt
restructuring arrangement all interest paid was treated as retirement of
principal.
The foregoing resulted in income before income taxes and extraordinary
item of $1,098,300 compared to $1,595,800 in 1993. Net income for 1994 was
$921,600 compared to net income of $1,589,800 in 1993.
Liquidity and Capital Resources
Sales volumes of natural gas continued to increase while the natural
gas prices fluctuated monthly and resulted in a lower average price than the
prior year. The Company's gas sales prices are subject to increase and
decrease based on various market sensitive indices. A major factor in the
variability of these indices is the seasonal variation of demand for natural
gas, which typically peaks during the winter months. The volumes of gas
sales are expected to continue to increase as a result of continued drilling
activities. There has been a dramatic increase in the price of natural gas
since December 31 which will have a positive effect on the Company's 1996
-13-
<PAGE>
liquidity. While prices cannot be predicted for the entire year it is
generally believed that the sales price of natural gas will be higher in
1996 than in 1995.
The Company closed its fourth drilling partnership of 1995 on December
30th and will drill approximately 45 wells during the first quarter of 1996.
Typically, the Company's drilling activity peaks during the winter months.
The Company has registered a 1996-1997 public drilling program consisting of
eight partnerships and has commenced sales of units in the first partnership
which is scheduled to close in May, 1996. The Company's public drilling
programs continue to receive wide market acceptance.
The Company continues to pursue capital investment opportunities in
producing gas properties along with its commitment to participate in its
sponsored gas drilling partnerships. Management believes that the Company
has adequate capital to meet its investing and operating requirements and
continues to pursue opportunities for operating improvements and cost
efficiencies.
Recently Issued Accounting Standards
In November, 1995, the FASB issued SFAS 123, Accounting for Stock-Based
Compensation. SFAS 123 establishes a fair value based approach for
accounting for stock-based compensation arrangements under which employees
receive shares of stock or other equity instruments of the employer, or the
employer otherwise incurs liabilities to its employees in amounts based on
the price of its stock. The Statement provides a choice of accounting
methods for transactions within the scope of APB Opinion No. 25 Accounting
for Stock Issued to Employees ("Opinion 25"). Companies may continue to
apply Opinion 25 in accounting for its stock-based employee compensation
arrangements. However, an entity that does so shall disclose pro forma net
income and earnings per share determined as if the fair value based method
had been applied in measuring compensation cost. SFAS 123 is effective for
financial statements for fiscal years beginning after December 15, 1995.
The Company currently plans to continue to value its stock options using the
guidance of Opinion 25 and to implement SFAS No. 123 by including the pro
forma disclosures in the notes to its consolidated financial statements for
the year ended December 31, 1996.
The Company adopted Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of", effective Janaury 1, 1995. This statement
requires that long-lived assets and certain identifiable intangibles be
reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. In performing
the review for recoverability, the entity should estimate the future cash
flows expected to result from the use of the asset and its eventual
disposition. If the sum of the expected future cash flows (undiscounted and
without interest charges) is less that the carrying amount of the asset, an
impairment loss is recognized. Measurement of an impairment loss for long-
lived assets and identifiable tangibles is based on the fair value of the
asset. The impact from the adoption of this accounting standard was not
significant.
PART III
Item 8. Financial Statements and Supplementary Data:
The response to this Item is set forth herein in a separate section of
this Report, beginning on Page F-1.
-14-
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item 10. Directors and Executive Officers of the Company
The executive officers and directors of the Company, their principal
occupations for the past five years and additional information are set forth
below:
<TABLE>
<S> <S> <S> <S>
Held Current
Name Age Positions and Offices Held Position Since
James N. Ryan 64 Chairman, Chief Executive
Officer and Director March, 1983
Steven R. Williams 45 President and Director March, 1983
Roger J. Morgan 68 Secretary and Director November, 1969
Vincent F. D'Annunzio 43 Director February, 1989
Dale G. Rettinger 51 Executive Vice President,
Treasurer and Director July, 1980
Jeffrey C. Swoveland 41 Director March, 1991
The term of directors is three years expiring in alternating years.
Executive officers have a term of one year and until a successor is elected.
Such elections are expected to occur at the Company's next annual meeting
presently scheduled for June, 1996. There is no family relationship between
any director or executive officer and any other director or executive
officer of the Company. There are no arrangements or understandings between
any director or officer and any other person pursuant to which such person
was selected as an officer.
The following is a brief account of the business experience during the
past five years of each director and executive officer:
James N. Ryan has served as President and Director of the Company from
1969 to 1983 and was elected Chairman and Chief Executive Officer in March,
1983.
Steven R. Williams has served as President and Director of the Company
since March 1983. Prior to joining the Company, Mr. Williams was employed
by Exxon until 1979 and attended Stanford Graduate School of Business,
graduating in 1981. He then worked with Texas Oil and Gas until July, 1982,
when he joined Exco Enterprises as Manager of Operations.
Roger J. Morgan has been a member of the law firm of Young, Morgan &
Cann, Clarksburg, West Virginia, for more than the past five years. Mr.
Morgan is not active in the day-to-day business of the Company, but his law
firm provides legal services to the Company.
Vincent F. D'Annunzio has for the past five years served as President
of Beverage Distributors, Inc. located in Clarksburg, West Virginia. Mr.
D'Annunzio is a director of CB&T Bank of Clarksburg, West Virginia.
Dale G. Rettinger has served as Vice President and Treasurer of the
Company since July, 1980. Mr. Rettinger was elected Director in 1985.
Previously, Mr. Rettinger was a partner with KMG Main Hurdman, Certified
Public Accountants, having served in that capacity since 1976.
