<PAGE>
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 31, 1997
REGISTRATION NO. 333-36369
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
AMENDMENT NO. 2
TO
FORM S-2
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
----------------
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
NEVADA 95-2636730
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) No.)
103 EAST MAIN STREET
BRIDGEPORT, WEST VIRGINIA 26330
(304) 842-6256
(Address, including zip code, and telephone number, including
area code, of registrant's principal executive offices)
----------------
STEVEN R. WILLIAMS, PRESIDENT
PETROLEUM DEVELOPMENT CORPORATION
103 EAST MAIN STREET
BRIDGEPORT, WEST VIRGINIA 26330
(304) 842-6256
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
----------------
COPIES TO: DAVID J. SORIN, ESQUIRE
LAURENCE S. LESE, ESQUIRE BUCHANAN INGERSOLL
DUANE, MORRIS & HECKSCHER LLP 500 COLLEGE ROAD EAST
1667 K STREET N.W., SUITE 700 PRINCETON, NJ 08540
WASHINGTON, DC 20006-1608 (609) 987-6800
(202) 776-7815
----------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS
REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH
SECTION 8(A) OF THE SECURITIES ACT OR UNTIL THIS REGISTRATION STATEMENT SHALL
THEREAFTER BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO
SAID SECTION 8(A), MAY DETERMINE.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
<PAGE>
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A +
+REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE +
+SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY +
+OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT +
+BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR +
+THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE +
+SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE +
+UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF +
+ANY SUCH STATE. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
File No. 333-36369
SUBJECT TO COMPLETION, DATED OCTOBER 31, 1997
PROSPECTUS
3,850,000 SHARES
[LOGO OF PETROLEUM DEVELOPMENT CORPORATION APPEARS HERE]
PETROLEUM DEVELOPMENT CORPORATION
COMMON STOCK
-----------
Of the 3,850,000 shares of Common Stock offered hereby, 3,500,000 shares are
being sold by the Company and 350,000 shares are being sold by the Selling
Stockholders. The Company will not receive any proceeds from the sale of shares
of Common Stock by the Selling Stockholders. See "Principal and Selling
Stockholders."
The Common Stock is currently traded on the Nasdaq National Market under the
symbol PETD. On September 23, 1997, the last reported sale price of the Common
Stock on the Nasdaq National Market was $8 11/16 per share. See "Price Range of
Common Stock."
-----------
THE SHARES OFFERED HEREBY INVOLVE A HIGH DEGREE OF RISK.
SEE "RISK FACTORS" COMMENCING ON PAGE 5.
-----------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
PRICE TO UNDERWRITING PROCEEDS TO PROCEEDS TO
PUBLIC DISCOUNT (1) COMPANY (2) SELLING STOCKHOLDERS
- ---------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Per Share............... $ $ $ $
- ---------------------------------------------------------------------------------
Total (3)............... $ $ $ $
</TABLE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
(1) Excludes a non-accountable expense allowance of $150,000 payable to the
Representative of the Underwriters. See "Underwriting" for indemnification
arrangements.
(2) Before deducting the expenses of the offering payable by the Company,
estimated at $550,000, including the non-accountable expense allowance.
(3) The Company has granted the Underwriters a 30-day option to purchase up to
an additional 577,500 shares of Common Stock solely to cover over-
allotments, if any. If all such shares are purchased, the total Price to
Public, Underwriting Discount and Proceeds to Company will be $ , $ ,
and $ , respectively. See "Underwriting."
-----------
The shares of Common Stock are offered by the several Underwriters, subject
to prior sale, when, as and if delivered to and accepted by them and subject to
their right to reject any order in whole or in part. It is expected that
certificates of such shares will be available for delivery on or about October
, 1997 at the offices of Pennsylvania Merchant Group Ltd in West
Conshohocken, Pennsylvania.
PENNSYLVANIA MERCHANT GROUP LTD
, 1997
<PAGE>
[MAP APPEARS HERE]
Map of the eastern United States, including the Company's headquarters located
in Bridgeport, West Virginia and the Company's natural gas and oil production
operation areas in the West Virginia, Pennsylvania, Ohio and Tennessee
portions of the Appalachian Basin, as well as the Company's operations in the
Michigan Basin.
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN, OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING ENTERING INTO STABILIZING BIDS, EFFECTING SYNDICATE COVERING
TRANSACTIONS OR IMPOSING PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES,
SEE "UNDERWRITING."
IN CONNECTION WITH THIS OFFERING, CERTAIN UNDERWRITERS AND SELLING GROUP
MEMBERS, IF ANY, MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE
COMMON STOCK ON THE NASDAQ NATIONAL MARKET IN ACCORDANCE WITH RULE 103 OF
REGULATION M. SEE "UNDERWRITING."
----------------
The Company's name and logo and those of its subsidiaries are trademarks of
the Company and its subsidiaries.
