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, 1997
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 16, 1998, 15,245,758 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 $75,458,012 (based on the
last traded price of $5.875).
DOCUMENTS INCORPORATED BY REFERENCE
Document Form 10-K Part III
Proxy Items 11 and 12
<PAGE>
PART I
Item 1. Business
The Company is a regional independent energy company engaged
primarily in the development, production and marketing of natural gas. The
Company has grown primarily through increased drilling and development
activities, the acquisition and subsequent development of natural gas
producing wells and the expansion of its natural gas marketing activities.
As of December 31, 1997, the Company operated approximately 1,281 wells
located in the Appalachian and Michigan Basins, and had net proved
reserves of 57.2 Bcf of natural gas. The Company's wells currently produce
an aggregate of approximately 22,000 Mcf of natural gas per day, of which
the Company's share is approximately 5,100 Mcf.
The majority of the wells operated by the Company are located in the
West Virginia and Pennsylvania portions of the Appalachian Basin. The
Appalachian Basin is characterized by shallow developmental wells, which
generally have provided highly predictable drilling success rates. In
addition, because wells drilled in the Appalachian Basin are closer to the
large demand centers for natural gas in the northeastern United States,
natural gas from this area typically has commanded a price premium
relative to natural gas produced in areas such as the Gulf Coast and
Mid-Continent regions of the United States. In 1997, the Company commenced
drilling in the Antrim shale formation of the Michigan Basin, and, through
December 31, 1997, had drilled 36 wells in this location. In addition to
its drilling activities, from time to time the Company purchases natural
gas producing properties. For example, in July 1996, the Company purchased
188 wells located in West Virginia from Angerman Associates, Inc.
In April 1996, the Company acquired Riley Natural Gas (RNG), an
Appalachian Basin natural gas marketing company, which aggregates and
resells natural gas developed by the Company and other producers. This
acquisition allowed the Company to diversify its operations beyond natural
gas drilling and production. RNG has established relationships with many
of the small natural gas producers in the Appalachian Basin and has
significant expertise in the natural gas end-user market. In addition, RNG
has extensive experience in the use of hedging strategies, which the
Company utilizes to reduce the financial impact on the Company of changes
in the price of natural gas.
Since 1984, the Company has sponsored limited partnerships formed to
engage in drilling operations. The Company typically retains a 20%
ownership interest in these drilling limited partnerships. In 1997, the
Company raised $35.5 million through four public drilling partnerships,
making it the sponsor of the largest public oil and gas partnership
program in the United States in that year. The drilling programs have
provided the Company with access to the capital resources necessary to
expand its drilling opportunities and to maintain the infrastructure
necessary to support such activities.
Industry Overview
Natural gas is the second largest energy source in the United States,
after liquid petroleum. The 22.5 Tcf of natural gas consumed in 1996
represented approximately 24% of the total energy used in the United
States. Natural gas is consumed in the United States as follows: 46% by
industrial end-users as feedstock for products such as plastic and
fertilizer or as the energy source for producing products such as glass;
24% and 15% by residential and commercial end-users, respectively, for
uses including heating, cooling and cooking; 12.5% by utilities for the
generation of electricity; and the remainder for transportation purposes.
The Company believes that the market for natural gas will grow in the
future. The demand for natural gas has increased due to four main factors:
Efficiency. Relative to other energy sources, natural gas losses
during transportation from source to destination are slight,
averaging only about 9% of the natural gas energy.
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Environmentally favorable. Natural gas is the cleanest and most
environmentally safe of the fossil fuels.
Safety. The delivery of natural gas is among the safest means of
distributing energy to customers, as the natural gas transmission
system is fixed and is located underground.
Price. The deregulation of the natural gas industry and a
favorable regulatory environment have resulted in end-users'
ability to purchase natural gas on a competitive basis from a
greater variety of sources.
The Company believes that the foregoing factors, together with the
increased availability of natural gas as a form of energy for residential,
commercial and industrial uses, should increase the demand for natural gas
as well as create new markets for natural gas.
As local supplies of natural gas are inadequate to meet demand, the
West Coast and the Northeast import natural gas from producing areas via
interstate natural gas pipelines. The cost of transporting natural gas
from the major producing areas to markets creates a price advantage for
production located closer to the consuming region. Appalachian Basin
natural gas production enjoys two advantageous factors affecting price.
First, the Appalachian Basin is characterized by shallow development gas
wells that generally have provided highly predictable drilling success
rates of 90% to 92%, which permits a more basic approach to drilling based
on the geology unique to the area. Also, the natural gas industry in the
Appalachian Basin benefits from its proximity to the northeastern United
States.
In the early 1980's, natural gas companies began exploiting the
northern portion of Michigan's lower peninsula, when certain favorable tax
credits for natural gas development were enacted. The result of such
development was new advances in drilling technology, which made natural
gas drilling in this area profitable even after the expiration of these
tax credits. In Michigan's lower peninsula, there is an abundance of
shallow Antrim gas shale, which should provide significant reserves per
well drilled. Additionally, this area is close to certain end-user
markets, which should provide favorable premiums. With a current
productive area of nearly 2.5 million acres, Michigan is one of the most
active areas for natural gas drilling in the United States.
Business Strategy
The Company's objective is to expand its natural gas reserves,
production and revenues through a strategy that includes the following key
elements:
Expand drilling operations. The Company has had one of the most
active drilling programs in the Northeast in the 1990's and will seek to
continue to build on the experience developed in drilling more than 550
shallow natural gas wells since 1992. The Company drilled 168 wells in
1997, compared to 97 for the year of 1996. The Company believes that it
will be able to drill a substantial number of new wells on its current
undeveloped leased properties. As of December 31, 1997, the Company had
61,850 net undeveloped acres in the Michigan Basin and 51,000 net
undeveloped acres in the Appalachian Basin. As drilling activity
increases, the Company benefits as its fixed costs may be spread over a
larger number of wells.
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<PAGE>
Acquire producing properties. The Company's acquisition efforts are
focused on properties that fit well within existing operations or that
help to build critical mass in areas where the Company is establishing new
operations. Acquisitions will likely offer economies in management and
administration, and therefore the Company believes that it will be able to
acquire more producing wells without incurring substantial increases in
its costs of operations.
Pursue geographic expansion. The Company has a proven ability to
drill and operate shallow natural gas wells successfully. There are a
number of areas outside the Appalachian Basin where drilling and operating
characteristics are similar to those in Appalachia. For example, in 1996,
the Company has expanded into the Michigan Basin, which permits the
Company to leverage its expertise developed in the Appalachian Basin
because of the similarities in methods of drilling, depth, equipment and
operations. Moreover, expected reserves and production levels of two to
three times that of Appalachian levels for a similar investment should
more than offset higher expected operating costs. The Company will
continue to evaluate opportunities to expand geographically on an ongoing
basis.
Reduce risks inherent in natural gas development and marketing. An
integral part of the Company's strategy has been and will continue to be
to concentrate on shallow development, (rather than exploratory) drilling,
and geographical diversification to reduce risk levels associated with
natural gas and oil production. Development drilling is less risky than
exploratory drilling and is likely to generate cash returns more quickly.
The focus on shallow wells builds on the Company's knowledge and
experience, and also provides greater investment diversification than an
equal investment in a smaller number of deeper and/or more expensive
wells. Geographical diversification can help to offset possible weakness
in the natural gas market or disappointing drilling results in one area.
The Company believes that, as natural gas markets are deregulated,
successful natural gas marketing is essential to profitable operations. To
further this goal, the Company acquired RNG, an experienced Appalachian
Basin natural gas marketer in 1996. The Company intends to continue to
expand its marketing capacity to keep pace with the changing natural gas
industry.
Expand strategic relationships. By managing drilling programs for
itself and other investors, the Company is able to share administrative,
overhead and other costs with its partners, reducing costs for both. The
Company also is able to maintain a larger and more capable geology and
engineering staff than would be possible without partners. Other benefits
from these associations include greater buying power for drilling services
and materials, larger amounts of natural gas available to market, profits
to the Company from drilling and operating wells for partners, and greater
awareness of the Company in the investment community.
Exploration and Development Activities
The Company's development activities focus on the identification and
drilling of new productive wells and the acquisition of existing producing
wells from other producers.
Prospect Generation
The Company's staff of professional geologists is responsible for
identifying areas with potential for economic production of natural gas.
The Company's team of professional geologists has decades of experience
drilling successful, economically feasible natural gas wells. The
geological team utilizes results from logs and other tools to evaluate
existing wells and to predict the location of attractive new gas reserves.
To further this process, 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
-4-
<PAGE>
actively drilling in the regions being evaluated. From this information
the geologists develop models of the subsurface structures and
stratigraphy that are used to predict areas with above-average prospects
for economic development.
On the basis of these models, the geologists instruct the Company's
land department to obtain available natural gas 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, the Company pays a lease bonus and
annual rental payments, converting, upon initiation of production, to a
12.5% royalty on gross production revenue in return for obtaining the
leases. In some instances of particularly attractive properties,
additional overriding royalty payments may be made to third parties or
royalty owners. As of December 31, 1997, the Company had a total
leasehold inventory of approximately 183,170 gross acres and 178,220 net
acres. See--"Properties--Natural Gas Leases."
Drilling Activities
When prospects have been identified and leased, the Company develops
these properties by drilling wells. In 1997, the Company drilled a total
of 168 wells, of which 10 were dry holes. 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. See
"Financing of Drilling Activities."
Much of the work associated with drilling, completing and connecting
wells, including drilling, fracturing, logging and pipeline construction,
is performed by subcontractors specializing in those operations, as is
common in the industry. A large part of the material and services used by
the Company in the development process is acquired through competitive
bidding by approved vendors. The Company also directly negotiates rates
and costs for services and supplies when conditions indicate that such an
approach is warranted. As the prices paid to the Company by its investor
partners for the Company's services are frequently fixed before the wells
are drilled or are determined solely on the well depth, the Company is
subject to the 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
development costs in advance of drilling and, when possible, at the time
of negotiation and execution of its investor partnership agreements.
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 greater ownership 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 approximately 53 wells from
Chesterfield Energy Corporation. The wells, located in Boone County, West
Virginia added more than two Bcf of proved producing reserves. In 1996,
the Company purchased approximately 188 producing wells from Angerman
Associates, Inc. The wells, located primarily in Gilmer County, West
Virginia, added more than four Bcf of proved producing reserves at
December 31, 1996, in addition to several proved undeveloped locations.
-5-
<PAGE>
Production
The following table shows the Company's net production in Bbls of
crude oil and in Mcf of natural gas and the costs and weighted average
selling prices thereof, for the last five years.
<TABLE>
<S> <S> <S> <S> <S> <S>
Year Ended December 31,
1997 1996 1995 1994 1993
Production(1):
Oil(MBbls) 9 7 11 11 10
Natural Gas (MMcf) 1,810 1,495 1,336 1,195 965
Equivalent MMcfs(2) 1,864 1,537 1,402 1,261 1,025
Average sales price:
Oil (per Bbl) $16.10 $16.35 $15.80 $14,.41 $16.62
Natural gas (per Mcf) $2.88 $3.04 $1.75 $2.01 $2.24
Average production cost
(lifting cost) per
equivalent Mcf(3) $0.65 $0.63 $0.53 $0.58 $0.57
</TABLE>
- ----------
[FN]
(1) Production as shown in the table is net to the Company and 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) A ratio of energy content of natural gas and oil (six Mcf of natural
gas equals one barrel of oil) was used to obtain a conversion factor
to convert oil production into equivalent Mcfs of natural gas.
(3) Production costs represent oil and gas operating expenses as
reflected in the financial statements of the Company.
</FN>
Well Operations
The Company currently operates approximately 1,190 natural gas wells
in the Appalachian Basin and 33 natural gas wells in the Michigan Basin.