Jeffrey C. Swoveland Director of Finance with Equitable Resources
since the fall of 1994. Mr. Swoveland previously served as Vice President
and a lending officer, with Mellon Bank, N.A. from July, 1989 to late 1994.
-15-
<PAGE>
Item 11. Management Remuneration and Transactions
There is incorporated by reference herein in response to this Item the
material under the heading "Election of Directors - Remuneration of Directors
and Officers", "Election of Directors - Stock Options" and "Election of
Directors - Interest of Management in Certain Transactions" in the Company's
definitive proxy statement for its 1996 annual meeting of stockholders filed
or to be filed with the Commission on or before April 30, 1996.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There is incorporated by reference herein in response to this Item, the
material under the heading "Election of Directors", in the Company's definitive
proxy statement for its 1996 annual meeting of stockholders filed or to be filed
with the Commission on or before April 30, 1996.
Item 13. Certain Relationships and Related Transactions
The response to this item is set forth herein in Note 9 in the Notes to
Consolidated Financial Statements.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements:
See Index to Financial Statements and Schedules on page F-1.
(2) Financial Statement Schedules:
See Index to Financial Statements and Schedules on page F-1.
Schedules and Financial Statements Omitted
All other financial statement schedules are omitted because
they are not required, inapplicable, or the information is
included in the Financial Statements or Notes thereto.
(3) Exhibits:
See Exhibits Index on page E-1.
(b) During the fourth quarter of 1995, the Company filed no report
on Form 8-K.
-16-
<PAGE>
CONFORMED COPY
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 by the undersigned, thereunto duly authorized.
PETROLEUM DEVELOPMENT CORPORATION
By /s/ James N. Ryan
James N. Ryan, Chairman
March 25, 1996
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:
Signature Title Date
/s/ James N. Ryan Chairman, Chief Executive March 25, 1996
James N. Ryan Officer and Director
/s/ Steven R. Williams President and Director March 25, 1996
Steven R. Williams
/s/ Dale G. Rettinger Executive Vice President, March 25, 1996
Dale G. Rettinger Treasurer and Director
(principal financial and
accounting officer)
/s/ Roger J. Morgan Secretary and Director March 25, 1996
Roger J. Morgan
-17-
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Index to Financial Statements and Financial Statement Schedules
1. Financial Statements:
Independent Auditors' Report F-2
Consolidated Balance Sheets - December 31, 1995 and 1994 F-3 & 4
Consolidated Statements of Income - Years Ended
December 31, 1995, 1994, and 1993 F-5
Consolidated Statements of Stockholders' Equity -
Years Ended December 31, 1995, 1994, and 1993 F-6
Consolidated Statements of Cash Flows -
Years Ended December 31, 1995, 1994, and 1993 F-7
Notes to Consolidated Financial Statements F-8 - 19
2. Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
and Reserves F-20
F-1
<PAGE>
Independent Auditors' Report
The Stockholders and Board of Directors
Petroleum Development Corporation:
We have audited the consolidated financial statements of Petroleum
Development Corporation and subsidiaries as listed in the accompanying
index. In connection with our audits of the consolidated financial
statements, we also have audited the financial statement schedule as listed
in the accompanying index. These consolidated financial statements and
financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
consolidated financial statements and financial statement schedule 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 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Petroleum Development Corporation and subsidiaries as of December 31, 1995
and 1994, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 1995, in conformity
with generally accepted accounting principles. Also in our opinion, the
related financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly,
in all material respects, the information set forth therein.
/s/KPMG PEAT MARWICK LLP
KPMG PEAT MARWICK LLP
Pittsburgh, Pennsylvania
March 15, 1996
F-2
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1995 and 1994
</TABLE>
<TABLE>
<S> <S> <S>
1995 1994
Assets
Current assets:
Cash and cash equivalents $10,053,600 8,906,800
Notes and accounts receivable (note 2) 2,016,600 1,975,400
Inventories 217,900 390,200
Prepaid expenses 868,800 850,600
Total current assets 13,156,900 12,123,000
Properties and equipment (notes 1 and 3):
Oil and gas properties (successful
efforts accounting method) 37,992,000 35,051,300
Pipelines 6,851,900 6,525,200
Transportation and other equipment 2,546,900 2,540,100
Land and buildings 849,200 843,300
48,240,000 44,959,900
Less accumulated depreciation,
depletion and amortization 21,127,100 19,204,400
27,112,900 25,755,500
Other assets (note 2) 350,300 446,800
$40,620,100 38,325,300
</TABLE>
(Continued)
F-3
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1995 and 1994
<TABLE>
<S> <S> <S>
1995 1994
Liabilities and Stockholders' Equity
Current liabilities:
Current maturities of long-term debt
(note 3) $ - 36,300
Accounts payable 2,119,100 2,484,700
Accrued taxes 155,100 44,900
Other accrued expenses 1,628,800 1,604,200
Advances for future drilling contracts 10,069,600 9,199,900
Funds held for future distribution 704,000 366,700
Total current liabilities 14,676,600 13,736,700