<PAGE>
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by, and should be read in
conjunction with, the more detailed information and consolidated financial
statements (including the notes thereto) appearing elsewhere in this
Prospectus. Unless the text indicates otherwise, the "Company" refers to
Petroleum Development Corporation and its wholly owned subsidiaries, Paramount
Natural Gas Company, Paramount Transmission Corporation, Riley Natural Gas
Company and PDC Securities Incorporated. Except where otherwise indicated, all
information in this Prospectus assumes no exercise of the Underwriters' over-
allotment option. For explanations of certain technical terms used in this
Prospectus, see "Glossary of Certain Industry Terms" on page 49.
THE COMPANY
Petroleum Development Corporation (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 of natural gas producing wells and the
expansion of its natural gas marketing activities. As of June 30, 1997, the
Company operated approximately 1,170 natural gas wells located in the
Appalachian Basin and in the Michigan Basin, and had net proved reserves of
47.3 Bcf of natural gas. The wells operated by the Company 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.
In 1996, more than 22.5 Tcf of natural gas were consumed in the United
States. Uses of natural gas include steam, process heat and co-generation for
industrial uses; feedstock for chemicals used in fertilizer and gasoline
production; electric generation and residential and commercial heating. It is
expected that natural gas will continue to increase market share relative to
other fossil fuels due to its efficiency and positive safety and environmental
characteristics. In addition, the Company believes that deregulation of certain
sectors of the natural gas industry, which has resulted in lower prices for
natural gas, is expected to increase market demand.
The majority of the wells operated by the Company are located in West
Virginia and Pennsylvania within the Appalachian Basin. The Appalachian Basin
is characterized by shallow natural gas formations, which generally have
provided for highly predictable drilling success rates. In addition, because
wells drilled in the Appalachian Basin are closer to the large demand centers
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 August 31, 1997, had drilled 24 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
producing wells located in West Virginia.
In April 1996, the Company acquired Riley Natural Gas Company ("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, as managing general partner, has sponsored limited
partnerships formed to engage in drilling operations. The Company typically
retains a 20% ownership interest in these drilling limited partnerships. In
1996, the Company raised $24.6 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 geological, engineering,
marketing and other resources necessary to support such activities.
1
<PAGE>
The Company's growth strategy is to expand its drilling operations in the
Appalachian Basin and the Michigan Basin, acquire producing properties, pursue
geographic expansion, reduce risks inherent in natural gas development and
marketing and expand its strategic relationships.
The Company was incorporated in Nevada in 1955 and commenced oil and gas
operations in 1969. Its principal executive offices are located at 103 East
Main Street, Bridgeport, West Virginia 26330, and its telephone number is (304)
842-6256.
THE OFFERING
Common Stock offered by the
Company............................. 3,500,000 shares
Common Stock offered by the Selling
Stockholders........................ 350,000 shares
Common Stock to be outstanding
after the offering.................. 14,485,753 shares(1)
Use of proceeds..................... 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.
Nasdaq National Market symbol....... PETD
- --------
(1) Based on 10,985,753 shares of Common Stock outstanding on September 15,
1997. Excludes an aggregate of 2,182,650 shares of Common Stock reserved
for issuance under the Company's stock option plans and outstanding
warrants, of which: (i) 2,057,650 shares are issuable upon the exercise of
stock options outstanding as of September 15, 1997, at a weighted average
exercise price of $1.96 per share, and (ii) 125,000 shares are issuable
upon the exercise of warrants outstanding as of September 15, 1997, at an
exercise price of $6.00 per share. See "Management--Stock Option Plans" and
"Description of Capital Stock--Warrants."
2
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------------ -----------------
1992 1993 1994 1995 1996(1)(2) 1996(1) 1997(2)
------- ------- ------- ------- ---------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Oil and gas well
drilling operations.... $14,931 $12,073 $15,190 $13,941 $18,698 $ 10,733 $ 19,277
Oil and gas sales....... 4,867 4,471 4,361 4,151 26,051 8,964 16,349
Well operations and
pipeline income and
other income........... 3,368 3,941 4,255 4,255 4,865 2,078 2,699
------- ------- ------- ------- ------- -------- --------
Total revenues.......... $23,166 $20,485 $23,806 $22,347 $49,614 $ 21,775 $ 38,325
======= ======= ======= ======= ======= ======== ========
Income before taxes and
extraordinary item..... $ 2,614 $ 1,596 $ 1,098 $ 1,832 $ 4,650 $ 2,462 $ 5,334
======= ======= ======= ======= ======= ======== ========
Net income.............. $ 1,748 $ 1,590 $ 922 $ 1,481 $ 3,549 $ 1,940 $ 3,910
======= ======= ======= ======= ======= ======== ========
Earnings per common and
common equivalent
share.................. $ 0.16 $ 0.14 $ 0.08 $ 0.13 $ 0.31 $ 0.17 $ 0.33
Weighted average common
shares outstanding..... 11,191 11,564 11,990 11,607 11,573 11,363 11,700
OTHER FINANCIAL DATA:
Depreciation, depletion
and amortization....... $ 1,671 $ 1,717 $ 1,848 $ 2,152 $ 2,310 $ 1,207 $ 1,220
Capital expenditures.... 2,830 2,630 5,607 3,910 10,416 1,093 2,712
EBITDA.................. 4,341 3,727 3,247 4,304 7,340 3,809 6,759
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1997
----------------------
ACTUAL AS ADJUSTED(3)
------ --------------
<S> <C> <C>
BALANCE SHEET DATA:
Working capital.............................. $ (313) $29,263
Total assets................................. 50,080 79,656
Total long-term debt, excluding current
maturities.................................. 3,695 3,695
Stockholders' equity......................... 27,010 56,586
</TABLE>
- --------
(1) In April 1996, the Company acquired the outstanding capital stock of RNG.