The Company also operates 58 oil wells in the Appalachian Basin. The
Company's ownership interest in these wells ranges from 0% to 100%, and,
on average, the Company has an approximate 40% ownership interest in the
wells it operates. Currently these wells produce an aggregate of about
22,000 Mcf of natural gas per day, including the Company's share of 5,100
Mcf per day.
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, such as
reworks and recompletions.
Transportation
Natural gas wells are connected by pipelines to natural 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 natural gas being
developed from new areas and to enhance or maintain its existing systems.
The Company is paid a transportation fee for natural gas that is moved by
other producers through these pipeline systems. In many cases the Company
has been able to receive higher natural gas prices as a result of its
ability to move natural gas to more attractive markets through this
pipeline system, to the benefit of both the Company and its investor
partners.
-6-
<PAGE>
The Company has an Ohio subsidiary, Paramount Natural Gas Company
("PNG"), which commenced operations in October 1992 as a regulated Ohio
distribution utility. As a utility, PNG has been able to connect new
customers, and the Company is able to compete for the natural gas markets
of these customers by transporting natural gas through the PNG system. The
majority of PNG's throughput is attributable to natural gas transported
for the Company and industrial customers for a transportation tariff, with
the balance being sales to residential, commercial and industrial
customers.
In September 1997, the Company was notified that it had submitted a
successful bid for the acquisition of Columbia Gas Transmission Company's
Rimersburg natural gas gathering system, located in northern Pennsylvania.
If consummated, this transaction would occur in early to mid-1998 and
would add to the Company's existing natural gas gathering system 207 miles
of pipeline located in an area contiguous to the Company's Pennsylvania
drilling operations, at a cost to the Company of $1.4 million. The Company
believes that the advantage of such acquisition would be to improve its
natural gas gathering network at low cost to the Company, as current
operating personnel would be used to manage the additional pipeline. The
Company has conditioned the consummation of the transaction on numerous
factors, including an environmental audit, resolution of any environmental
problems revealed in such audit, transfer of natural gas gathering
agreements from Columbia Gas Transmission Company to the Company and FERC
approval. No assurance can be given that the Company will consummate this
transaction.
Item 2. Properties
Drilling Activity
The following table summarizes the Company's development drilling
activity for the years ended December 31, 1993, 1994, 1995, 1996 and 1997.
There is no correlation between the number of productive wells completed
during any period and the aggregate reserves attributable to those wells.
The Company's exploratory wells drilled in the past five years consist of
three dry holes (0.75 net) drilled in 1993.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Development Wells Drilled
Total Productive Gas Dry
Drilled Net Drilled Net Drilled Net
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
1996 97 17.44 92 16.46 5 .98
1997 168 40.72 158 38.00 10 2.72
Total 468 95.32 434 88.01 34 7.31
</TABLE>
Summary of Productive Wells
The table below shows the number of the Company's productive gross and net
wells at December 31, 1997.
<TABLE>
<S> <S> <S> <S> <S>
WELLS
Gas Oil
Location Gross Net Gross Net
Michigan 33 14.90 - -
Ohio 16 5.50 9 2.03
Pennsylvania 211 44.65 - -
Tennessee 1 0.57 39 15.50
West Virginia 962 417.45 10 4.46
Total 1,223 483.07 58 21.99
</TABLE>
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<PAGE>
Reserves
All of the Company's oil and natural gas reserves are located in the
United States. The Company's approximate net proved reserves were
estimated by Wright & Company, Inc. independent petroleum engineers
("Wright & Company"), for 1997 and 1996 and by the Company's petroleum
engineers for 1995 to be 57,243,000 Mcf of natural gas and 45,000 Bbls of
oil at December 31, 1997; 43,312,000 Mcf of natural gas and 81,000 Bbls of
oil at December 31, 1996; and 33,829,000 Mcf of natural gas and 140,000
Bbls of oil at December 31, 1995.
The Company's approximate net proved developed reserves were
estimated, by Wright & Company for 1997 and 1996 and by the Company's
petroleum engineers for 1995 to be 42,411,000 Mcf of natural gas and
45,000 Bbls of oil at December 31, 1997; 35,516,000 Mcf of natural gas and
81,000 Bbls of oil at December 31, 1996; and 29,326,000 Mcf of natural gas
and 140,000 Bbls of oil at December 31, 1995.
No major discovery or other favorable or adverse event that would
cause a significant change in estimated reserves is believed by the
Company to have occurred since December 31, 1997. 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's
petroleum engineers in 1995 and by Wright & Company in 1996 and 1997, to
be $27.9 million as of December 31, 1997, $34.3 million as of December 31,
1996, and $21.1 million as of December 31, 1995. These amounts are based
on year-end prices at the respective dates. The values expressed are
estimates only, and may not reflect realizable values or fair market
values of the natural gas and oil 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 natural gas and oil currently owned and does not
necessarily reflect the actual costs that would be incurred to acquire
equivalent natural gas and oil reserves.
Net Proved Natural Gas and Oil Reserves
The proved reserves of natural gas and oil of the Company as
estimated by Wright & Company at December 31, 1997 are set forth below.
These reserves have been prepared in compliance with the rules of the
Securities and Exchange Commission (the "SEC") based on year-end prices.
An analysis of the change in estimated quantities of natural gas and oil
reserves from January 1, 1997 to December 31, 1997, all of which arc
located within the United States, is shown below:
<TABLE>
<S> <S>
Natural Gas (Mcf)
Proved developed and undeveloped reserves:
Beginning of year (January 1, 1997) 43,312,000
Revisions of previous estimates 875,000
Beginning of year as revised 44,187,000
New discoveries and extensions 2,489,000
Dispositions -
Acquisitions, net of sales to partnerships 12,377,000
Production (1,810,000)
End of period (December 31, 1997) 57,243,000
Proved developed reserves:
Beginning of year (January 1, 1997) 35,516,000
End of period (December 31, 1997) 42,411,000
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<PAGE>
Oil (Bbls)
Proved developed and undeveloped reserves:
Beginning of year (January 1, 1997) 81,000
Revisions of previous estimates (27,000)
Beginning of year as revised 54,000
Dispositions -
Acquisitions -
Production (9,000)
End of period (December 31, 1997) 45,000
Proved developed reserves:
Beginning of year (January 1, 1997) 81,000
End of period (December 31, 1997) 45,000
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Natural Gas and Oil Reserves
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 natural gas and oil reserves. Future cash
inflows are computed by applying year-end prices of natural gas and oil
relating to the Company's proved reserves to year-end quantities of those
reserves. 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 December 31, 1997
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>
December 31, 1997
Future estimated cash flows $159,618,000
Future estimated production and development costs (69,265,000)
Future estimated income tax expense (20,781,000)
Future net cash flows 69,572,000
10% annual discount for estimated
timing of cash flows (41,636,000)
Standardized measure of discounted
future estimated net cash flows $ 27,936,000
</TABLE>
The following table summarizes the principal sources of change in
the standardized measure of discounted future estimated net cash flows
from January 1, 1997 through December 31, 1997:
<TABLE>
<S> <S>
Sales of oil and natural gas production,
net of production costs $ (4,158,000)
Net changes in prices and production costs (63,573,000)
Extensions, discoveries and improved recovery,
less related cost 3,705,000
Acquisitions, net of sales to partnerships 13,299,000
Development costs incurred during the period 9,863,000
Revisions of previous quantity estimates 2,332,000
Changes in estimated income taxes 12,718,000
Accretion of discount 24,597,000
Other (5,109,000)
$ (6,326,000)
</TABLE>
The foregoing data should not be viewed as representing the expected
cash flow from, or current value of, existing proved reserves, as 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
-9-<PAGE>
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 and the limitations inherent
therein.
Substantially all of the Company's natural gas and oil reserves have
been mortgaged or pledged as security for bank loans to the Company. See
Note 3 of Notes to Consolidated Financial Statements.
Natural Gas Leases
The following table sets forth, as of December 31, 1997, the acres
of developed and undeveloped natural gas and oil properties in which the
Company had an interest, listed alphabetically by state.
<TABLE>
<S> <S> <S> <S> <S>
Developed Undeveloped
Acreage Acreage
Gross Net Gross Net
Michigan 9,700 9,400 63,700 61,850
Ohio 770 770 1,300 1,300
Pennsylvania 2,100 2,100 17,700 17,700
Tennessee 3,600 3,600 - -
West Virginia50,100 49,500 34,200 32,000
Total 66,270 65,370 116,900 112,850
</TABLE>
Title to Properties
The Company believes that it holds good and indefeasible title to
its properties, in accordance with standards generally accepted in the
natural 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 exceptions, in the Company's judgment, do
not detract substantially from the use of such property. As is customary
in the natural 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, an extensive 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. No single
property owned by the Company represents a material portion of the
Company's holdings. The Company's properties are subject to customary
royalty interests, liens incident to operating agreements, liens for
current taxes and other burdens which the Company believes do not
materially interfere with the use of or affect the value of such
properties.
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 natural gas and oil leases, farm-out 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.
Natural Gas Sales
Natural gas is sold by the Company under contracts with terms
ranging from one month to three years. Virtually all of the Company's
contract pricing provisions are tied to a market index, with certain
adjustments based on, among other factors, whether a well delivers to a
gathering or transmission line, quality of natural gas and prevailing
supply and demand conditions, so that the price of the natural gas
fluctuates to remain competitive with other available natural gas
supplies. As a result, the Company's revenues from the sale of natural gas
will suffer if market prices decline and benefit if they increase. The
Company believes that the pricing provisions of its natural gas contracts
are customary in the industry.
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The Company sells its natural gas to industrial end-users and
utilities. One customer, Hope Gas, Inc., a regulated public utility ("Hope
Gas"), accounted for 26.6% of the Company's revenues from oil and gas
sales (12.0% of total revenues) in 1997; 30.7% of the Company's revenues
from oil and gas sales (16.1% of total revenues) in 1996 and 39.7% of the
Company's revenues from oil and gas sales (7.4% of total revenues) in
1995. The Company and Hope Gas are parties to a Pipeline Purchase
Agreement, which expires on May 31, 1999, pursuant to which agreement the
Company must deliver to Hope Gas, upon demand, minimum quantities of
natural gas (4,500 dth per day delivered directly to Hope Gas's pipelines
and 11,000 dth per day for total deliveries including both direct and
transferred volumes). The Company and Hope Gas are also parties to a
Master Gas Purchase Agreement, which expires on May 31, 1999, pursuant to
which the Company must offer to Hope Gas all volumes of natural gas
available at specific points of delivery, up to the minimum delivery
requirements of the Pipeline Purchase Agreement. No other single purchaser
of the Company's natural gas accounted for 10% or more of the Company's
total revenues during 1997, 1996 or 1995.
At December 31, 1997, natural gas produced by the Company sold at
prices per Mcf ranging from $1.72 to $4.42, depending upon well location,
the date of the sales contract and whether the natural gas was sold in
interstate or intrastate commerce. The weighted net average price of
natural gas sold by the Company during 1997 was $2.88 per Mcf.
In general, the Company, together with its marketing subsidiary,
RNG, has been and expects to continue to be able to produce and sell
natural gas from its wells without curtailment by providing natural 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 natural gas at any point in time.
Natural Gas Marketing
The Company's natural gas marketing activities involve the
aggregation and reselling of natural gas produced by the Company and
others. The Company believes that, as natural gas markets are deregulated,
successful natural gas marketing is essential to profitable operations. A
variety of factors affect the market for natural gas, including the
availability of other domestic production, natural gas imports, the
availability and price of alterative fuels, the proximity and capacity of
natural gas pipelines, general fluctuations in the supply and demand for
natural gas and the effects of state and federal regulations on natural
gas production and sales. The natural gas industry also competes with
other industries in supplying the energy and fuel requirements of
industrial, commercial and individual customers.