Long-term debt, excluding current maturities
(note 3) 2,500,000 3,100,000
Other liabilities 601,700 328,600
Deferred income taxes (note 4) 2,920,900 2,779,500
Commitments and contingencies (note 10)
Stockholders' equity (note 5):
Common stock, par value $.01 per share;
authorized 22,250,000 shares; issued and
outstanding 11,208,627 and 11,040,627 112,100 110,400
Common stock, Class A, par value $.01 per
share; authorized 2,750,000 shares; issued
and outstanding - none - -
Additional paid-in capital 7,019,800 6,873,600
Retained earnings 12,878,000 11,396,500
Unamortized stock award (89,000) -
Total stockholders' equity 19,920,900 18,380,500
$40,620,100 38,325,300
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Income
Years Ended December 31, 1995, 1994 and 1993
<TABLE>
<S> <S> <S> <S>
1995 1994 1993
Revenues:
Oil and gas well drilling operations $13,941,000 15,190,200 12,073,500
Oil and gas sales 4,150,600 4,361,300 4,471,200
Well operations and pipeline income 3,750,900 3,730,300 3,843,100
Other income 504,000 524,400 97,600
22,346,500 23,806,200 20,485,400
Costs and expenses:
Cost of oil and gas well drilling
operations 11,943,000 14,288,700 11,100,000
Oil and gas purchases and production
cost 4,138,700 4,067,000 4,119,700
General and administrative expenses 1,960,600 2,203,800 1,897,000
Depreciation, depletion
and amortization 2,152,100 1,848,200 1,717,400
Interest 319,700 300,200 55,500
20,514,100 22,707,900 18,889,600
Income before income
taxes and extraordinary item 1,832,400 1,098,300 1,595,800
Income taxes (note 4) 350,900 176,700 275,000
Income before extraordinary item 1,481,500 921,600 1,320,800
Extraordinary item (less applicable
income taxes of $89,600) (note 7) - - 269,000
Net income $ 1,481,500 921,600 1,589,800
Primary earnings per common
and common equivalent share
(note 8):
Income before extraordinary
item $.13 .08 .11
Net income $.13 .08 .14
Fully diluted earnings per
common and common equivalent
share (note 8):
Income before extraordinary
item $.12 .08 .11
Net income $.12 .08 .14
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 1995, 1994 and 1993
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Common stock
issued
Number Additional
of paid-in Retained Unamortized
shares Amount capital earnings Stock Award Total
Balance
December 31, 1992 10,027,903 $100,200 6,361,800 8,885,100 - 15,347,100
Issuance of common
stock:
Exercise of employee
stock options 142,960 1,500 39,200 - - 40,700
Exercise of warrants 1,993,073 19,900 1,980,100 - - 2,000,000
Purchase of treasury
stock for cancellation
or reissuance (1,424,323) (14,200) (1,877,700) - - (1,891,900)
Reissuance of Treasury
stock to profit
sharing plan (note 6) 92,308 900 149,100 - - 150,000
Net income - - - 1,589,800 - 1,589,800
Balance,
December 31, 1993 10,831,921 108,300 6,652,500 10,474,900 - 17,235,700
Issuance of common
stock:
Purchase of properties 55,000 500 109,500 - - 110,000
Exercise of employee
stock options 153,706 1,600 111,600 - - 113,200
Net income 921,600 - 921,600
Balance,
December 31, 1994 11,040,627 $110,400 6,873,600 11,396,500 - 18,380,500
Issuance of common
stock:
Exercise of employee
stock options 78,000 800 45,800 - 46,600
Stock award 90,000 900 100,400 - (101,300) -
Amortization of
stock award - - - - 12,300 12,300
Net income - - - 1,481,500 - 1,481,500
Balance,
December 31, 1995 11,208,627 $112,100 7,019,800 12,878,000 (89,000) 19,920,900
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 1995, 1994 and 1993
<TABLE>
<S> <S> <S> <S>
1995 1994 1993
Cash flows from operating activities:
Net income $1,481,500 921,600 1,589,800
Adjustment to net income to reconcile
to cash provided by operating activities:
Extraordinary gain on debt restructuring - - (358,600)
Deferred income taxes 112,600 97,400 166,700
Depreciation, depletion and amortization 2,152,100 1,848,200 1,717,400
Disposition of leasehold acreage 201,300 173,600 97,400
Employee compensation paid in stock 12,300 108,200 -
Profit sharing plan contribution - - 150,000
(Increase) decrease in notes and accounts
receivable (41,200) 39,400 128,700
Decrease (increase) in inventories 172,300 (38,100) (90,400)
Decrease (increase) in prepaid expenses 10,600 (211,000) (100,700)
Decrease in other assets 65,800 65,100 15,000
Increase (decrease) in accounts payable
and accrued expenses 42,300 92,200 (1,397,700)
Increase in advances for future
drilling contracts 869,700 1,071,900 3,019,300
Increase (decrease) in funds held for
future distribution 337,300 (474,300) 1,700
Other (95,800) 18,300 8,600
Total adjustments 3,839,300 2,790,900 3,357,400
Net cash provided by operating
activities 5,320,800 3,712,500 4,947,200
Cash flows from investing activities:
Capital expenditures (3,910,400) (5,606,500) (2,630,200)
Proceeds from sale of leases 289,400 282,100 359,600
Proceeds from sale of fixed assets 36,700 34,200 64,400
Net cash used in investing
activities (3,584,300) (5,290,200) (2,206,200)
Cash flows from financing activities:
Proceeds from debt - 800,000 3,399,000
Proceeds from issuance of stock 46,600 5,000 40,700
Purchase of treasury stock - - (1,892,000)
Retirement of debt (636,300) (899,300) (2,952,700)
Net cash used in financing
activities (589,700) (94,300) (1,405,000)
Net increase (decrease) in cash
and cash equivalents 1,146,800 (1,672,000) 1,336,000
Cash and cash equivalents,
beginning of year 8,906,800 10,578,800 9,242,800
Cash and cash equivalents, end of year $10,053,600 8,906,800 10,578,800
</TABLE>
See accompanying notes to consolidated financial statements.