Such acquisition has been accounted for under the purchase method of
accounting, and, accordingly, the results of continuing operations of RNG
have been included in the Company's Consolidated Statement of Operations
since the date of the acquisition. See Note 12 of Notes to Consolidated
Financial Statements.
(2) In July 1996, the Company acquired 188 producing wells from Angerman
Associates, Inc. See Note 12 of Notes to Consolidated Financial Statements.
(3) Adjusted to reflect (i) the sale of 500,000 shares of Common Stock pursuant
to a private placement consummated on September 15, 1997 and the $2.0
million net proceeds therefrom and (ii) the estimated net proceeds from the
sale of 3,500,000 shares of Common Stock offered by the Company hereby.
3
<PAGE>
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------------- -----------------
1992 1993 1994 1995 1996 1996 1997
------ ------ ------ ------ ------ -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Development wells drilled:
Productive.............. 73 49 71 64 92 55 100
Dry..................... 7 7 4 8 5 3 6
------ ------ ------ ------ ------ -------- --------
Total................... 80 56 75 72 97 58 106
Net development wells
drilled:
Productive.............. 14.5 8.8 13.0 11.8 16.4 10.0 24.8
Dry..................... 1.4 1.3 0.8 1.6 1.0 0.6 1.6
------ ------ ------ ------ ------ -------- --------
Total................... 15.9 10.1 13.8 13.4 17.4 10.6 26.4
Production(1):
Oil (MBbls)............. 16 10 11 11 7 3 4
Natural gas (MMcf)...... 948 965 1,195 1,336 1,495 666 878
Equivalent MMcfs(2)..... 1,044 1,025 1,261 1,402 1,537 684 902
Average Sales Price(3):
Oil (per Bbl)........... $18.21 $16.62 $14.41 $15.80 $16.35 $ 17.78 $ 16.48
Natural gas (per Mcf)... $ 2.41 $ 2.24 $ 2.01 $ 1.75 $ 3.04 $ 3.15 $ 3.14
Average production cost
(lifting cost) per
equivalent Mcf(4)........ $ 0.48 $ 0.57 $ 0.58 $ 0.53 $ 0.63 $ 0.80 $ 0.66
</TABLE>
- --------
(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) Average sale price does not include the effect of hedge transactions.
(4) Production costs represent oil and gas operating expenses as reflected in
the financial statements of the Company.
SUMMARY RESERVE DATA
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------- AS OF
1992 1993 1994 1995 1996 JUNE 30, 1997
------- ------- ------- ------- ------- -------------
<S> <C> <C> <C> <C> <C> <C>
ESTIMATED NET PROVED
RESERVES
Oil (MBbls).............. 79 91 79 140 81 41
Natural gas (MMcf)....... 24,980 24,660 32,225 33,829 43,312 47,333
Equivalent MMcfs......... 25,448 25,206 33,699 32,669 43,798 47,579
Standardized measure of
discounted future cash
flows (after-
tax)($000)(1)........... $15,515 $14,018 $14,445 $21,060 $34,262 $16,924
</TABLE>
- --------
(1) Represents the estimated future net revenues after income taxes discounted
at 10% per annum.
4
<PAGE>
RISK FACTORS
An investment in the Common Stock involves a high degree of risk. This
Prospectus contains forward-looking statements within the meaning of Section
27A of the Securities Act of 1933, as amended (the "Securities Act"),
including, without limitation, trends impacting the natural gas industry
(including prices and market demand), the Company's success in drilling and
development activities, the expected effect of deregulation and the Company's
ability to expand geographically and implement its acquisition strategy, that
involve risks and uncertainties. The Company's actual results and development
could differ materially from those discussed or implied in the forward-looking
statements as a result of certain factors. Factors that may cause or
contribute to such differences include those discussed under "Risk Factors,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business," as well as those discussed elsewhere in this
Prospectus. The Company cautions the reader, however, that this list of
factors may not be exhaustive. Prospective investors should consider carefully
the following factors, in addition to the other information in this
Prospectus, prior to making their investment decision.
VOLATILITY OF NATURAL GAS PRICES AND MARKETS
The Company's revenues, results of operations, financial condition,
profitability, ability to obtain additional capital and future rate of growth
depend substantially on prevailing prices for natural gas, which are highly
volatile. Prices for natural gas are subject to wide fluctuations in response
to relatively minor changes in the supply of and demand for natural gas,
market uncertainty and a variety of additional factors, all of which are
beyond the control of the Company. These factors include actual and
anticipated weather conditions, changes in the demand for, and supply of,
natural gas, seasonality, the supply and price of Canadian and other foreign
natural gas, the price and availability of alternative fuels, governmental
regulations, speculation in the natural gas market and regional or national
economic conditions. These external factors and the volatile nature of the
energy markets make it difficult to accurately estimate future prices of
natural gas. Decreases in natural gas prices may materially adversely affect
the Company's financial condition, liquidity, ability to finance planned
capital expenditures, results of operations and ability to produce natural gas
economically.