In 1996, the Company acquired RNG, an Appalachian Basin natural gas
marketing company that specializes in the acquisition and aggregation of
Appalachian Basin gas production. The owner/managers and employees of RNG
joined the Company, and RNG's operations were relocated to the Company's
headquarters. RNG markets natural gas produced by the Company and also
purchases natural gas from other producers and resells to utilities, end
users or other marketers. The employees of RNG have extensive knowledge of
the natural gas market in the Appalachian region. Such knowledge should
assist the Company in maximizing its prices as it markets natural gas from
Company-operated wells. RNG and its management also bring to the Company
specific knowledge and relationships with many producers in the
Appalachian Basin region. Paramount Transmission Corporation ("PTC"), an
-11-
<PAGE>
Ohio subsidiary of the Company, focuses its efforts on the marketing of
Ohio natural gas production to commercial and industrial end-users.
In West Virginia, Pennsylvania and Michigan, the Company markets
natural gas from its own wells and wells operated for its investment
partnerships as a part of the services provided under the basic monthly
operating charge. The gas is marketed to natural 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.
Hedging Activities
The Company utilizes commodity-based derivative instruments as
hedges to manage a portion of its exposure to price volatility stemming
from its natural gas sales and marketing activities. These instruments
consist of NYMEX-traded natural gas futures contracts. The futures
contracts hedge committed and anticipated natural gas purchases and sales,
generally forecasted to occur within a three- to twelve-month period.
Company policy prohibits the use of natural gas futures for speculative
purposes and permits utilization of hedges only if there is an underlying
physical position.
The Company has extensive experience with the use of financial
hedges to reduce the risk and impact of natural gas price changes. These
hedges are used to coordinate fixed and variable priced purchases and
sales and to "lock in" fixed prices from time to time for the Company's
share of production. In order for future contracts to serve as effective
hedges, there must be sufficient correlation to the underlying hedged
transaction. While hedging can help provide price protection if spot
prices drop, hedges can also limit upside potential.
Despite the measures taken by the Company to attempt to control
price risk, the Company remains subject to price fluctuations for natural
gas sold in the spot market. The Company continues to evaluate the
potential for reducing these risks by entering into hedge transactions. In
addition, the Company may also close out any portion of hedges that may
exist from time to time. As of December 31, 1997, there were 198 existing
hedge positions. Total natural gas purchased and sold under hedging
arrangements during the year ended December 31, 1997 was 4,000,000 MMbtu.
Under such hedging arrangements, the Company realized a loss of $390,300
for the year ended December 31, 1997.
Financing of Drilling Activities
The Company conducts development drilling activities for its own
account and for other investors. In 1984, the Company began sponsoring
private drilling limited partnerships, and, in 1989, the Company began to
register the partnership interests offered under public drilling programs
with the SEC. The Company's public partnerships had $35.5 million in
subscriptions in 1997. Funds received pursuant to drilling contracts were
$25.5 million in 1996 and $13.6 million in 1995. The Company generally
invests, as its equity contribution to each drilling partnership, an
additional sum approximating 20% of the aggregate subscriptions received
for that particular drilling partnership. As a result, the Company is
subject to substantial cash commitments at the closing of each drilling
partnership. The funds received from these programs are restricted to use
in future drilling operations. 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. Most of the Company's drilling and development funds now are
received from partnerships in which the Company serves as managing general
partner. However, because wells produce for a number of years, the Company
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<PAGE>
continues to serve as operator for a large number of unaffiliated parties.
In addition to the partnership structure, the Company also utilizes joint
venture arrangements for financing drilling activities.
The financing process begins when the Company enters into a
development agreement with an investor partner, pursuant to which the
Company agrees to assign its rights in the property to be drilled to the
partnership or other entity. The partnership or other entity thereby
becomes owner of a working interest in the property.
The Company's development contracts with its investor partners have
historically taken many different forms. Generally the agreements can be
classified as on a "footage-based" rate, whereby the Company receives
drilling and completion payments based on the depth of the well;
"cost-plus," in which the Company is reimbursed for its actual cost of
drilling plus some additional amount for overhead and profit; or
"turnkey," in which a specified amount is paid for drilling and another
amount for completion. As part of the compensation for its services, the
Company also has received 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. Often the Company's development
contracts provide for a combination of several of the foregoing 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
subject properties.
The level of the Company's drilling and development activity is
dependent upon the amount of subscriptions in its public drilling
partnerships and investments from other partnerships or other joint
venture partners. The use of partnerships and similar financing structures
enables the Company to diversify its holdings, thereby reducing the risks
to its development investments. Additionally, the Company benefits through
such arrangements by its receipt of fees for its management services
and/or through an increased share in the revenues produced by the
developed properties. The Company believes that investments in drilling
activities, whether through Company-sponsored partnerships or other
sources, are influenced in part by the favorable treatment that such
investments enjoy under the federal income tax laws. No assurance can be
given that the Company will continue to have access to funds generated
through these financing vehicles.
Oil Production
Before 1980, the Company generated a significant portion of its
revenues from oil production. However, the Company made a strategic
decision to concentrate its development efforts on natural gas production
and most of the Company's current oil production is associated with
natural gas production. The Company does not believe its current
production of oil, from wells located in Tennessee, Ohio and West
Virginia, to be material, as its share of oil production has declined to
about 9,000 barrels per year. The Company is currently able to sell all
the oil that it can produce under existing sales contracts with petroleum
refiners and marketers. The Company does not refine any of its oil
production. 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.
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 1997, 1996 or 1995.
At December 31, 1997, oil produced by the Company sold at prices ranging
from $14.25 to $15.50 per barrel, depending upon the location and quality
of oil. In 1997, the weighted net average price per barrel of oil sold by
the Company was $16.10.
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<PAGE>
Oil production is subject to many of the same operating hazards and
environmental concerns as natural gas production, but is also subject to
the risk of oil spills. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as the
Company, to procure and implement spill prevention, control, counter-
measures and response plans relating to the possible discharge of oil into
surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of
facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from oil spills.
Noncompliance with OPA may result in varying civil and criminal penalties
and liabilities. Operations of the Company are also subject to the Federal
Clean Water Act and analogous state laws relating to the control of water
pollution, which laws provide varying civil and criminal penalties and
liabilities for release of petroleum or its derivatives into surface
waters or into the ground.
Governmental Regulation
The Company's business and the natural gas industry in general are
heavily regulated. The availability of a ready market for natural gas
production depends on several factors beyond the Company's control. These
factors include regulation of natural gas production, federal and state
regulations governing environmental quality and pollution control, state
limits on allowable rates of production, the amount of natural gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive
fuels. State and federal regulations generally are intended to prevent
waste of natural gas, protect rights to produce natural gas between owners
in a common reservoir, control the amount of natural gas produced by
assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal,
state and local agencies. The Company takes the steps necessary to comply
with applicable regulations both on its own behalf and as part of the
services it provides to its investor partnerships. The Company believes
that it is in substantial compliance with such statutes, rules,
regulations and governmental orders, although there can be no assurance
that this is or will remain the case. The following discussion of the
regulation of the United States natural gas industry is not intended to
constitute a complete discussion of the various statutes, rules,
regulations and environmental orders to which the Company's operations may
be subject.
Regulation of Natural Gas Exploration and Production
The Company's natural gas operations are subject to various types of
regulation at the federal, state and local levels. Prior to commencing
drilling activities for a well, the Company must procure permits and/or
approvals for the various stages of the drilling process from the
applicable state and local agencies in the state in which the area to be
drilled is located. Such permits and approvals include those for the
drilling of wells, and such regulation includes maintaining bonding
requirements in order to drill or operate wells and regulating the
location of wells, the method of drilling and casing wells, the surface
use and restoration of properties on which wells are drilled, the plugging
and abandoning of wells and the disposal of fluids used in connection with
operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the
size of drilling and spacing units or proration units and the density of
wells, which may be drilled and the unitization or pooling of natural gas
properties. In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely
primarily or exclusively on voluntary pooling of lands and leases. In
areas where pooling is voluntary, it may be more difficult to form units,
and therefore, more difficult to develop a project if the operator owns
less than 100% of the leasehold. In addition, state conservation laws
establish maximum rates of production from natural gas wells, generally
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<PAGE>
prohibit the venting or flaring of natural gas and impose certain
requirements regarding the ratability of production. The effect of these
regulations may limit the amount of natural gas the Company can produce
from its wells and may limit the number of wells or the locations at which
the Company can drill. The regulatory burden on the natural gas industry
increases the Company's costs of doing business and, consequently, affects
its profitability. In as much as such laws and regulations are
frequently expanded, amended and reinterpreted, the Company is unable to
predict the future cost or impact of complying with such regulations.
Regulation of Sales and Transportation of Natural Gas
Historically, the transportation and sale for resale of natural gas
in interstate commerce have been regulated pursuant to the Natural Gas Act
of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the
regulations promulgated thereunder by FERC. Maximum selling prices of
certain categories of natural gas sold in "first sales," whether sold in
interstate or intrastate commerce, were regulated pursuant to the NGPA.
The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as
of January 1, 1993, all remaining federal price controls from natural gas
sold in "first sales" on or after that date. FERC's jurisdiction over
natural gas transportation was unaffected by the Decontrol Act. While
sales by producers of natural gas and all sales of crude oil, condensate
and natural gas liquids can currently be made at market prices, Congress
could reenact price controls in the future.
The Company's sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to
pipeline transportation are subject to extensive regulation. In recent
years, FERC has undertaken various initiatives to increase competition
within the natural gas industry. As a result of initiatives like FERC
Order No.636, issued in April 1992, the interstate natural gas
transportation and marketing system has been substantially restructured to
remove various barriers and practices that historically limited
non-pipeline natural gas sellers, including producers, from effectively
competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most
significant provisions of Order No.636 require that interstate pipelines
provide transportation separate or "unbundled" from their sales service,
and require that pipelines provide firm and interruptible transportation
service on an open access basis that is equal for all natural gas
suppliers. In many instances, the result of Order No.636 and related
initiatives have been to substantially reduce or eliminate the interstate
pipelines' traditional role as wholesalers of natural gas in favor of
providing only storage and transportation services. Another effect of
regulatory restructuring is the greater transportation access available on
interstate pipelines. In some cases, producers and marketers have
benefitted from this availability. However, competition among suppliers
has greatly increased and traditional long-term producer-pipeline
contracts are rare. Furthermore, gathering facilities of interstate
pipelines are no longer regulated by FERC, thus allowing gatherers to
charge higher gathering rates.
Additional proposals and proceedings that might affect the natural
gas industry are pending before Congress, FERC, state commissions and the
courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by FERC and Congress will continue.
The Company cannot determine to what extent future operations and earnings
of the Company will be affected by new legislation, new regulations, or
changes in existing regulation, at federal, state or local levels.
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<PAGE>
Environmental Regulations
The Company's operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years.
The trend of more expansive and stricter environmental legislation and
regulations could continue. To the extent laws are enacted or other
governmental action is taken that restricts drilling or imposes
environmental protection requirements that result in increased costs to
the natural gas industry in general, the business and prospects of the
Company could he adversely affected.
The Company generates wastes that may be subject to the Federal
Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The U.S. Environmental Protection Agency ("EPA") and various
state agencies have limited the approved methods of disposal for certain
hazardous and nonhazardous wastes. Furthermore, certain wastes generated
by the Company's operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes,"
and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Company currently owns or leases numerous properties that for
many years have been used for the exploration and production of oil and
natural gas. Although the Company believes that it has utilized good
operating and waste disposal practices, prior owners and operators of
these properties may not have utilized similar practices, and hydrocarbons
or other wastes may have been disposed of or released on or under the
properties owned or leased by the Company or on or under locations where
such wastes have been taken for disposal. These properties and the wastes
disposed thereon may be subject to the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous
state laws as well as state laws governing the management of oil and
natural gas wastes. Under such laws, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed
of or released by prior owners or operators) or property contamination
(including groundwater contamination) or to perform remedial plugging
operations to prevent future contamination.