F-7
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Years Ended December 31, 1995, 1994 and 1993
(1) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts
of Petroleum Development Corporation and its wholly owned
subsidiaries. All material intercompany accounts and transactions
have been eliminated in consolidation. The Company accounts for its
investment in limited partnerships under the proportionate
consolidation method. Under this method, the Company's balance
sheets and operating statements include its prorata share of assets
and liabilities and revenues and expenses, respectively, of the
limited partnerships in which it participates.
The Company is principally involved in oil and gas exploration,
production and development and related property management which is
considered one business segment for financial reporting purposes.
The Company grants credit to purchasers of oil and gas and the owners
of managed properties, substantially all of whom are located in the
Appalachian Basin area of West Virginia, Tennessee, Pennsylvania and
Ohio.
Cash Equivalents
For purposes of the statement of cash flows, the Company considers all
highly liquid debt instruments with original maturities of three
months or less to be cash equivalents.
Inventories
Inventories of well equipment, parts and supplies are valued at the
lower of average cost or market.
Oil and Gas Properties
Exploration and development costs are accounted for by the successful
efforts method.
The Company assesses impairment of capitalized costs of proved oil and
gas properties by comparing net capitalized costs to undiscounted
future net cash flows on a field-by-field basis using expected
prices. Prices utilized for measurement purposes and expected costs
are held constant. If net capitalized costs exceed undiscounted
future net cash flow, the measurement of impairment is based on
estimated fair value.
Property acquisition costs are capitalized when incurred. Geological
and geophysical costs and delay rentals are expensed as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether the wells have discovered economically
producible reserves. If reserves are not discovered, such costs are
expensed as dry holes. Development costs, including equipment and
intangible drilling costs related to both producing wells and
developmental dry holes, are capitalized.
Unproved properties are assessed on a property-by-property basis and
properties considered to be impaired are charged to expense when such
impairment is deemed to have occurred.
(Continued)
F-8
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Costs of proved properties, including leasehold acquisition,
exploration and development costs and equipment, are depreciated or
depleted by the unit-of-production method based on estimated proved
developed oil and gas reserves.
Upon sale or retirement of complete units of depreciable or depletable
property, the net cost thereof, less proceeds or salvage value, is
credited or charged to income. Upon retirement of a partial unit of
property, the cost thereof is charged to accumulated depreciation and
depletion.
Based on the Company's experience, management believes site
restoration, dismantlement and abandonment costs to be immaterial in
relation to operating costs. These costs are being expensed when
incurred.
Transportation Equipment, Pipelines and Other Equipment
Transportation equipment, pipelines and other equipment are carried at
cost. Depreciation is provided principally on the straight-line
method over useful lives of 3 to 17 years.
Maintenance and repairs are charged to expense as incurred. Major
renewals and betterments are capitalized. Upon the sale or other
disposition of assets, the cost and related accumulated depreciation,
depletion and amortization are removed from the accounts, the
proceeds applied thereto and any resulting gain or loss is reflected
in income.
Buildings
Buildings are carried at cost and depreciated on the straight-line
method over estimated useful lives of 30 years.
Retirement Plans
The Company has a 401-K contributory retirement plan (401-K Plan)
covering full-time employees. The Company provides a discretionary
matching of employee contributions to the plan.
The Company also has a profit sharing plan covering full-time
employees. The Company's contributions to this plan are
discretionary.
During 1994, the Company established a deferred compensation
arrangement covering executive officers of the Company as a
supplemental retirement benefit.
During 1995, the Company established split-dollar life insurance
arrangements with certain executive officers. Under these
arrangements, advances are made to these officers equal to the
premiums due. The advances are collateralized by the cash surrender
value of the policies. The Company records as other assets its share
of the cash surrender value of the policies.
Revenue Recognition
Oil and gas wells are drilled primarily on a contract basis. The
Company follows the percentage-of-completion method of income
recognition for drilling operations in progress.
Well operations income consists of operation charges for well upkeep,
maintenance and operating lease income on tangible well equipment.
(Continued)
F-9<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income
in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date.
Use of Estimates
Management of the Company has made a number of estimates and
assumptions relating to the reporting of assets and liabilities and
revenues and expenses and the disclosure of contingent assets and
liabilities to prepare these financial statements in conformity with
generally accepted accounting principles. Actual results could
differ from those estimates. Estimates which are particularly
significant to the consolidated financial statements include
estimates of oil and gas reserves and future undiscounted cash flows
from oil and gas properties.
New Pronouncement
The Company adopted Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of", effective Janaury 1, 1995.
This statement requires that long-lived assets and certain
identifiable intangibles be reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. In performing the review for
recoverability, the entity should estimate the future cash flows
expected to result from the use of the asset and its eventual
disposition. If the sum of the expected future cash flows
(undiscounted and without interest charges) is less that the carrying
amount of the asset, an impairment loss is recognized. Measurement
of an impairment loss for long-lived assets and identifiable
tangibles is based on the fair value of the asset. The impact from
the adoption of this accounting standard was not significant.
(2) Notes and Accounts Receivable
The Company holds notes receivable from officers, directors and
employees with interest from 8% to 12% as of December 31, 1995 and
1994, in the amounts of $33,300 and $41,900, respectively, of which
$200 and $8,700 are current.
Included in other assets are noncurrent notes and accounts receivable
as of December 31, 1995 and 1994, in the amounts of $168,400 and
$368,000, net of the allowance for doubtful accounts of $368,800 and
$254,000, respectively.
The allowance for doubtful current accounts receivable as of December
31, 1995 and 1994 was $20,200 and $175,400, respectively.