In addition to general factors affecting prices for natural gas, the
Company's prices for natural gas are affected by geographic location. Prices
for natural gas sold from Appalachian wells historically have been higher than
those for natural gas produced in the Gulf Coast and Mid-Continent regions of
the United States, generally because of the geographic proximity to the large
demand centers in the Northeast natural gas markets. No assurance can be given
that this price advantage will continue. In Michigan and other new locations
of operations for the Company, it is likely that natural gas will be sold at a
lower premium compared to average national prices, and possibly even below
average national prices. The Company will attempt to evaluate the impact of
price differences prior to drilling in any new area. Furthermore, from time to
time, a surplus of natural gas occurs in West Virginia, Pennsylvania, and many
other areas of the United States. The effect of a surplus may be to reduce the
price the Company receives for its natural gas production, or to reduce the
amount of natural gas that the Company may produce and sell.
The availability of a ready market for the Company's natural gas also
depends on the proximity of the Company's natural gas reserves to pipelines,
the capacity of such pipelines and the cooperation of pipeline owners. In
addition, under certain of its natural gas sales arrangements, the Company is
subject to the risk of reduced purchases or access to pipelines under firm and
interruptible transportation agreements. Wells may temporarily be shut in for
lack of a market or due to inadequacy or unavailability of pipeline or
gathering system capacity. Any significant reduction or curtailment of the
Company's production for an extended period of time could have a material
adverse effect on its business, financial condition and results of operations.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations."
DRILLING RISKS
The selection of prospects for natural gas drilling is inherently risky, and
the Company cannot predict whether any prospect will produce commercial
quantities of natural gas. The costs of drilling, completing and operating
wells are often uncertain, and drilling operations may be curtailed, delayed
or canceled as a result of a
5
<PAGE>
variety of factors, including unexpected drilling conditions, compliance with
governmental requirements and shortages or delays in the availability of
drilling rigs and equipment, and labor shortages. Additionally, as the prices
paid to the Company by its drilling partners are frequently fixed before the
wells are drilled or are determined solely upon the well depth, the Company is
subject to the risk that prices of goods or services used in drilling could
increase, rendering its drilling contracts less profitable or unprofitable. In
addition, the natural gas industry has experienced periods of rapid cost
increases from time to time, and within short periods of time. If such
increases were to occur in the future, they would adversely affect the ability
of the Company to acquire additional natural gas leases, equipment and
supplies. A substantial industry-wide increase in drilling operations in the
United States could result in the decreased availability of drilling rigs and
gas field tubular goods. This in turn could lead to shortages of equipment and
material, which would make timely drilling and completion of wells impossible.
The Company cannot predict whether its drilling activities will prove to be
economically successful, and, if not successful, such activities will have a
material adverse effect on the Company's business, financial condition and
results of operations. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Business--Exploration and
Development Activities."
ABILITY TO REPLACE RESERVES; UNCERTAINTY OF RESERVE INFORMATION AND FUTURE
RESERVE ESTIMATES
In general, the rate of production from a natural gas property declines as
its reserves are depleted, with the rate of decline depending upon the
property's reservoir characteristics. Unless the Company conducts successful
exploration and development activities or acquires properties containing
proved reserves, the Company's proved reserves will decline. The Company's
future success is therefore dependent upon its ability to replace and expand
its existing natural gas reserves through the acquisition of producing
properties and the exploration for and development of additional natural gas
reserves. There can be no assurance that the Company's acquisition,
exploration and development activities will result in the replacement of, or
additions to, the Company's reserves.
Acquisition of economically viable producing properties generally requires,
among other things, accurate assessments of recoverable reserves, future oil
and natural gas prices, operating costs and potential environmental risks and
other liabilities. Such assessments are inherently imprecise and inexact, and
their accuracy is uncertain. Estimates of the Company's proved reserves and
future net revenues appearing elsewhere in this Prospectus and estimates made
for the Company in future periods are and will be based primarily on
independent engineering reports prepared for the Company. Natural gas reserves
cannot be precisely measured, and estimates made by other engineers might
differ materially from such estimates. There can be no assurance that
estimated prices will be realized or that the volumes projected will be
produced as indicated in a summary reserve report, if at all. Estimates of
economically recoverable natural gas reserves, and future net cash flows,
depend upon a number of factors, including assumptions concerning future
natural gas prices, future operating costs, development costs, severance and
excise taxes, workover and remedial costs, governmental regulations and other
factors beyond the control of the Company. Certain events, including
production history, acquisitions and sales of properties, changes in prices
and further drilling and development, could result in increases or decreases
of estimated proved reserves or estimates of future net revenues. The
Company's inability to replace its reserves or receive accurate reserve
estimates will likely have a material adverse effect on the Company's
business, financial condition or results of operations. See "Business--
Properties," Note 17 of Notes to Consolidated Financial Statements and the
Summary Reserve Report attached to this Prospectus as Appendix A.