CERCLA and similar state laws impose liability, without regard to
fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the
owner or operator of the disposal site or sites where the release occurred
and companies that disposed of or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were
responsible for release of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into
the environment.
The Company's operations may be subject to the Clean Air Act ("CAA")
and comparable state and local requirements. Amendments to the CAA were
adopted in 1990 and contain provisions that may result in the gradual
imposition of certain pollution control requirements with respect to air
emissions from the operations of the Company. The EPA and states have been
developing regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several years
for air pollution control equipment in connection with maintaining or
obtaining operating permits and approvals addressing other air
emission-related issues.
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<PAGE>
The Company's expenses relating to preserving the environment during
1997 were not significant in relation to operating costs and the Company
expects no material change in 1998. Environmental regulations have had no
materially adverse effect on the Company's 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 business, financial condition
or results of operations.
As a matter of corporate policy and commitment, the Company attempts
to minimize the adverse environmental impact of all its operations. For
example, during 1997, the Company was one of the most active drilling
companies in West Virginia. Even with this level of activity, the Company
was able to maintain a high level of environmental sensitivity. During the
1990's, the Company has been a four-time recipient of the West Virginia
Department of Environmental Protection's top award in recognition of the
quality of the Company's environmental and reclamation work in its
drilling activities.
Utility Regulation
PNG, 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.
Operating Hazards and Insurance
The Company's exploration and production operations include a
variety of operating risks, including the risk of fire, explosions,
blowouts, craterings, pipe failure, casing collapse, abnormally pressured
formations, and environmental hazards such as gas leaks, ruptures and
discharges of toxic gas, the occurrence of any of which could result in
substantial losses to the Company due to injury and loss of life, severe
damage to and destruction of property, natural resources and equipment,
pollution and other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations. The
Company's pipeline, gathering and distribution operations are subject to
the many hazards inherent in the natural gas industry. These hazards
include damage to wells, pipelines and other related equipment, and
surrounding properties caused by hurricanes, floods, fires and other acts
of God, inadvertent damage from construction equipment, leakage of natural
gas and other hydrocarbons, fires and explosions and other hazards that
could also result in personal injury and loss of life, pollution and
suspension of operations.
Any significant problems related to its facilities could adversely
affect the Company's ability to conduct its operations. In accordance with
customary industry practice, the Company maintains insurance against some,
but not all, potential risks; however, there can be no assurance that such
insurance will be adequate to cover any losses or exposure for liability.
The occurrence of a significant event not fully insured against could
materially adversely affect the Company's operations and financial
condition. The Company cannot predict whether insurance will continue to
be available at premium levels that justify its purchase or whether
insurance will be available at all.
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Competition
The Company believes that its exploration, drilling and production
capabilities and the experience of its management generally enable it to
compete effectively. The Company encounters competition from numerous
other natural gas companies, drilling and income programs and partnerships
in all areas of its operations, including drilling and marketing natural
gas and obtaining desirable natural gas leases. Many of these competitors
possess larger staffs and greater financial resources than the Company,
which may enable them to identify and acquire desirable producing
properties and drilling prospects more economically. The Company's ability
to explore for natural gas prospects and to acquire additional properties
in the future depends upon its ability to conduct its operations, to
evaluate and select suitable properties and to consummate transactions in
this highly competitive environment. 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. The Company also faces intense competition in the marketing of
natural gas from competitors including other producers as well as
marketing companies. Also, international developments and the possible
improved economics of domestic natural gas exploration may influence other
oil companies to increase their domestic natural gas exploration.
Furthermore, competition among natural gas companies for favorable natural
gas prospects can be expected to continue, and it is anticipated that the
cost of acquiring natural gas properties may increase in the future.
Factors affecting competition in the natural gas industry include price,
location, availability, quality and volume of natural gas. The Company
believes that it can compete effectively in the natural gas industry on
each of the foregoing factors, due to the location of its wells near the
large demand centers for natural gas located in the northeastern United
States and the price premiums generally available for Appalachian Basin
natural gas, the quality and availability of the natural gas the Company
produces, the proximity of its wells to transportation and the significant
volume of natural gas produced by the Company on a daily basis.
Nevertheless, the Company's business, financial condition or results of
operations could be materially adversely affected by competition.
Employees
As of December 31, 1997, the Company had 75 employees, including 12
in finance, seven in administration, 13 in exploration and development, 37
in production and six in natural gas marketing. The Company's engineers,
supervisors and well tenders are generally responsible for the day-to-day
operation of wells and pipeline systems. In addition, the Company retains
subcontractors to perform drilling, fracturing, logging, and pipeline
construction functions at drilling sites. The Company's employees act as
supervisors of the subcontractors.
The Company's employees are not covered by a collective bargaining
agreement. The Company considers relations with its employees to be
excellent.
Facilities
The Company owns and occupies three buildings in Bridgeport, West
Virginia, two of which serve as the Company's headquarters and one which
serves as a field operating site. The Company also owns a field operating
building in Gilmer County, West Virginia. The Company believes that its
current facilities are sufficient for its current and anticipated
operations.
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Item 3. Legal Proceedings
From time to time the Company is a party to various legal
proceedings in the ordinary course of business. The Company is not
currently a party to any litigation that it believes would materially
affect the Company's business, financial condition or results of
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
1996
First Quarter 2 1/8 1 5/16
Second Quarter 2 13/16 1 7/8
Third Quarter 3 9/16 2 7/16
Fourth Quarter 6 3/16 3 3/8
1997
First Quarter 5 1/8 3 9/16
Second Quarter 5 5/16 2 7/8
Third Quarter 11 7/16 4 13/16
Fourth Quarter 10 7/16 4 3/4
</TABLE>
As of December 31, 1997, there were approximately 1,758 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.
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Item 6. Selected Financial Data (1)
<TABLE>
<S> <S> <S> <S> <S> <S>
Year Ended December 31,
1997 1996 1995 1994 1993
Revenues
Oil and gas well
drilling
operations $34,405,400 $18,698,200 $13,941,000 $15,190,200 $12,073,500
Oil and gas sales 33,390,200 26,051,100 4,150,600 4,361,300 4,471,200
Well operations
income 4,509,300 3,928,800 3,750,900 3,730,300 3,843,100
Other income 1,573,100 935,600 504,000 524,400 97,600
Total $73,878,000 $49,613,700 $22,346,500 $23,806,200 $20,485,400
Costs and Expenses
(excluding
interest and
depreciation,
depletion and
amortization) $61,219,600 $42,274,100 $18,042,300 $20,559,500 $17,116,700
Interest Expense $ 315,900 $ 380,000 $ 319,700 $ 300,200 $ 55,500
Depreciation,
Depletion and
Amortization $ 2,660,300 $ 2,309,600 $ 2,152,100 $ 1,848,200 $ 1,717,400
Income before
extraordinary
item $ 7,586,800 $ 3,549,400 $ 1,481,500 $ 921,600 $ 1,320,800
Extraordinary item
net of income
taxes - - - - 269,000
Net Income $ 7,586,800 $ 3,549,400 $ 1,481,500 $ 921,600 $ 1,589,800
Basic earnings
per common share
Income before
extraordinary item $ .67 $ .34 $ .13 $ .08 $ .13
Net income $ .67 $ .34 $ .13 $ .08 $ .15
Diluted earnings
per share
Income before
extraordinary item $ .61 $ .31 $ .13 $ .08 $ .11
Net income $ .61 $ .31 $ .13 $ .08 $ .14
Average Common and
Common Equivalent
Shares Outstanding
During the Year 12,540,165 11,542,315 11,611,164 12,115,612 11,604,332
December 31,
1997 1996 1995 1994 1993
Total Assets $98,411,600 $63,604,200 $40,620,100 $38,325,300 $36,412,900
Working Capital $16,483,200 $(2,357,200) $(1,519,700) $(1,613,700) $ 289,000
Long-Term Debt,
excluding current
maturities $ - $ 5,320,000 $ 2,500,000 $ 3,100,000 $ 3,167,300
Stockholders'
Equity $55,766,100 $23,072,500 $19,920,900 $18,380,500 $17,235,700
</TABLE>
(1) See Consolidated Financial Statements elsewhere herein.
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Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Safe Harbor Statement Under the Private Securities
Litigation Reform Act of 1995
Statements, other than historical facts, contained in this Annual
Report on Form 10-K, including statements of estimated oil and gas
production and reserves, drilling plans, future cash flows, anticipated
capital expenditures and Management's strategies, plans and objectives, are
"forward looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. Although the Company believes that its
forward looking statements are based on reasonable assumptions, it cautions
that such statements are subject to a wide range of risks and uncertainties
incident to the exploration for, acquisition, development and marketing of
oil and gas, and it can give no assurance that its estimates and
expectations will be realized. Important factors that could cause actual
results to differ materially from the forward looking statements include,
but are not limited to, changes in production volumes, worldwide demand, and
commodity prices for petroleum natural resources; the timing and extent of
the Company's success in discovering, acquiring, developing and producing
oil and gas reserves; risks incident to the drilling and operation of oil
and gas wells; future production and development costs; the effect of
existing and future laws, governmental regulations and the political and
economic climate of the United States; the effect of hedging activities; and
conditions in the capital markets. Other risk factors are discussed
elsewhere in this Form 10-K.
Results of Operations
Year Ended December 31, 1997 Compared with December 31, 1996
Revenues. Total revenues for the year ended December 31, 1997 were
$73.9 million compared to $49.6 million for the year ended December 31,
1996, an increase of approximately $24.3 million, or 49.0%. Drilling
revenues for the year ended December 31, 1997 were $34.4 million compared to
$18.7 for the year ended December 31, 1996, an increase of approximately
$15.7 million, or 84.0%. Such increase was due to an increase in drilling
and completion activities, which was a direct result of an increase in
drilling funds from the Company's public drilling programs. Oil and gas
sales for the year ended December 31, 1997 were $33.4 million compared to
$26.1 million for the year ended December 31, 1996, an increase of
approximately $7.3 million, or 28.0%. Such increase was due primarily to
the natural gas marketing activities of RNG, along with increased production
from the Company's producing properties. This increase was offset in part
by lower average sales prices from the Company's producing properties and
decreased natural gas purchased for resale. Well operations and pipeline
income for the year ended December 31, 1997 were $4.5 million compared to
$3.9 million for the year ended December 31, 1996, an increase of
approximately $600,000, or 15.4%. Such increase resulted from an increase
in the number of wells operated by the Company. Other income for the year
ended December 31, 1997 was $1,573,000 compared to $936,000 for the year
ended December 31, 1996, an increase of approximately $637,000 or 68.1%.
Such increase was due to management fees earned on higher volumes of
drilling partnerships, interest earned on higher average cash balances along
with a gain on the sale of equipment.
Costs and expenses. Costs and expenses for the year ended December 31,
1997 were $64.2 million compared to $45.0 million for the year ended
December 31, 1996, an increase of approximately $19.2 million, or 42.7%.
Oil and gas well drilling operations costs for the year ended December 31,
1997 were $28.0 million compared to $15.8 million for the year ended
December 31, 1996, an increase of approximately $12.2 million, or 77.2%.
-21-
<PAGE>
Such increase resulted from additional expenses due to increased drilling
activity. Oil and gas purchases and production costs for the year ended
December 31, 1997 were $30.9 million compared to $24.2 million for the year
ended December 31, 1996, an increase of approximately $6.7 million, or
27.7%. Such increase was due primarily to natural gas purchases by RNG for
resale and offset partially by lower volumes of natural gas purchased for
resale.