(3) Long-Term Debt
Long-term debt at December 31, 1995 and 1994, consisted of the
following:
(Continued)
F-10
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
<TABLE>
<S> <S> <S>
1995 1994
Note payable to bank, under a credit
agreement, due in November 1998 with
interest payable monthly at prime
(8.5% at December 31, 1995) plus 1/2% $2,500,000 3,100,000
Mortgage note payable to bank with interest
at prime (8.5% at December 31, 1994) plus
1-1/2%, due in monthly installments of $2,700,
secured by real property - 28,200
Installment notes payable with various interest
rates ranging to 8.5%, payable in monthly
installments of approximately $1,300 plus
interest through 1995, secured by equipment - 8,100
2,500,000 3,136,300
Current maturities - 36,300
Long-term debt, excluding current maturities $2,500,000 3,100,000
</TABLE>
On November 17, 1993, the Company entered into a Credit Agreement
providing a borrowing base of $7,500,000 subject to adequate natural gas
reserve levels. During 1995 an amendment to the Credit Agreement was
executed which reduced the interest rate and extended the Agreement
until 1998.
The Credit Agreement requires no principal payments until it matures in
November, 1998. The Company has activated $5,000,000 of the credit line
and is required to pay an annual commitment fee of 1/2% on the unused
portion of the activated credit facility. The loan is secured by
substantially all properties and equipment of the Company. The Credit
Agreement requires the existence of satisfactory levels of natural gas
reserves, and additionally provides, among other things, for the
maintenance of certain working capital and tangible net worth ratios
along with limitations on dividend payments.
(4) Income Taxes
The Company's provision for income taxes consisted of the following:
<TABLE>
<S> <S> <S> <S>
1995 1994 1993
Current:
Federal $ 128,400 66,600 111,800
State 109,900 12,700 86,100
Total current
income taxes 238,300 79,300 197,900
Deferred:
Federal 87,300 75,500 129,200
State 25,300 21,900 37,500
Total deferred
income taxes 112,600 97,400 166,700
Total taxes $ 350,900 176,700 364,600
Income tax expense is included in the financial statements as follows:
Operations $ 350,900 176,700 275,000
Extraordinary item - - 89,600
$ 350,900 176,700 364,600
</TABLE>
(Continued)
F-11
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Income tax expense attributable to income from continuing operations was
$350,900, $176,700 and $275,000 for the years ended December 31, 1995,
1994 and 1993, respectively, and differed from the amounts computed by
applying the U.S. federal income tax rate of 34 percent to pretax
income from continuing operations as a result of the following:
<TABLE>
<S> <S> <S> <S>
1995 1994 1993
Amount Amount Amount
Computed "expected" tax $ 623,000 373,400 542,600
State income tax 108,800 71,200 95,000
Percentage depletion (155,900) (136,000) (240,200)
Nonconventional source
fuel credit (127,300) (18,000) (147,000)
Adjustment to oil and
gas properties - (132,700) -
Adjustments to valuation
allowance (100,700)
Other 3,000 18,800 24,600
$ 350,900 176,700 275,000
</TABLE>
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at December
31, 1995, and 1994 are presented below:
<TABLE>
<S> <S> <S>
1995 1994
Deferred tax assets:
Drilling notes, principally
due to allowance for
doubtful accounts $ 671,300 839,700
Investment tax credit
carryforwards 233,300 342,100
Alternative minimum tax
credit carryforwards
(Section 29) 909,400 698,600
Other 440,600 340,200
Total gross deferred tax assets 2,254,600 2,220,600
Less valuation allowance (941,300) (842,700)
Deferred tax assets 1,313,300 1,377,900
Less current deferred tax assets
(included in prepaid expenses) (386,200) (275,000)
Net non-current deferred
tax assets 927,100 1,102,900
Deferred tax liabilities:
Plant and equipment,
principally due to
differences in depreciation
and amortization (3,848,000) (3,882,400)
Total gross deferred
tax liabilities (3,848,000) (3,882,400)
Net deferred tax liability $(2,920,900) (2,779,500)
</TABLE>
The Company has evaluated each deferred tax asset and has provided a
valuation allowance where it is believed more likely than not that some
portion of the asset will not be realized.
The valuation allowance for deferred tax assets as of January 1, 1993 was
$698,000. The net changes in the total valuation allowance for the years
ended December 31, 1995, 1994, and 1993 were increases of $98,600, $45,000
and $99,700, respectively.
At December 31, 1995, the Company has investment tax credit carryforwards
for federal income tax purposes of approximately $233,300 which are
(Continued)
F-12
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
available to reduce future federal income taxes, if any, through 2000. In
addition, the Company has alternative minimum tax credit carryforwards
(Section 29) of approximately $909,400 which are available to reduce future
federal regular income taxes, if any, over an indefinite period.
(5) Common Stock
Options
Options amounting to 210,000 and 128,500 shares were granted during 1995
and 1993, respectively to certain employees and directors under the
Company's Stock Option Plans. These options were granted at market value
as of the date of grant and the outstanding options expire from 1995 to
2002.
<TABLE>
<S> <S> <S> <S>
Number
of Shares Average Range
Outstanding December 31, 1992 2,398,750 $0.64 .38 - 1.00
Granted 128,500 $1.63 1.63 - 1.63
Exercised (156,000) $0.42 .38 - .65
Expired (189,000) $0.64 .55 - .72
Outstanding December 31, 1993 2,182,250 $0.71 .38 - 1.63
Granted - $ - -
Exercised (226,250) $0.50 .44 - .69
Expired - $ - -
Outstanding December 31, 1994 1,956,000 $0.77 .38 - 1.63
Granted 210,000 $1.13 .94 - .94
Exercised (78,000) $0.60 .56 - .72
Expired (235,350) $0.68 .38 - 1.63
Outstanding December 31, 1995 1,852,650 $0.91 .50 - 1.63
</TABLE>
Stock Redemption Agreement
The Company has stock redemption agreements with three officers of the
Company. The agreements require the Company to maintain life insurance
on each executive in the amount of $1,000,000. The agreements provide
that the Company shall utilize the proceeds from such insurance to
purchase from such executives' estates or heirs, at their option,
shares of the Company's stock. The purchase price for the outstanding
common stock is to be based upon the average closing asked price for
the Company's stock as quoted by NASDAQ during a specified period. The
Company is not required to purchase any shares in excess of the amount
provided for by such insurance.