WORKING CAPITAL REQUIREMENTS
The natural gas industry is capital-intensive. The Company's business and
operations require a substantial investment of working capital, principally to
finance operating activities. The Company requires significant capital
reserves in connection with its acquisition and leasing of producing and
potentially producing properties as well as for drilling expenses.
Historically, the Company has relied upon funds generated by its drilling
operations, primarily through its interests in the drilling partnerships it
has sponsored, and through bank borrowing. The use of funds generated from the
drilling partnerships is restricted to future drilling operations. The Company
also finances its other cash needs through funds from operations. There can be
no assurance that such sources will continue to be available to the Company
for its working capital needs in the future on terms acceptable to the
Company, if at all. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources."
6
<PAGE>
RISKS ASSOCIATED WITH DRILLING LIMITED PARTNERSHIPS
Since 1984, the Company has served as the managing general partner of 42
drilling limited partnerships, which have provided an aggregate of
approximately $137.0 million for drilling activities. These funds represent
the majority of the funds utilized by the Company in development activities to
date. As competition for investment capital for both public and private
drilling programs is intense, the Company competes with a number of the
companies that offer interests in drilling partnerships which have a wide
range of investment objectives and program structures. There can be no
assurance that the Company will be able to continue to raise the necessary
funds from drilling limited partnerships for investment and development, and
such inability will likely have a material adverse effect on the Company's
business, financial condition or results of operations.
The Company may be subject to certain risks with respect to its sales and
management of the drilling limited partnerships. The Company is contingently
liable as general partner for the obligations of these partnerships, including
responsibility for their day-to-day operations and liabilities that cannot be
repaid from partnership assets or insurance proceeds. Additionally, the
Company may be exposed to litigation in connection with partnership activities
and may find it necessary to advance funds on behalf of certain partnerships
to protect the value of their natural gas assets. The Company also faces
potential conflicts of interest in its role as manager of the limited
partnerships, such as provisions in limited partnership agreements: (i)
limiting the Company's ability to benefit disproportionately from discoveries
made by the limited partnerships; (ii) prohibiting the Company's acquisition
of certain property interests if to do so would conflict with the interests of
the limited partnerships; and (iii) providing for an increase in distributions
to the investor partners and a decrease in distributions to the Company for
periods ranging from three to ten years, in the event that certain performance
and earnings goals are not met by a particular well or a particular drilling
partnership. The result of such provisions could be to reduce the Company's
earnings from its participation in the drilling partnerships.
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. As
the general partner of the partnerships, the Company is also subject to a
variety of tax regulations, which may change from time to time. Additionally,
the Company and its wholly owned broker-dealer subsidiary, PDC Securities
Incorporated ("PDC Securities"), the dealer-manager of the drilling limited
partnerships, are subject to various federal and state securities regulations,
and failure to comply with these regulations could result in liability to the
Company and PDC Securities. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Business--Financing of
Drilling Activities."
DEPENDENCE ON KEY PERSONNEL
The success of the Company depends to a large degree on the efforts of its
three senior officers, James N. Ryan, Chief Executive Officer and Chairman of
the Board of Directors, Steven R. Williams, President and a director, and Dale
G. Rettinger, Executive Vice President and Chief Financial Officer and a
director. The loss of the services of any of these individuals could have a
material adverse effect on the Company's business, financial condition or
results of operations. The Company has employment agreements with each of
these individuals and maintains key-man insurance on the life of each of them,
in the amount of $5.0 million for Mr. Ryan and $1.0 million for each of
Messrs. Williams and Rettinger. In the event that the services of any of
Messrs. Ryan, Williams or Rettinger become unavailable to the Company, there
is no assurance that the Company could find a qualified replacement on
acceptable terms. See "Management--Employment and Other Agreements and
Arrangements" and "Management--Key-Man Insurance."
DERIVATIVES AND HEDGING RISKS
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 natural gas
futures contracts traded on the NYMEX. The futures contracts hedge committed
and anticipated natural gas purchases and sales, generally forecasted to occur
within a three- to twelve-month period. The Company does not hold or issue
derivatives for trading or speculative purposes. In order for futures
contracts
7
<PAGE>
to serve as effective hedges, there must be sufficient correlation to the
underlying hedged transaction. The use of hedges cannot completely alleviate
the Company's exposure to price volatility. In addition, the use of hedges
will prevent the Company from receiving the full economic benefit of increases
in oil and natural gas prices. See "Business--Hedging Activities."
COMPETITION
The Company encounters competition from numerous other natural gas
companies, drilling programs and partnerships in all areas of its operations,
including drilling and marketing natural gas, acquiring producing properties
and obtaining desirable natural gas leases. Many of these competitors possess
larger staffs and greater financial resources than the Company, which may
enable such competitors 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 on its ability to conduct its operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment. 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. The Company's
business, financial condition or results of operations could be materially
adversely affected by such competition. See "Business--Competition."