Net income. Net income for the year ended December 31, 1997 was $7.6
million compared to $3.5 million for the year ended December 31, 1996, an
increase of approximately $4.1 million, or 117.1%.
Year Ended December 31, 1996 Compared with December 31, 1995
Revenues. Total revenues for the year ended December 31, 1996 were
$49.6 million compared to $22.3 million for the year ended December 31,
1995, an increase of approximately $27.3 million, or 122.4%. Drilling
revenues for the year ended December 31, 1996, were $18.7 million compared
to $13.9 million for the year ended December 31, 1995, an increase of
approximately $4.8 million, or 34.5%. Such increase was due to an increase
in drilling and completion activities, which was a direct result of an
increase in drilling funds from the Company's public drilling programs. Oil
and gas sales for year ended December 31, 1996 were $26.1 million compared
to $4.2 million for the year ended December 31, 1995, an increase of
approximately $21.9 million, or 521.4%. Such increase was due primarily to
the natural gas marketing activities of RNG, along with increased production
and higher average sales prices from the Company's producing properties and
increased natural gas purchased for resale. Well operations and pipeline
income for the year ended December 31, 1996 were $3.9 million compared to
$3.7 million for the year ended December 31, 1995, an increase of
approximately $200,000, or 5.4%. Such increase resulted from an increase in
the number of wells operated by the Company. Other income for the year
ended December 31, 1996 was $936,000 compared to $504,000 for the year ended
December 31, 1995, an increase of approximately $432,000, or 85.7%. Such
increase was due to management fees earned on higher volumes of drilling
partnerships.
Costs and expenses. Costs and expenses for the year ended December 31,
1996 were $45.0 million compared to $20.5 million for the year ended
December 31, 1995, an increase of approximately $24.5 million, or 119.5%.
Oil and gas well drilling operations costs for the year ended December 31,
1996 were $15.8 million compared to $11.9 million for the year ended
December 31, 1995, an increase of approximately $3.9 million, or 32.8%.
Such increase resulted from additional expenses resulting from increased
drilling activity. Oil and gas purchases and production costs for the year
ended December 31, 1996 were $24.2 million compared to $4.1 million for the
year ended December 31, 1995, an increase of approximately $20.1 million, or
490.2%. Such increase was due primarily to natural gas purchases by RNG for
resale and to a lesser extent higher volumes of natural gas purchased for
resale at higher average prices. General and administrative expenses for
the year ended December 31, 1996 were $2.3 million compared to $2.0 million
for the year ended December 31, 1995, an increase of approximately $300,000,
or 15.0%. Such increase was due to overall administrative costs and
increased personnel costs and generally higher administrative overhead.
Net income. Net income for the year ended December 31, 1996 was $3.5
million compared to $1.5 million for the year ended December 31, 1995, an
increase of approximately $2.0 million, or 133.3%.
Year 2000 Issue
The Company has assessed the extent of the Year 2000 Issues affecting
the Company. The Company believes that the new computer system including
operating software currently being installed along with modifications being
made by the Company's computer technicians will address the dating system
-22-
<PAGE>
flaw inherent in most operating systems. The Company expects to be fully
Year 2000 Compliant by the end of 1998. Management believes that cost to
become Year 2000 Compliant is not material to the Company's financial
position or results of operations.
Liquidity and Capital Resources
The Company funds its operations through a combination of cash flow
from operations, capital raised through drilling partnerships, and use of
the Company's credit facility. Operational cash flow is generated by sales
of natural gas from the Company's well interests, well drilling and
operating activities for the Company's investor partners, natural gas
gathering and transportation, and natural gas marketing. Cash payments from
Company-sponsored partnerships are used to drill and complete wells for the
partnerships, with operating cash flow accruing to the Company to the extent
payments exceed drilling costs. The Company utilizes its revolving credit
arrangement to meet the cash flow requirements of its operating and
investment activities.
Sales volumes of natural gas have continued to increase while natural
gas prices fluctuate monthly. The Company's natural 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 the natural gas, which typically peaks during the winter
months. The volumes of natural gas sales are expected to continue to
increase as a result of continued drilling activities. The Company utilizes
commodity-based derivative instruments (natural gas futures contracts traded
on the NYMEX) as hedges to manage a portion of its exposure to this price
volatility. The futures contracts hedge committed and anticipated natural
gas purchases and sales, generally forecasted to occur within a three- to
twelve-month period. As of December 31, 1997, the Company had futures
contracts for the sale of $4.6 million of natural gas. While these
contracts have nominal carrying value, their fair value, represented by the
estimated amount that would be received upon termination of the contracts,
based on market quotes, was a net value of $277,200 at December 31, 1997.
The Company is required to maintain margin deposits ($926,100 as of December
31, 1997) with brokers for outstanding futures contracts.
On March 13, 1997, the Company amended and restated its bank credit
agreement with First National Bank of Chicago, which provides a borrowing
base of $10.0 million, subject to adequate oil and natural gas reserves. At
the request of the Company, the bank, at its sole discretion, may increase
the borrowing base to $20.0 million. As of December 31, 1997, no balance is
outstanding on the line of credit. Interest accrues at prime, with LIBOR
(London Interbank Market Rate) alternatives available at the discretion of
the Company. No principal payments are required until the credit agreement
expires on December 31, 1999.
The Company closed four public drilling partnerships during 1997. The
total amount received during 1997 was $35.5 million compared to $24.6
million for 1996, an increase of $10.9 million or 44.3%. The Company closed
a record drilling program on December 30, 1997 in the amount of $18.5
million and will drill the wells during the first quarter 1998. The Company
generally invests, as its equity contribution to each drilling partnership,
an additional sum approximating 20% of the aggregate subscriptions received
for that particular drilling partnership. As a result, the Company is
subject to substantial cash commitments at the closing of each drilling
partnership. The funds received from these programs are restricted to use
in future drilling operations. No assurance can be made that the Company
will continue to receive this level of funding from these or future
programs.
-23-
<PAGE>
In September 1997, the Company consummated a private offering of Common
Stock (the "Private Placement"), pursuant to which it issued and sold
500,000 shares at a price of $4.00 per share, and issued warrants for
125,000 shares of Common Stock exercisable during a two-year period ending
September 15, 1999 at an exercise price of $6.00 per share, resulting in
proceeds to the Company of $2.0 million. No registration rights were
granted in connection with the securities issued in the Private Placement.
In September 1997, the Company was notified that it had submitted a
successful bid for the acquisition of Columbia Gas Transmission Company's
Rimersburg natural gas gathering system, located in northern Pennsylvania.
If consummated, this transaction would occur in early to mid-1998 and would
add to the Company's existing natural gas gathering system 207 miles of
pipeline located in an area contiguous to the Company's Pennsylvania
drilling operations, at a cost to the Company of $1.4 million.
In November 1997, the Company completed a public offering of 4,077,500
shares of its common stock at a price of $6.25 per share. Net proceeds to
the Company of approximately $23 million from the sale of common stock will
be used primarily to fund development drilling on new and existing
properties, potential acquisition of producing properties and general
corporate purposes, including working capital and possible acquisitions of
complementary businesses.
On February 19, 1998, the Company offered to purchase from the
Investors their units of investment in the Company's Drilling Programs
formed prior to 1993. The total of the offer if accepted by all of the
approximately 3,500 investors would be approximately $9.9 million. The
offer expires on March 31, 1998. The Company plans to utilize capital
received from its Public Stock Offering (see Note 5) to fund this purchase
obligation.
The Company continues to pursue capital investment opportunities in
producing natural gas properties as well as its plan to participate in its
sponsored natural gas drilling partnerships, while pursuing opportunities
for operating improvements and costs efficiencies. Management believes that
the Company has adequate capital to meet its operating requirements.
New Accounting Standards
During the fourth quarter, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 128, Earnings per Share. SFAS No. 128
supersedes APB Opinion No. 15. Earnings per Share ("Opinion No. 15"), and
requires the calculation and dual presentation of basic and diluted earnings
per share ("EPS"), replacing the measures of primary and fully-diluted EPS
as reported under Opinion No. 15. SFAS No. 128 is effective for financial
statements issued for periods ending after December 15, 1997; earlier
application was not permitted. The adoption of SFAS No. 128 did not have a
material effect on the Company's EPS in 1997, 1996 or 1995.
In June, 1997, SFAS No. 130, "Reporting Comprehensive Income," and SFAS
No. 131, Disclosure about Segments of an Enterprise and Related
Information," were issued. The Company will adopt these standards in 1998.
The Company does not believe adoption will have a material effect on the
Company's financial statements and related disclosures.
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.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
-24-<PAGE>
Item 10. Directors and Executive Officers of the Company
Directors and Officers of the Company
The directors and officers of the Company, their principal occupations
for the past five years and additional information are set forth below:
Name Age Positions and Offices Held
James N. Ryan 66 Chairman, Chief Executive Officer and Director
Steven R. Williams 46 President and Director
Dale G. Rettinger 53 Chief Financial Officer, Executive Vice
President, Treasurer and Director
Ersel E. Morgan 54 Vice President of Production
Thomas F. Riley 45 Vice President of Business Development
Eric R. Stearns 39 Vice President of Exploration and Development
Darwin L. Stump 42 Controller
Roger J. Morgan 70 Secretary and Director
Vincent F. D'Annunzio 45 Director
Jeffrey C. Swoveland 42 Director
James N. Ryan served as President of the Company from 1969 to 1983 and has
served as director of the Company since 1969. Mr. Ryan was elected Chairman
and Chief Executive Officer of the Company in March 1983. Mr. Ryan focuses
on capital formation through the Company's drilling partnerships.
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
as an engineer from 1973 until 1979. A 1981 graduate of the Stanford
Graduate School of Business, Mr. Williams was employed by Texas Oil and Gas
Company as a financial analyst from 1981 until July 1982, when he joined
Exco Enterprises as Manager of Operations, and served in that capacity until
he joined the Company.
Dale G. Rettinger has served as Vice President and Treasurer of the Company
since July 1980. Additionally, Mr. Rettinger has served as President of PDC
Securities Incorporated since 1981. Mr. Rettinger was elected director in
1985 and appointed Chief Financial Officer in September 1997. Previously,
Mr. Rettinger was a partner with KMG Main Hurdman, Certified Public
Accountants, and served in that capacity from 1976 until he joined the
Company.
Ersel E. Morgan has served as Vice President of Production of the Company
since 1996. Prior to assuming this position, Mr. Morgan served as the
Company's Manager of the Land and Operations groups from 1981 until 1993 and
as Manager of Production of the Company from 1993 to 1996.
Thomas E. Riley has served as Vice President of Business Development of the
Company since April 1996. Mr. Riley co-founded and has served as President
of RNG since its inception in 1987 until the present. See "Certain
Transactions."
Eric R. Stearns has served as Vice President of Exploration and Development
of the Company since 1995. Mr. Stearns joined the Company in 1985 as a
wellsite geologist and served as Manager of Geology from 1988 until 1995.
Darwin L. Stump has served as Controller of the Company since 1980.
Previously, Mr. Stump was a senior accountant with Main Hurdman, Certified
Public Accountants, having served in that capacity from 1977 until he joined
the Company.
Roger J. Morgan, a director and Secretary of the Company since 1969, 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.
-25-
<PAGE>
Vincent F. D 'Annunzio, a director since February 1989, has for the past
five years served as President of Beverage Distributors, Inc. located in
Clarksburg, West Virginia. Mr. D'Annunzio serves as a director of Heritage
Bank in Clarksburg, West Virginia.
Jeffrey C. Swoveland, a director since March 1991, has been employed by
Equitable Resources, an oil and gas production, marketing and distribution
company, since 1994 and presently serves as Treasurer. Mr. Swoveland
previously served as Vice President and a lending officer with Mellon Bank,
N.A. from July 1989 until 1994.