(6) Employee Benefit Plans
The Company made 401-K Plan contributions of $71,800, $68,700 and $63,200
for 1995, 1994 and 1993, respectively.
The Company has a profit sharing plan (the Plan) covering full-time
employees. The Company contributed $28,500 to the plan in cash during
1995 and 92,308 shares of the Company's stock (treasury shares) with a
market value of $150,000 plus $5,000 in cash in 1993. The Company did
not make a contribution to the Plan during 1994.
During 1995 and 1994, the Company expensed and established a liability
for $90,000 each year under a deferred compensation arrangement with
the executive officers of the Company.
(Continued)
F-13<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
In 1995, a total of 90,000 restricted shares of the Company's common
stock were granted to certain employees and available to them upon
retirement. The market value of shares awarded was $101,300. This
amount was recorded as unamortized stock award and is shown as a
separate component of stockholders' equity. The unamortized stock
award is being amortized to expense over the employees' expected years
to retirement and amounted to $12,300 in 1995.
At December 31, 1995, the Company has recorded as other assets $60,000 as
its share of the cash surrender value of the life insurance pledged as
collateral for the payment of premiums on split-dollar life insurance
policies owned by certain executive officers.
(7) Extraordinary Item
As discussed in Note 3, the Company executed a new credit agreement on
November 17, 1993. As a result of the early retirement of the
outstanding obligation under the previously existing credit
arrangement, the Company wrote off the remaining liability for future
interest amounting to $358,600 established in connection with a debt
restructuring in 1990. Consistent with the accounting for the 1990
restructuring, the write-off of $358,600 before applicable income taxes
of $89,600 has been accounted for as an extraordinary item.
(8) Earnings Per Share
Earnings per share is based on the weighted average number of common and
common equivalent shares outstanding of 11,606,690 for 1995, 11,990,497
for 1994 and 11,563,648 for 1993.
Fully diluted earnings per share is based upon the weighted average
number of common and common equivalent shares outstanding of
11,937,130, 11,990,497 and 11,563,648, for 1995, 1994 and 1993,
respectively. Stock warrants and options are considered to be common
stock equivalents and, to the extent appropriate, have been added to
the weighted average common shares outstanding.
(9) Transactions with Affiliates
As part of its duties as well operator, the Company received $11,397,000
in 1995, $12,834,300 in 1994 and $11,894,200 in 1993 representing
proceeds from the sale of oil and gas and made distributions to
investor groups according to their working interests in the related oil
and gas properties.
(10) Commitments and Contingencies
The nature of the independent oil and gas industry involves a dependence
on outside investor drilling capital and involves a concentration of
gas sales to a few customers. The Company sells natural gas to various
public utilities and industrial customers, none of which accounted for
more than 10% of total revenues.
The Company is not party to any legal action that would materially affect
the Company's operations or financial statements.
(11) Supplemental Disclosure of Cash Flows
The Company paid $319,700, $300,200 and $55,000 for interest in 1995,
1994 and 1993, respectively. The Company paid income taxes in 1994 and
1993 in the amounts of $312,500 and $261,000, respectively.
(Continued)
F-14
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(12) Noncash Financing and Investing Activities
In 1994 the Company issued 55,000 shares of common stock for the purchase
of producing properties. Also in 1994, employees exercised stock
options for 143,706 shares of common stock and surrendered options for
72,544 common shares in lieu of cash payments in connection with the
options exercised. This resulted in compensation expense of $108,200.
In 1993 warrant holders exercised warrants for 1,993,073 shares of common
stock and surrendered warrants for 756,927 common shares, in lieu of
cash payments in connection with the warrants exercised.
(13) Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
Costs incurred by the Company in oil and gas property acquisition,
exploration and development are presented below:
<TABLE>
<S> <S> <S> <S>
Years Ended December 31,
1995 1994 1993
Property acquisition cost:
Proved undeveloped properties $ 167,800 426,200 267,500
Producing properties 218,500 1,332,100 59,700
Exploration costs - - 97,800
Development costs 2,977,700 2,260,800 1,412,000
$3,364,000 4,019,100 1,837,000
</TABLE>
Property acquisition costs include costs incurred to purchase, lease or
otherwise acquire a property. Exploration costs include the cost 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 oil and gas.