GOVERNMENTAL REGULATION
Natural gas operations are subject to various federal, state and local
government regulations, which may be changed from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties and
taxation. From time to time, regulatory agencies have imposed price controls
and limitations on production by restricting the rate of flow of natural gas
wells below actual production capability in order to conserve supplies of
natural gas. The natural gas industry is subject to extensive tax laws,
including laws relating to depletion and intangible drilling costs. Potential
changes to these laws could have adverse effects on the Company that cannot be
predicted. Legal requirements are frequently changed and are subject to
interpretation, and the Company is unable to predict the ultimate cost of
compliance with these requirements or their effect on its operations.
Additionally, the Company is impacted by state and federal regulation, such as
regulation by the Federal Energy Regulatory Commission ("FERC") of pipeline
transportation, which requires that pipelines provide firm and interruptible
transportation service on an open access basis. Although the Company believes
that it is in material compliance with all such laws and regulations, there is
no assurance that new laws or regulations or new interpretations of existing
laws and regulations will not substantially increase the costs of compliance
or otherwise adversely affect the Company's business, financial condition or
results of operations. See "Business--Governmental Regulation."
ENVIRONMENTAL RISKS AND REGULATIONS
The development, production, handling, storage, transportation and disposal
of natural gas and oil, by-products thereof and other substances and materials
produced or used in connection with natural gas operations are subject to
federal, state and local laws and regulations primarily relating to the
protection of the environment and human health. There are numerous natural
hazards involved in the drilling of natural gas and oil wells, including
unexpected or unusual formations, pressures, blowouts involving possible
damages to property and third parties, surface damages, damage to and loss of
equipment, reservoir damage, discharge of natural gas or pollutants into the
air, soil or water, oil spills and loss of reserves. No assurance can be given
that existing laws or regulations, as currently interpreted or reinterpreted
in the future, or future laws or regulations will not materially adversely
affect the Company's business, financial condition or results of operations.
The Company may thus be subject to liability for pollution, abuses of the
environment and other similar damages. See "Business--Governmental
Regulation--Environmental Regulations."
8
<PAGE>
OPERATING HAZARDS AND LIABILITIES
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's business, financial condition or results of operations 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. 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. Furthermore, 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. The occurrence of a significant
event not fully insured against could materially adversely affect the
Company's business, financial condition or results of operations. See
"Business--Operating Hazards and Insurance."
MANAGEMENT OF GROWTH RISKS
The Company has experienced significant growth in the recent past due to
increased drilling and development activities, the acquisition of natural gas
producing wells and the expansion of its natural gas marketing activities. In
1996, the Company purchased RNG, which expanded the range of the Company's
operations to include natural gas marketing, purchased 188 producing wells in
the Appalachian Basin and drilled 97 new wells. Additionally, the Company's
drilling programs have provided large amounts of capital for drilling
projects. The Company's rapid growth has placed, and is expected to continue
to place, a significant strain on the Company's financial, technical,
operational and administrative resources. The Company has relied in the past,
and expects to continue to rely in the future, on outside investment partners
and independent subcontractors that have provided the Company with drilling
funds and operational services. As part of its strategy, the Company intends
to expand into new geographical areas. Such expansion will subject the Company
to increased state and local regulation, different geological formations and
environmental conditions and the need for additional skilled and reliable
subcontractors. The success of such expansion will depend on the ability of
the Company and its geologists, engineers and subcontractors to adapt to the
requirements of such new locations. The failure of the Company to continue to
upgrade its technical, operational and administrative resources, the
occurrence of unexpected expansion difficulties or the reduced availability of
investment partners and subcontractors, could have a material adverse effect
on the Company's business, financial condition or results of operations. There
can be no assurance that the Company will be successful in achieving growth or
any other aspect of its business strategy. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Business--
Strategy."
DEPENDENCE UPON SUBCONTRACTORS
The nature of the Company's business, including the variety of skills
necessary for the exploration, drilling, extraction and marketing of natural
gas, requires specialized personnel. The Company relies on subcontractors for
many of these functions, both to take advantage of their expertise and because
of geographical and seasonal constraints. Additionally, although the Company
endeavors to ascertain the financial condition of its subcontractors, if
subcontractors fail to timely pay for materials and services, the wells
operated by the Company could be subject to materialmen's and workmen's liens.
In that event, the Company could incur additional costs in discharging such
liens. The Company's business, financial condition or results of operations
may be adversely affected by the inability of the Company to retain a
sufficient number of skilled and reliable subcontractors with adequate
financial resources. See "Business--Exploration and Developmental Activities."
9
<PAGE>
VOLATILITY OF STOCK PRICES
Stock prices for natural gas companies depend upon a variety of factors,
including the prevailing prices for natural gas, seasonality, supply and
demand for natural gas, media and analysts' reports and changes in
environmental regulations and other governmental policies. The price of the
Common Stock has been, and likely will continue to be, affected by these
factors. The trading price of the Common Stock could be subject to wide
fluctuations in response to quarter-to-quarter variations in operating results
(historically, the Company's operating results have been strongest in the
first and fourth quarters of the year), announcements of unanticipated
operating results by the Company and other events or factors. In addition, the
stock market has from time to time experienced extreme price and volume
fluctuations, which have particularly affected the market price for certain
companies in a manner often unrelated to the operating performance of these
companies. These broad market fluctuations may adversely affect the market
price of the Common Stock. See "Management's Discussion and Analysis of
Financial Conditions and Results of Operations" and "Price Range of Common
Stock."