The Company's By-Laws provide that the directors of the Company shall be
divided into three classes and that, at each annual meeting of stockholders
of the Company, successors to the class of directors whose term expires at
the annual meeting will be elected for a three-year term. The classes are
staggered so that the term of one class expires each year. Mr. Ryan and Mr.
D'Annunzio are members of the class whose term expires in 1998; Mr.
Rettinger and Mr. Swoveland are members of the class whose term expires in
1999; and Mr Williams and Mr. Morgan are members of the class whose term
expires in 2000. 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.
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 1998 annual meeting of
stockholders filed or to be filed with the Commission on or before April 30,
1998.
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 1998 annual meeting of stockholders filed
or to be filed with the Commission on or before April 30, 1998.
Item 13. Certain Relationships and Related Transactions
The response to this item is set forth herein in Note 8 in the Notes to
Consolidated Financial Statements.
-26-
<PAGE>
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 1997, the Company filed Form 8-K
to report the private sale of 500,000 shares of common stock.
-27-
<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 17, 1998
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 17, 1998
James N. Ryan Officer and Director
/s/ Steven R. Williams President and Director March 17, 1998
Steven R. Williams
/s/ Dale G. Rettinger Chief Financial Officer March 17, 1998
Dale G. Rettinger Executive Vice President,
Treasurer and Director
(principal financial and
accounting officer)
/s/ Roger J. Morgan Secretary and Director March 17, 1998
Roger J. Morgan
-28-
<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, 1997 and 1996 F-3 & 4
Consolidated Statements of Income - Years Ended
December 31, 1997, 1996, and 1995 F-5
Consolidated Statements of Stockholders' Equity -
Years Ended December 31, 1997, 1996, and 1995 F-6
Consolidated Statements of Cash Flows -
Years Ended December 31, 1997, 1996, and 1995 F-7
Notes to Consolidated Financial Statements F-8 - 23
2. Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
and Reserves F-24
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, 1997
and 1996, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 1997, 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.
KPMG PEAT MARWICK LLP
Pittsburgh, Pennsylvania
March 5, 1998
F-2
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1997 and 1996
<TABLE>
<S> <S> <S>
1997 1996
Assets
Current assets:
Cash and cash equivalents (includes
restricted cash of $926,100 and
$1,734,900, respectively) $46,561,000 20,615,400
Notes and accounts receivable 4,923,400 6,696,000
Inventories 297,900 567,200
Prepaid expenses 2,076,500 740,900
Total current assets 53,858,800 28,619,500
Properties and equipment:
Oil and gas properties (successful
efforts accounting method) 57,614,900 46,525,700
Pipelines 7,007,800 7,186,900
Transportation and other equipment 2,014,000 2,151,200
Land and buildings 1,155,500 1,098,200
67,792,200 56,962,000
Less accumulated depreciation,
depletion and amortization 24,222,900 22,522,300
43,569,300 34,439,700
Other assets 983,500 545,000
$98,411,600 63,604,200
</TABLE>
(Continued)
F-3<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1997 and 1996
<TABLE>
<S> <S> <S>
1997 1996
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 9,792,300 9,703,800
Accrued taxes 367,000 506,000
Other accrued expenses 2,265,000 1,505,900
Advances for future drilling contracts 23,291,600 18,397,000
Funds held for future distribution 1,659,700 864,000
Total current liabilities 37,375,600 30,976,700
Long-term debt, excluding
current maturities - 5,320,000
Other liabilities 1,684,000 1,094,200
Deferred income taxes 3,585,900 3,140,800
Commitments and contingencies
Stockholders' equity:
Common stock, par value $.01 per share;
authorized 22,250,000 shares; issued and
outstanding 15,245,758 and 10,460,753 152,500 104,600
Common stock, Class A, par value $.01 per
share; authorized 2,750,000 shares; issued
and outstanding - none - -
Additional paid-in capital 31,617,600 6,617,300
Warrants outstanding 46,300 -
Retained earnings 24,014,200 16,427,400
Unamortized stock award (64,500) (76,800)
Total stockholders' equity 55,766,100 23,072,500
$98,411,600 63,604,200
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Income
Years Ended December 31, 1997, 1996 and 1995
<TABLE>
<S> <S> <S> <S>
1997 1996 1995
Revenues:
Oil and gas well drilling operations $34,405,400 18,698,200 13,941,000
Oil and gas sales 33,390,200 26,051,100 4,150,600
Well operations and pipeline income 4,509,300 3,928,800 3,750,900
Other income 1,573,100 935,600 504,000
73,878,000 49,613,700 22,346,500
Costs and expenses:
Cost of oil and gas well drilling
operations 28,033,200 15,779,800 11,943,000
Oil and gas purchases and production
cost 30,867,600 24,190,300 4,138,700
General and administrative expenses 2,318,800 2,304,000 1,960,600
Depreciation, depletion
and amortization 2,660,300 2,309,600 2,152,100
Interest 315,900 380,000 319,700
64,195,800 44,963,700 20,514,100
Income before income taxes 9,682,200 4,650,000 1,832,400
Income taxes 2,095,400 1,100,600 350,900
Net income $ 7,586,800 3,549,400 1,481,500
Basic earnings per common share $.67 .34 .13
Diluted earnings per common
and common equivalent share $.61 .31 .13
</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, 1997, 1996 and 1995
<TABLE>
<S> <S> <S> <S> <S> <S> <S> <S>
Common stock
issued
Number Additional Warrants
of paid-in out- Retained Unamortized
shares Amount capital standing earnings stock award Total
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 11,208,6277 $112,100 7,019,800 - 12,878,000 (89,000) 19,920,900
Issuance
of common
stock:
Exercise of
employee
stock options 230,699 2,300 166,100 - - - 168,400
Purchase of
subsidiary 236,094 2,300 446,800 - - - 449,100
Amortization
of stock award 12,200 12,200
Repurchase and
cancellation
of treasury
stock (1,214,667) (12,100)(1,015,400) - - - (1,027,500)
Net income - - - - 3,549,400 - 3,549,400
Balance
December
31, 1996 10,460,753 $104,600 6,617,300 - 16,427,400 (76,800) 23,072,500
Issuance of
common
stock:
Stock offerings 4,577,500 45,800 24,903,600 46,300 - - 24,995,700
Exercise of
employee
stock options 207,505 2,100 96,700 - - - 98,800
Amortization
of stock
award 12,300 12,300
Net income - - - - 7,586,800 - 7,586,800
Balance
December
31, 1997 15,245,758 $152,500 31,617,600 46,300 24,014,200 (64,500) 55,766,100
</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, 1997, 1996 and 1995
<TABLE>
<S> <S> <S> <S>
1997 1996 1995
Cash flows from operating activities:
Net income $ 7,586,800 3,549,400 1,481,500
Adjustment to net income to reconcile
to cash provided by operating activities:
Deferred income taxes 107,700 213,900 112,600
Depreciation, depletion and amortization 2,660,300 2,309,600 2,152,100
Disposition of leasehold acreage 187,200 151,700 201,300
Employee compensation paid in stock 12,300 17,900 12,300
Decrease (increase) in notes and accounts
receivable 1,772,600 (1,480,600) (41,200)
Decrease (increase) in inventories 269,300 (349,300) 172,300
(Increase) decrease in prepaid expenses (998,200) 203,300 10,600
(Increase) decrease in other assets (453,000) (226,400) 65,800
Increase in accounts payable
and accrued expenses 1,298,400 3,938,200 42,300
Increase in advances for future
drilling contracts 4,894,600 8,327,400 869,700
Increase in funds held for
future distribution 795,700 160,000 337,300
Other (39,600) 90,700 (95,800)
Total adjustments 10,507,300 13,356,400 3,839,300
Net cash provided by operating
activities 18,094,100 16,905,800 5,320,800
Cash flows from investing activities:
Capital expenditures (13,675,100) (10,415,500) (3,910,400)
Proceeds from sale of leases 1,710,900 655,400 289,400
Proceeds from sale of fixed assets 87,600 10,800 36,700
Net cash acquired from
purchase of subsidiary - 1,450,000 -
Net cash used in investing
activities (11,876,600) (8,299,300) (3,584,300)
Cash flows from financing activities:
Proceeds from debt - 4,200,000 -
Proceeds from issuance of stock 25,048,100 135,300 46,600
Purchase of treasury stock - (1,000,000) -
Retirement of debt (5,320,000) (1,380,000) (636,300)
Net cash provided by (used in)
financing activities 19,728,100 1,955,300 (589,700)
Net increase in cash
and cash equivalents 25,945,600 10,561,800 1,146,800
Cash and cash equivalents,
beginning of year 20,615,400 10,053,600 8,906,800
Cash and cash equivalents, end of year $ 46,561,000 20,615,400 10,053,600
</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, 1997, 1996 and 1995
(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 financial
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 involved in two business segments. The different
segments are oil and gas well drilling and production, and marketing
and pipeline operations.
The Company grants credit to purchasers of oil and gas and the owners
of managed properties, substantially all of whom are located in West
Virginia, Tennessee, Pennsylvania, Ohio and Michigan.
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. An inventory of natural gas is
recorded when gas is purchased in excess of deliveries to customers
and is recorded at the lower of 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 which would consider future discounted cash
flows.
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 restor-
ation, dismantlement and abandonment costs net of salvage 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. These assets are reviewed
for impairment whenever events or changes in circumstances indicate
that the carrying amount of the assets may not be recoverable. An
impairment loss based on estimated fair value is recorded when the
review indicates that the related expected future net cash flow
(undiscounted and without interest charges) is less than the carrying
amount of the asset.
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.
Advances for Future Drilling Contracts
Represents funds received from Partnerships and other joint ventures
for drilling activities which have not been completed and accordingly
have not yet been recognized as income in accordance with the
Company's income recognition policies.
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.
The Company has a deferred compensation arrangement covering executive
officers of the Company as a supplemental retirement benefit.
(Continued)
F-9
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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.
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.
Derivatives
Gains and losses related to qualifying hedges of firm commitments or
anticipated transactions through the use of natural gas futures
contracts are deferred and recognized in income or as adjustments of
carrying amounts when the underlying hedged transaction occurs. In
order for futures contracts to qualify as a hedge, there must be
sufficient correlation to the underlying hedged transaction. The
change in the fair value of derivative instruments which do not
qualify for hedging are recognized into income currently.
Stock Compensation
On January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation," which permits entities to recognize as
expense over the vesting period the fair value of all stock-based
awards on the date of grant. Alternatively, SFAS 123 allows entities
to continue to measure compensation cost for stock-based awards using
the intrinsic value based method of accounting prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and to
provide pro forma net income and pro forma earnings per share
disclosures as if the fair value based method defined in SFAS 123 had
been applied. The Company has elected to continue to apply the
provisions of APB 25 and provide the pro forma disclosure provisions
of SFAS 123. See note 5 to the financial statements.
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 cash flows from oil and
gas properties.
(Continued)
F-10
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
New Accouting Standards
During the fourth quarter, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 128, Earnings per Share. SFAS No.
128 supersedes APB Opinion No. 15 Earnings per Share ("Opinion No.
15"), and requires the calculation and dual presentation of basic and
diluted earnings per share ("EPS"), replacing the measures of primary
EPS as reported under Opinion No. 15. SFAS No. 128 is effective for
financial statements issued for periods ending after December 15,
1997; earlier application was not permitted. The adoption of SFAS
No. 128 did not have a material effect on the Company's EPS in 1997,
1996 or 1995.
(2) Notes and Accounts Receivable
Included in other assets are noncurrent notes and accounts receivable
as of December 31, 1997 and 1996, in the amounts of $22,522 and
$5,930 net of the allowance for doubtful accounts of $129,800 and
$147,200, respectively.
The allowance for doubtful current accounts receivable as of December
31, 1997 and 1996 was $145,600 and $140,600, respectively.