(14) Oil and Gas Capitalized Costs
Aggregate capitalized costs for the Company related to oil and gas
exploration and production activities with applicable accumulated
depreciation, depletion and amortization are presented below:
<TABLE>
<S> <S> <S>
December 31,
1995 1994
Proved properties:
Intangible drilling costs $16,582,000 16,363,400
Tangible well equipment 16,831,800 13,854,200
Well equipment leased to others 4,063,600 4,063,600
Undeveloped properties 514,600 770,100
37,992,000 35,051,300
Less accumulated depreciation,
depletion and amortization 14,529,900 13,021,600
$23,462,100 22,029,700
</TABLE>
(Continued)
F-15
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(15) Results of Operations for Oil and Gas Producing Activities
The results of operations for oil and gas producing activities
(excluding marketing) are presented below:
<TABLE>
<S> <S> <S> <S>
Years Ended December 31,
1995 1994 1993
Revenue:
Oil and gas sales $2,534,000 2,610,100 2,201,800
Expenses:
Production costs 596,000 734,700 580,700
Depreciation, depletion
and amortization 1,000,700 922,300 981,900
1,596,700 1,657,000 1,562,600
Results of operations for
oil and gas producing
activities before provision
for income taxes 937,300 953,100 639,200
Provision for income taxes 137,800 146,600 75,100
Results of operations for
oil and gas producing
activities (excluding
corporate overhead
and interest costs) $ 799,500 806,500 564,100
</TABLE>
Production costs include those costs incurred to operate and maintain
productive wells and related equipment, including such costs as
labor, repairs, maintenance, materials, supplies, fuel consumed,
insurance and other production taxes. In addition, production costs
include administrative expenses and depreciation applicable to
support equipment associated with these activities.
Depreciation, depletion and amortization expense includes those costs
associated with capitalized acquisition, exploration and development
costs, but does not include the depreciation applicable to support
equipment.
The provision for income taxes is computed at the statutory federal
income tax rate and is reduced to the extent of permanent
differences, such as investment tax credits and statutory depletion
allowed for income tax purposes.
(16) Net Proved Oil and Gas Reserves (Unaudited)
The proved reserves of oil and gas of the Company as estimated by the
Company, all of which are located within the United States, are as
follows:
<TABLE>
<S> <S> <S> <S>
Oil (BBLS)
1995 1994 1993
Proved developed and
undeveloped reserves:
Beginning of year 79,000 91,000 78,000
Revisions of previous estimates 72,000 (1,000) 23,000
Beginning of year as revised 151,000 90,000 101,000
Production (11,000) (11,000) (10,000)
End of year 140,000 79,000 91,000
Proved developed reserves:
Beginning of year 79,000 91,000 78,000
End of year 140,000 79,000 91,000
</TABLE>
(Continued)
F-16
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
<TABLE>
<S> <S> <S> <S>
Gas (MCF)
1995 1994 1993
Proved developed and
undeveloped reserves:
Beginning of year 32,225,000 24,660,000 24,980,000
Revisions of previous estimates 686,000 4,472,000 (889,000)
Beginning of year as revised 32,911,000 29,132,000 24,091,000
New discoveries and extensions 2,119,000 2,345,000 1,534,000
Acquisitions 135,000 1,943,000 -
Production (1,336,000) (1,195,000) (965,000)
End of year 33,829,000 32,225,000 24,660,000
Proved developed reserves:
Beginning of year 27,746,000 20,181,000 20,477,000
End of year 29,326,000 27,746,000 20,181,000
</TABLE>
(17) Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Gas Reserves (Unaudited)
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. Future cash inflows
are derived by applying current oil and gas prices to estimated
future production. Future production, development, site restoration
and abandonment costs are derived based on current costs assuming
continuation of existing economic conditions. Future income tax
expenses are computed by applying the statutory rate in effect at the
end of each year to the future pretax net cash flows, less the tax
basis of the properties and gives effect to permanent differences,
tax credits and allowances related to the properties.
<TABLE>
<S> <S> <S> <S>
Years Ended December 31,
1995 1994 1993
Future estimated cash flows $99,478,000 73,316,000 64,588,000
Future estimated production
and development costs (29,288,000) (24,370,000) (18,736,000)
Future estimated income
tax expense (20,004,000) (13,950,000) (13,068,000)
Future net cash flows 50,186,000 34,996,000 32,784,000
10% annual discount for
estimated timing of cash
flows (29,126,000) (20,551,000) (18,766,000)
Standardized measure of
discounted future
estimated net cash flows $21,060,000 14,445,000 14,018,000
</TABLE>
(Continued)
F-17
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The following table summarizes the principal sources of change in the
standardized measure of discounted future estimated net cash flows:
<TABLE> <S> <S> <S> <S>
Years Ended December 31,
1995 1994 1993
Sales of oil and gas
production, net of
production costs $(1,938,000) (1,875,000) (1,621,000)
Net changes in prices
and production costs 17,024,000 (9,560,000) (6,046,000)
Extensions, discoveries
and improved recovery,
less related cost 4,609,000 3,875,000 2,818,000
Acquisitions 294,000 2,745,000 -
Development costs incurred
during the period 2,978,000 2,261,000 1,412,000
Revisions of previous
quantity estimates 1,700,000 8,222,000 (1,607,000)
Changes in estimated
income taxes (6,054,000) (882,000) 3,803,000
Accretion of discount (8,575,000) (1,785,000) 1,572,000
Other (3,423,000) (2,574,000) (1,828,000)
$ 6,615,000 427,000 (1,497,000)
</TABLE>
It is necessary to emphasize that the data presented should not be
viewed as 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. Actual future prices and
costs are likely to be substantially different from the current
prices and costs utilized in the computation of reported amounts.
Any analysis or evaluation of the reported amounts should give
specific recognition to the computational methods utilized and the
limitations inherent therein.