ANTI-TAKEOVER PROVISIONS
Certain provisions of the Nevada general corporation law and the Company's
By-Laws may tend to deter potential unsolicited offers or other efforts to
obtain control of the Company that are not approved by the Board of Directors
or a majority of the Company's stockholders entitled to vote. Such provisions
may therefore deprive the stockholders of opportunities to sell shares of
Common Stock at prices higher than prevailing market prices. See "Description
of Capital Stock--Certain Corporate Anti-Takeover Provisions."
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of Common Stock in the public market following
this offering could adversely affect the market price for the Company's Common
Stock. The number of shares of Common Stock available for sale in the public
market is limited by restrictions under the Securities Act and lock-up
agreements under which the Company, its officers and directors and the Selling
Stockholders have agreed that they will not, without the prior written consent
of the Representative of the Underwriters, offer for sale, contract to sell,
sell or otherwise dispose of any shares of Common Stock for a period of 180
days from the date of this Prospectus. After these contractual restrictions
expire, such persons will be permitted to sell these shares in the public
market, subject only to applicable restrictions prescribed by Rule 144 of the
Securities Act. Immediately following the offering, 14,485,753 shares of
Common Stock will be outstanding. Of these shares, an aggregate of 13,015,739
shares, consisting of (i) the 3,850,000 shares sold in this offering (plus any
additional shares sold upon the Underwriters' exercise of their over-allotment
option) and (ii) an aggregate of 9,165,739 shares, without taking into account
the lock-up agreements referred to above, issued and outstanding prior to the
date the Registration Statement is declared effective will be freely
transferable by persons other than "affiliates" of the Company without
restriction or further registration under the Securities Act. The remaining
shares may not be sold in the absence of registration under the Securities Act
unless an exemption from registration is available, including an exemption
afforded by Rule 144. See "Shares Eligible for Future Sale."
NO DIVIDENDS
The Company has never declared or paid dividends on its Common Stock and
does not anticipate paying any dividends in the foreseeable future. The
Company intends to retain any earnings for operations and expansion of its
business. See "Dividend Policy."
10
<PAGE>
USE OF PROCEEDS
The net proceeds from the sale of the 3,500,000 shares of Common Stock
offered hereby by the Company at an assumed offering price of $8 11/16 per
share are estimated to be $27.6 million after deduction of underwriting
discounts and estimated offering expenses payable by the Company. The Company
will not receive any proceeds from the sale of the shares of Common Stock by
the Selling Stockholders. See "Principal and Selling Stockholders."
The Company intends to use the net proceeds from this offering for
development drilling on new and existing properties, potential acquisition of
producing properties and for general corporate purposes, including working
capital and possible acquisitions of complementary businesses, including, for
example, the Company's possible acquisition of a natural gas gathering system
at a cost to the Company of $1.4 million. See "Business--Exploration and
Development Activities--Transportation." Although the Company reviews and
considers possible acquisitions on an ongoing basis, other than as set forth
in the preceding sentence, no specific acquisitions are being negotiated or
planned as of the date of this Prospectus. The actual use of proceeds may vary
depending on the Company's assessment of the relative attractiveness of
available acquisition and development opportunities. Pending such uses, the
net proceeds to the Company from this offering will be invested in short-term,
investment-grade, interest-bearing instruments.
PRICE RANGE OF COMMON STOCK
The following table sets forth, for the periods indicated, the high and low
daily sales prices per share of the Common Stock as reported by the Nasdaq
National Market for the periods indicated. The Common Stock is traded on the
Nasdaq National Market under the symbol PETD.
<TABLE>
<CAPTION>
HIGH LOW
-------- --------
<S> <C> <C>
YEAR ENDED DECEMBER 31, 1995:
First Quarter.............................................. $1 3/8 $ 7/8
Second Quarter............................................. 1 9/16 1 1/16
Third Quarter.............................................. 1 3/8 1
Fourth Quarter............................................. 1 5/8 31/32
YEAR ENDED DECEMBER 31, 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 1/2
YEAR ENDED DECEMBER 31, 1997:
First Quarter.............................................. $5 1/8 $3 9/16
Second Quarter............................................. 5 5/16 3
Third Quarter (through September 23, 1997)................. 11 7/16 4 11/16
</TABLE>
The last reported sale price of the Common Stock on the Nasdaq National
Market on September 23, 1997 was $8 11/16 per share.
As of June 30, 1997, there were approximately 1,794 record holders of the
Company's Common Stock.
DIVIDEND POLICY
The Company has never declared or paid cash dividends on its Common Stock
and does not anticipate paying any cash dividends in the foreseeable future.