(3) Long-Term Debt
On March 13, 1997, the Company amended and restated its bank credit
agreement with First National Bank of Chicago, which provides a
borrowing base of $10.0 million, subject to adequate oil and natural
gas reserves. At the request of the Company, the bank, at its sole
discretion, may increase the borrowing base to $20.0 million. As of
December 31, 1997, the balance available under the line was $10.0
million. The Company is required to pay a commitment fee of 1/8% to
1/4% on the unused portion of the credit facility. Interest accrues
at prime, with LIBOR (London Interbank Market Rate) alternatives
available at the discretion of the Company. No principal payments
are required until the credit agreement expires on December 31, 1999.
As of December 31, 1997 there was no balance outstanding. On December
31, 1996, the balance outstanding was $5,320,000. Any amounts
outstanding under the credit agreement are secured by substantially
all properties of the Company. The credit agreement requires, among
other things, the existence of satisfactory levels of natural gas
reserves, maintenance of certain working capital and tangible net
worth ratios along with a restriction on the payment of dividends.
(4) Income Taxes
The Company's provision for income taxes consisted of the following:
<TABLE>
<S> <S> <S> <S>
1997 1996 1995
Current:
Federal $1,349,600 545,600 128,400
State 638,100 341,100 109,900
Total current
income taxes 1,987,700 886,700 238,300
Deferred:
Federal (32,100) 165,800 87,300
State 139,800 48,100 25,300
Total deferred
income taxes 107,700 213,900 112,600
Total taxes $2,095,400 1,100,600 350,900
</TABLE>
(Continued)
F-11
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Income tax expense 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>
1997 1996 1995
Amount Amount Amount
Computed "expected" tax $3,291,900 1,581,000 623,000
State income tax 513,400 249,900 108,800
Percentage depletion (263,500) (205,800) (155,900)
Nonconventional source
fuel credit (846,400) (510,500) (127,300)
Adjustments to valuation
allowance (565,200) - (100,700)
Other (34,800) (14,000) 3,000
$2,095,400 1,100,600 350,900
</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, 1997 and 1996 are presented below:
<TABLE>
<S> <S> <S>
1997 1996
Deferred tax assets:
Drilling notes, principally due to
allowance for doubtful accounts $110,800 465,800
Investment tax credit carryforwards - 45,200
Alternative minimum tax credit
carryforwards (Section 29) 1,413,400 1,630,500
Other 880,600 550,800
Total gross deferred tax assets 2,404,800 2,692,300
Less valuation allowance (848,200) (1,630,500)
Deferred tax assets 1,556,600 1,061,800
Less current deferred tax assets
(included in prepaid expenses) (713,600) (376,100)
Net non-current deferred
tax assets 843,000 685,700
Deferred tax liabilities:
Plant and equipment, principally
due to differences in
depreciation and amortization (4,428,900) (3,826,500)
Total gross deferred
tax liabilities (4,428,900) (3,826,500)
Net deferred tax liability $(3,585,900) (3,140,800)
</TABLE>
The Company has evaluated each deferred tax asset and has provided a
valuation allowance where it is believed it is more likely than not
that some portion of the asset will not be realized. The valuation
allowance relates principally to the alternative minimum tax credit
carryforwards (Section 29).
The net changes in the total valuation allowance were for the year
ended December 31, 1997 a decrease of $782,300 and a decrease of
$14,700 for the year ended December 31, 1996.
At December 31, 1997, the Company has alternative minimum tax credit
carryforwards (Section 29) of approximately $1,413,400 which are
available to reduce future federal regular income taxes over an
indefinite period.
(Continued)
F-12
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(5) Common Stock
Options
Options amounting to 500,000 and 210,000 shares were granted during
1997 and 1995, respectively, to certain employees and directors under
the Company's Stock Option Plans. These options were granted with an
exercise price equal to market value as of the date of grant and vest
over a two year period. The outstanding options expire from 2000 to
2007.
The estimated fair value of the options granted during 1997 and 1995
was $3.30 and $.67 per option. The fair value was estimated using the
Black-Scholes option pricing model with the following assumptions for
the 1997 and 1995 grant, respectively: risk-free interest rate of 6.3%
and 5.8%, expected dividend yield of 0%, expected volatility of 57.4%
and 51% and expected life of 7 years.
<TABLE>
<S> <S> <S> <S>
Average Range of
Number Exercise Exercise
of Shares Price Prices
Outstanding December 31, 1994 1,956,000 $0.77 .38 - 1.63
Granted 210,000 $1.13 1.13 - 1.13
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
Granted -
Exercised (230,000) $0.72 .50 - 1.125
Expired (40,000) $0.80 .50 - 1.625
Outstanding December 31, 1996 1,582,650 $0.94 .50 - 1.625
Granted 500,000 $5.13 5.13 - 5.13
Exercised (210,000) $0.58 .50 - 1.13
Expired - $ - . - .
Outstanding December 31, 1997 1,872,650 $2.10 .94 - 5.13
</TABLE>
As of December 31, 1997, there were 1,372,650 options outstanding and
exercisable in the $.94 to $1.63 exercise price range which have a weighted
average remaining contractual life of 4.4 years and weighted average
exercise price of $.99. Also as of December 31, 1997 there were 500,000
options outstanding at a $5.13 exercise price having weighted average
remaining contractual life of 9.5 years. As of December 31, 1997 none of
these $5.13 options were exercisable.
(Continued)
F-13
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The Company accounts for its stock-based compensation plans under APB
25. For stock options granted, the option price was not less than the
market value of shares on the grant date, therefore, no compensation
cost has been recognized. Had compensation cost been determined under
the provisions of SFAS 123, the Company's net income and earnings per
share would have been the following on a pro forma basis:
<TABLE>
<S> <S> <S> <S> <S>
1997 1996
As Reported Pro Forma As Reported Pro Forma
Net income $7,586,800 $7,163,600 $3,549,400 $3,473,250
Basic earnings
per share $ .67 $ .64 $ .34 $ .33
Diluted earnings
per share $ .61 $ .58 $ .31 $ .30
</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.
Stock Purchase
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.
Stock Offerings
In September 1997, the Company completed a private offering of Common
Stock pursuant to which it issued and sold 500,000 shares at a price of
$4.00 per share and issued warrants for 125,000 shares of Common Stock
exercisable during a two-year period ending September 15, 1999 at an
exercise price of $6.00 per share, resulting in proceeds to the Company
of $2.0 million. No registration rights were granted in connection
with the securities issued in this offering.
In November 1997, the Company completed a public offering of 4,077,500
shares of its Common Stock at a price of $6.25 per share. Net proceeds
to the Company of approximately $23 million from the sale of common
stock will be used primarily to fund development drilling on new and
existing properties, potential acquisition of producing properties and
general corporate purposes, including working capital and possible
acquisitions of complementary businesses.
(Continued)
F-14
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(6) Employee Benefit Plans
The Company made 401-K Plan contributions of $171,300, $139,800 and
$71,800 for 1997, 1996 and 1995, respectively.
The Company has a profit sharing plan (the Plan) covering full-time
employees. The Company contributed $15,500, $50,000 and 28,500 to the
plan in cash during 1997, 1996 and 1995, respectively.
During 1997 and 1996, the Company expensed and established a liability
for $90,000 each year under a deferred compensation arrangement with
the executive officers of the Company.
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 and $12,200 in 1997 and 1996,
respectively.
At December 31, 1997 and 1996, the Company has recorded as other assets
$192,000 and $111,800, respectively 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) Earnings Per Share
In 1997, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 128, Earnings per share. All periods presented have been
restated to conform to SFAS No. 128.
Basic earnings per share is based on the weighted average number of
common share outstanding of 11,278,800 for 1997, 10,449,137 for 1996
and 11,056,441 for 1995.
Diluted earnings per share is based on the weighted average number of
common and common equivalent shares outstanding of 12,540,165 for 1997,
11,542,315 for 1996 and 11,611,164 for 1995. Stock options are
considered to be common stock equivalents and, to the extent
appropriate, have been added to the weighted average common shares
outstanding.
(8) Transactions with Affiliates
As part of its duties as well operator, the Company received $22,985,400
in 1997, $18,234,200 in 1996 and $11,397,000 in 1995 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. The Company provided oil and gas well drilling
services to affiliated partnerships, substantially all of the Company's
oil and gas well drilling operations was for such partnerships. The
Company also provided related services of operation of wells,
reimbursement of syndication costs, management fees, tax return
preparation and other services relating to the operation of the
partnerships. The Company received $8,113,000 in 1997, $6,435,700 in
1996 and $4,003,500 in 1995 for those services.
During 1997, 1996 and 1995, the Company paid $63,800, $35,400 and
$38,500, respectively to the Corporate Secretary's law firm for various
legal services.
(Continued)
F-15
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(9) 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. One customer, Hope Gas
Inc., a regulated public utility, accounted for 12.0% of total revenues
in 1997.
Substantially all of the Company's drilling programs contain a repurchase
provision where Investors may tender their partnership units for
repurchase at any time beginning with the third anniversary of the
first cash distribution. The provision provides that the Company is
obligated to purchase an aggregate of 10% of the initial subscriptions
per calendar year (at a minimum price of three times the most recent 12
months' cash distributions), only if such units are tendered, subject
to the Company's financial ability to do so. The maximum annual 10%
repurchase obligation, if tendered by the investors, is currently
approximately $1.0 million. The Company has adequate capital to meet
this obligation.
The Company is not party to any legal action that would materially affect
the Company's results of operations or financial condition.
(10) Supplemental Disclosure of Cash Flows
The Company paid $315,900, $380,000 and $319,700 for interest in 1997,
1996 and 1995, respectively. The Company paid income taxes in 1997,
1996 and 1995 in the amounts of $1,932,500, $664,300 and $0,
respectively.
(11) Acquisitions
On April 1, 1996, the Company acquired Riley Natural Gas Company (RNG),
a privately held gas marketing company in a stock for stock exchange
accounted for as a purchase. The acquisition has substantially
increased the Company's capabilities in the natural gas marketing area.
PDC issued 236,094 shares with a market value of $449,100, for 100% of
the outstanding common stock of RNG. Key employees of RNG have entered
into employment contracts with PDC to assure the continuity of RNG's
gas marketing operations.
The following unaudited pro forma information presents the results of
operations of the Company assuming the RNG acquisition occurred at the
beginning of 1995:
Proforma Results (unaudited)
<TABLE>
<S> <S> <S>
1996 1995
Revenues $53,091,400 $35,361,800
Net income $3,592,800 $1,546,900
Basic earnings per share $ .31 $ .13
</TABLE>
The pro forma results are presented for informational purposes only and
are not necessarily indicative of results that would have occurred had
the RNG acquisition been consummated at the beginning of 1995.
On August 6, 1996 the Company purchased an interest in 188 oil and gas
wells in West Virginia. The Company utilized its revolving credit line
to finance the purchase. The purchase increased the Company's oil and
gas reserves by 4.3 Bcf of natural gas and 27,000 barrels of oil, added
12,000 acres of leases to its leasehold inventory and increased the
Company's gathering systems by forty-nine miles. The purchase price
was $3.3 million.
(Continued)
F-16<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(12) Derivatives and Hedging Activities
The company utilizes commodity based derivative instruments as hedges
to manage a portion of its exposure to price volatility stemming from
its integrated natural gas production and marketing activities.
These instruments consist of natural gas futures contracts traded on
the New York Mercantile Exchange. The futures contracts hedge
committed and anticipated natural gas purchases and sales, generally
forecasted to occur within a 12 month period. The Company does not
hold or issue derivatives for trading or speculative purposes.
As of December 31, 1997 and 1996, the Company had futures contracts for
the sale of $4,599,700 and $3,869,900 of natural gas, respectively.