(Continued)
F-18
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(18) Quarterly Financial Data (Unaudited)
Summarized quarterly financial data for the years ended December 31,
1995 and 1994, are as follows:
<TABLE>
<S> <S> <S> <S> <S> <S>
1995
Quarter Year
First Second Third Fourth
Revenues $9,537,000 $4,432,800 $3,582,500 $4,794,200 $22,346,500
Cost of operations 8,034,500 3,621,700 2,764,500 3,813,100 18,233,800
Gross profit 1,502,500 811,100 818,000 981,100 4,112,700
General and
administrative
expenses 450,300 520,900 600,700 388,700 1,960,600
Interest expense 83,400 76,300 71,000 89,000 319,700
533,700 597,200 671,700 477,700 2,280,300
Income before
income taxes 968,800 213,900 146,300 503,400 1,832,400
Income taxes 240,300 53,000 36,300 21,300 350,900
Net income $ 728,500 $ 160,900 $ 110,000 $ 482,100 $ 1,481,500
Primary earnings
per share $ .06 $ .02 $ .01 $ .04 $ .13
1994
Quarter Year
First Second Third Fourth
Revenues $8,833,900 $4,844,700 $3,715,700 $6,411,900 $23,806,200
Cost of operations 7,553,000 4,330,400 3,139,400 5,181,100 20,203,900
Gross profit 1,280,900 514,300 576,300 1,230,800 3,602,300
General and
administrative
expenses 498,100 532,300 635,200 538,200 2,203,800
Interest expense 68,600 69,600 81,200 80,800 300,200
566,700 601,900 716,400 619,000 2,504,000
Income (loss) before
income taxes 714,200 (87,600) (140,100) 611,800 1,098,300
Income taxes 160,700 (19,700) (39,800) 75,500 176,700
Net income (loss) $ 553,500 $ (67,900) $ (100,300) $ 536,300 $ 921,600
Primary earnings
(loss) per share $.05 $(.01) $(.01) $ .05 $ .08
</TABLE>
Cost of operations include cost of oil and gas well drilling operations,
oil and gas purchases and production costs and depreciation, depletion
and amortization.
(19) Subsequent Event
On January 31, 1996, the Company purchased 1,200,000 shares of its common
stock pursuant to an option agreement. The option was obtained in
connection with a debt restructuring in 1990. The company utilized its'
revolving credit line to acquire the shares for $1,000,000 or $0.83 a
share. The shares representing approximately 11% of the currently
outstanding stock were retired by the Company.
F-19
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
AND RESERVES
Years Ended December 31, 1995, 1994 and 1993
<TABLE>
<S> <S> <S> <S> <S>
Column A Column B Column C Column D Column E
Additions,
Balance at Charged to Balance
Beginning Costs and at End
Description of Period Expenses Deductions of Period
Allowance for doubtful
accounts deducted from
accounts and notes receivable
in the balance sheet
1995 $429,400 $210,000 $250,400 $389,000
1994 $362,300 $ 75,100 $ 8,000 $429,400
1993 $ 58,400 $410,000 $106,100 $362,300
</TABLE>
F-20
<PAGE>
Petroleum Development Corporation
Index to Exhibits
11 Schedule of Computation of Net Income Per Share E-2
E-1
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
EXHIBIT 11
SCHEDULE OF COMPUTATION OF NET INCOME PER SHARE
Years Ended December 31,
<TABLE>
<S> <S> <S> <S>
PRIMARY
1995 1994 1993
Net income for primary income
per common share before extraordinary item $1,481,500 $ 921,600 $ 1,320,800
Net income for primary income
per common share $1,481,500 $ 921,600 $ 1,589,800
Weighted average number of common shares
outstanding during the year 10,056,441 10,878,601 10,312,501
Add - common equivalent shares (determined
using the "treasury stock" method) represent-
ing shares issuable upon exercise of employee
stock options 1,550,249 1,111,896 1,251,147
Weighted average number of shares
used in calculation of primary
income per share 11,606,690 11,990,497 11,563,648
Primary income per share before
extraordinary item $ .13 $ .08 $ .11
Primary income per share $ .13 $ .08 $ .14
FULLY DILUTED
Net income for primary income per
common share before extraordinary item $ 1,481,500 $ 921,600 $ 1,320,800
Net income for primary income per
common share $ 1,481,500 $ 921,600 $ 1,589,800
Add:
Interest reduction on payment of debt
from issuance of stock proceeds, net
of applicable income taxes - - -
Net income for fully diluted
net income per share before
extraordinary item $ 1,481,500 $ 921,600 $ 1,320,800
Net income for fully diluted
net income per share $ 1,481,500 $ 921,600 $ 1,589,800
Weighted average number of shares
used in calculating primary income
per common share 11,606,690 11,990,497 11,563,648
Shares issuable upon exercise of stock
options used in primary calculation above (1,550,249) (1,111,896) (1,251,147)
Shares issuable for fully diluted calculation 1,880,689 1,111,896 1,251,147
Weighted average number of shares
used in calculation of fully
diluted income per share 11,937,130 11,990,497 11,563,648
Fully diluted earnings per share before
extraordinary item $ .12 $ .08 $ .11
Fully diluted earnings per share $ .12 $ .08 $ .14
E-11<PAGE>
</TABLE>
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<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 10,053,600
<SECURITIES> 0
<RECEIVABLES> 2,016,600
<ALLOWANCES> 389,000
<INVENTORY> 217,900
<CURRENT-ASSETS> 13,156,900
<PP&E> 48,240,000
<DEPRECIATION> 21,127,100
<TOTAL-ASSETS> 40,620,100
<CURRENT-LIABILITIES> 14,676,600
<BONDS> 2,500,000
0
0
<COMMON> 112,100
<OTHER-SE> 19,808,800
<TOTAL-LIABILITY-AND-EQUITY> 40,620,100
<SALES> 4,150,600
<TOTAL-REVENUES> 22,346,500
<CGS> 4,138,700
<TOTAL-COSTS> 20,514,100
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 210,000
<INTEREST-EXPENSE> 319,700
<INCOME-PRETAX> 1,832,400
<INCOME-TAX> 350,900
<INCOME-CONTINUING> 1,481,500
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,481,500
<EPS-PRIMARY> .13
<EPS-DILUTED> .12
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