While these contracts have nominal carrying value, their fair value,
represented by the estimated amount that would be received upon
termination of the contracts, based on market quotes, was a net value
of $277,200 at December 31, 1997 and $217,800 at December 31, 1996.
The Company is required to maintain margin deposits with brokers for
outstanding futures contracts. As of December 31, 1997 and 1996,
cash in the amount of $926,100 and $1,734,900 was on deposit.
(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,
1997 1996 1995
Property acquisition cost:
Proved undeveloped
properties $ 3,109,000 543,600 167,800
Producing properties 85,100 3,211,800 218,500
Development costs 9,863,200 5,344,900 2,977,700
$13,057,300 9,100,300 3,364,000
</TABLE>
Property acquisition costs include costs incurred to purchase, lease or
otherwise acquire a property. 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,
1997 1996
Proved properties:
Intangible drilling costs $31,820,100 19,572,400
Tangible well equipment 19,700,200 21,999,600
Well equipment leased to others 4,063,600 4,063,600
Undeveloped properties 2,031,000 890,100
57,614,900 46,525,700
Less accumulated depreciation,
depletion and amortization 17,828,500 15,837,900
$39,786,400 30,687,800
</TABLE>
(Continued)
F-17
<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,
1997 1996 1995
Revenue:
Oil and gas sales $5,363,600 4,674,900 2,534,000
Expenses:
Production costs 1,206,000 963,600 596,000
Depreciation, depletion
and amortization 1,629,900 1,248,200 1,000,700
2,835,900 2,211,800 1,596,700
Results of operations for
oil and gas producing
activities before provision
for income taxes 2,527,700 2,463,100 937,300
Provision for income taxes 567,800 519,600 137,800
Results of operations for oil
and gas producing activities
(excluding corporate over-
head and interest costs) $1,959,900 1,943,500 799,500
</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 and non-conventional source fuel
tax credits and statutory depletion allowed for income tax purposes.
(Continued)
F-18
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(16) Net Proved Oil and Gas Reserves (Unaudited)
The proved reserves of oil and gas of the Company have been estimated
by an independent petroleum engineer, Wright & Company, Inc. at
December 31, 1997 and 1996 and by the Company's petroleum engineers
at December 31, 1995. These reserves have been prepared in
compliance with the Securities and Exchange Commission rules based on
year end prices. An analysis of the change in estimated quantities
of oil and gas reserves, all of which are located within the United
States, is shown below:
<TABLE>
<S> <S> <S> <S>
Oil (BBLS)
1997 1996 1995
Proved developed and
undeveloped reserves:
Beginning of year 81,000 140,000 79,000
Revisions of previous estimates (27,000) (30,000) 72,000
Beginning of year as revised 54,000 110,000 151,000
Dispositions - (49,000) -
Acquisitions - 27,000 -
Production (9,000) (7,000) (11,000)
End of year 45,000 81,000 140,000
Proved developed reserves:
Beginning of year 81,000 140,000 79,000
End of year 45,000 81,000 140,000
Gas (MCF)
1997 1996 1995
Proved developed and
undeveloped reserves:
Beginning of year 43,312,000 33,829,000 32,225,000
Revisions of previous estimates 875,000 (1,037,000) 686,000
Beginning of year as revised 44,187,000 32,792,000 32,911,000
New discoveries and extensions 2,489,000 2,613,000 2,119,000
Dispositions - (127,000) -
Acquisitions, net of sales
to partnerships 12,377,000 9,529,000 135,000
Production (1,810,000) (1,495,000) (1,336,000)
End of year 57,243,000 43,312,000 33,829,000
Proved developed reserves:
Beginning of year 35,516,000 29,326,000 27,746,000
End of year 42,411,000 35,516,000 29,326,000
</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 computed by applying year-end prices of oil and gas relating to
the Company's proved reserves to the year-end quantities of those
reserves. 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.
(Continued)
F-19
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
<TABLE>
<S> <S> <S> <S>
Years Ended December 31,
1997 1996 1995
Future estimated cash flows $159,618,000 193,800,000 99,478,000
Future estimated production
and development costs (69,265,000) (59,806,000) (29,288,000)
Future estimated income
tax expense (20,781,000) (33,499,000) (20,004,000)
Future net cash flows 69,572,000 100,495,000 50,186,000
10% annual discount for
estimated timing of cash
flows (41,636,000) (66,233,000) (29,126,000)
Standardized measure of
discounted future
estimated net cash flows $ 27,936,000 34,262,000 21,060,000
</TABLE>
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,
1997 1996 1995
Sales of oil and gas
production, net of
production costs $(4,158,000) (3,711,000) (1,938,000)
Net changes in prices
and production costs (63,573,000) 42,384,000 17,024,000
Extensions, discoveries
and improved recovery,
less related cost 3,705,000 9,659,000 4,609,000
Acquisitions, net of sales
to partnerships 13,299,000 17,775,000 294,000
Development costs incurred
during the period 9,863,000 5,345,000 2,978,000
Revisions of previous
quantity estimates 2,332,000 (2,902,000) 1,700,000
Changes in estimated
income taxes 12,718,000 (13,495,000) (6,054,000)
Accretion of discount 24,597,000 (37,107,000) (8,575,000)
Other (5,109,000) (4,746,000) (3,423,000)
$ (6,326,000) 13,202,000 6,615,000
</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-20<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(18) Business Segments
Information on the Company's operations by business segment are as follows
for the years ended December 31,:
<TABLE>
<S> <S> <S> <S>
1997 1996 1995
Revenues:
Drilling and production $44,679,600 27,940,200 20,360,100
Marketing and pipeline 27,625,300 20,737,900 1,482,400
$72,304,900 48,678,100 21,842,500
Operating Profit:
Drilling and production $10,470,900 6,207,000 3,714,300
Marketing and pipeline 272,900 191,400 (105,600)
10,743,800 6,398,400 3,608,700
General and administrative expense $(2,318,800) (2,304,000) (1,960,600)
Interest expense (315,900) (380,000) (319,700)
Interest income and other 1,573,100 935,600 504,000
Income before income taxes $ 9,682,200 4,650,000 1,832,400
Depreciation, Depletion
and Amortization:
Drilling and production $ 2,516,700 2,153,900 2,008,000
Marketing and pipeline 143,600 155,700 144,100
$ 2,660,300 2,309,600 2,152,100
Identifiable Assets:
Drilling and production $90,530,800 54,847,000 39,016,000
Marketing and pipeline 7,114,000 8,005,100 1,067,700
Corporate 766,800 752,100 536,400
$98,411,600 63,604,200 40,620,100
Capital Expenditures:
Drilling and production $13,460,300 10,059,900 3,817,700
Marketing and pipeline 157,600 124,200 86,900
Corporate 57,200 231,400 5,800
$13,675,100 10,415,500 3,910,400
</TABLE>
(Continued)
F-21
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(19) Quarterly Financial Data (Unaudited)
Summarized quarterly financial data for the years ended December 31, 1997 and
1996, are as follows:
<TABLE>
<S> <S> <S> <S> <S> <S>
1997
Quarter Year
First(1) Second(1) Third(1) Fourth(1)
Revenues $23,407,800 $14,917,400 $13,955,000 $21,597,800 $73,878,000
Cost of operations 19,490,600 12,205,000 11,409,700 18,455,800 61,561,100
Gross profit 3,917,200 2,712,400 2,545,300 3,142,000 12,316,900
General and
administrative
expenses 498,600 592,900 631,900 595,400 2,318,800
Interest expense 102,600 101,900 83,600 27,800 315,900
601,200 694,800 715,500 623,200 2,634,700
Income before
income taxes 3,316,000 2,017,600 1,829,800 2,518,800 9,682,200
Income taxes 812,400 611,700 376,800 294,500 2,095,400
Net income $2,503,600 $ 1,405,900 $ 1,453,000 $ 2,224,300 $ 7,586,800
Basic earnings
per share $ .24 $ .13 $ .14 $ .16 $ .67
Diluted earnings
per share $ .21 $ .12 $ .12 $ .16 $ .61
1996
Quarter Year
First Second(1) Third(1) Fourth(1)
Revenues $11,441,300 $10,333,700 $11,317,000 $16,521,700 $49,613,700
Cost of operations 9,203,000 8,858,900 9,996,500 14,221,300 42,279,700
Gross profit 2,238,300 1,474,800 1,320,500 2,300,400 7,334,000
General and
administrative
expenses 541,800 570,100 651,000 541,100 2,304,000
Interest expense 72,100 67,300 106,400 134,200 380,000
613,900 637,400 757,400 675,300 2,684,000
Income before
income taxes 1,624,400 837,400 563,100 1,625,100 4,650,000
Income taxes 344,400 177,500 152,600 426,100 1,100,600
Net income $1,280,000 $ 659,900 $ 410,500 $1,199,000 $ 3,549,400
Basic earnings
per share $ .12 $ .06 $ .04 $ .12 $ .34
Diluted earnings
per share $ .11 $ .06 $ .04 $ .10 $ .31
</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.
(1) These quarters include the operations of Riley Natural Gas Company acquired
on April 1, 1996, see footnote 11.
F-22<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(20) Subsequent Event (unaudited)
On February 19, 1998, the Company offered to purchase from the Investors
their units of investment in the Company's Drilling Programs formed prior
to 1993. The total of the offer if accepted by all of the approximately
3,500 investors would be approximately $9.9 million. The offer expires
on March 31, 1998. Management does not expect the entire amount of the
offer to be accepted by the investors. The Company plans to utilize
capital received from its Public Stock Offering (see Note 5) to fund this
purchase obligation.
F-23
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
AND RESERVES
Years Ended December 31, 1997, 1996 and 1995
<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
1997 $287,800 $ 4,200 $ 16,600 $275,400
1996 $389,000 $108,100 $209,300 $287,800
1995 $429,400 $210,000 $250,400 $389,000
</TABLE>
F-24
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 46,561,000
<SECURITIES> 0
<RECEIVABLES> 4,923,400
<ALLOWANCES> 287,600
<INVENTORY> 297,900
<CURRENT-ASSETS> 53,858,800
<PP&E> 67,792,200
<DEPRECIATION> 24,222,900
<TOTAL-ASSETS> 98,411,600
<CURRENT-LIABILITIES> 37,375,600
<BONDS> 0
0
0
<COMMON> 152,500
<OTHER-SE> 55,613,600
<TOTAL-LIABILITY-AND-EQUITY> 98,411,600
<SALES> 33,390,200
<TOTAL-REVENUES> 73,878,000
<CGS> 30,867,600
<TOTAL-COSTS> 64,195,800
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 4,200
<INTEREST-EXPENSE> 315,900
<INCOME-PRETAX> 9,682,200
<INCOME-TAX> 2,095,400
<INCOME-CONTINUING> 7,586,800
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 7,586,800
<EPS-PRIMARY> .67
<EPS-DILUTED> .61
</TABLE>
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
<TABLE>
<S> <S> <S> <S>
Years Ended December 31,
BASIC
1997 1996 1995
Net income for basic income
per common share $ 7,586,800 3,549,400 $1,481,500
Weighted average number of common shares
outstanding during the year 11,278,800 10,449,137 11,056,441
Basic earnings per share $ .67 $ .34 $ .13
DILUTED
Net income for basic earnings per
common share $ 7,586,800 $ 3,549,400 $ 1,481,500
Net income for diluted
earnings per share $ 7,586,800 $ 3,549,400 $ 1,481,500
Weighted average number of shares
used in calculating basic earnings
per common share 11,278,800 10,449,137 11,056,441
Shares issuable for diluted calculation 1,261,365 1,093,178 554,723
Weighted average number of shares
used in calculation of
diluted earnings per share 12,540,165 11,542,315 11,611,164
Diluted earnings per share $ .61 $ .31 $ .13
</TABLE>
E-2