The Company currently intends to retain its earnings for operations and
expansion of its business. Furthermore, the Company's credit agreement
prohibits the Company from paying dividends in excess of 50% of the Company's
net income for the respective fiscal year. The declaration and payment by the
Company of any dividends on its Common Stock in the future and the amount
thereof will, nevertheless, be at the discretion of the Company's Board of
Directors and will depend upon the Company's operating results, financial
condition, cash requirements, future prospects and other factors deemed
relevant by the Company's Board of Directors.
11
<PAGE>
CAPITALIZATION
The following table sets forth the capitalization of the Company as of June
30, 1997 and as adjusted to give effect to the sale of 3,500,000 shares of
Common Stock offered by the Company hereby (assuming an offering price of $8
11/16 per share and after deducting the underwriting discount and estimated
offering expenses payable by the Company). See "Use of Proceeds."
<TABLE>
<CAPTION>
JUNE 30, 1997
-----------------------
ACTUAL AS ADJUSTED(1)
------- --------------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt(2)...................................... $ 3,695 $ 3,695
------- -------
Stockholders' equity:
Common Stock, Class A, $0.01 par value;
authorized 2,750,000 shares; none issued............ -- --
Common Stock, $0.01 par value;
authorized 22,250,000 shares; 10,485,753 shares
issued and outstanding; 14,485,753 shares issued and
outstanding, as adjusted(1)(3)...................... 105 145
Additional paid-in capital............................. 6,639 36,129
Warrants outstanding................................... -- 46
Retained earnings...................................... 20,337 20,337
Unamortized stock award................................ (71) (71)
------- -------
Total stockholders' equity........................... 27,010 56,586
------- -------
Total capitalization............................... $30,705 $60,281
======= =======
</TABLE>
- --------
(1) Reflects a pro forma adjustment to include 500,000 shares of Common Stock
issued and sold by the Company on September 15, 1997. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
(2) For information concerning the Company's long-term debt, see Note 3 of
Notes to Consolidated Financial Statements.
(3) Excludes an aggregate of 2,182,650 shares of Common Stock reserved for
issuance under the Company's stock option plans and outstanding warrants,
of which: (i) 2,057,650 shares are issuable upon the exercise of stock
options outstanding as of September 15, 1997, at a weighted average
exercise price of $1.96, and (ii) 125,000 shares are issuable upon the
exercise of warrants outstanding as of September 15, 1997, at an exercise
price of $6.00 per share. See "Management--Stock Option Plans" and
"Description of Capital Stock."
12
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data as of December 31, 1992,
1993, 1994, 1995 and 1996 and for each of the years in the five-year period
ended December 31, 1996 have been derived from the audited consolidated
financial statements of the Company. The following selected consolidated
financial data as of June 30, 1996 and 1997 and for each of the six-month
periods ended June 30, 1996 and 1997 have been derived from unaudited
consolidated financial statements and include all adjustments (consisting only
of normal recurring accruals) that the Company considers necessary for a fair
presentation of such financial information for those periods. The results of
operations for the six months ended June 30, 1997 are not necessarily
indicative of the results that may be expected for any other interim period or
for the full year. The data set forth below should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements of the Company and
related notes included elsewhere herein. All information is in thousands,
except per share data.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------------ -----------------
1992 1993 1994 1995 1996 1996 1997
------- ------- ------- ------- ------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Revenues:
Oil and gas well
drilling operations... $14,931 $12,073 $15,190 $13,941 $18,698 $ 10,733 $ 19,277
Oil and gas sales...... 4,867 4,471 4,361 4,151 26,051 8,964 16,349
Well operations and
pipeline income....... 2,936 3,843 3,730 3,750 3,929 1,847 2,248
Other income........... 432 98 525 504 936 231 451
------- ------- ------- ------- ------- -------- --------
Total revenues........ 23,166 20,485 23,806 22,347 49,614 21,775 38,325
------- ------- ------- ------- ------- -------- --------
Costs and expenses:
Cost of oil and gas
well drilling
operations............ 13,347 11,100 14,289 11,943 15,780 8,770 15,759
Oil and gas purchases
and production
costs................. 3,643 4,120 4,067 4,139 24,190 8,084 14,716
General and
administrative
expenses.............. 1,837 1,897 2,204 1,961 2,304 1,112 1,092
Depreciation, depletion
and amortization...... 1,671 1,717 1,848 2,152 2,310 1,208 1,220
Interest............... 54 55 300 320 380 139 204
------- ------- ------- ------- ------- -------- --------
Total costs and
expenses............. 20,552 18,889 22,708 20,515 44,964 19,313 32,991
------- ------- ------- ------- ------- -------- --------
Income before income
taxes and extraordinary
item................... 2,614 1,596 1,098 1,832 4,650 2,462 5,334
Income taxes............ 866 275 177 351 1,101 522 1,424
------- ------- ------- ------- ------- -------- --------
Income before
extraordinary item..... 1,748 1,321 921 1,481 3,549 1,940 3,910
Extraordinary item net
of income taxes........ -- 269 -- -- -- -- --
------- ------- ------- ------- ------- -------- --------
Net income.............. $ 1,748 $ 1,590 $ 921 $ 1,481 $ 3,549 $ 1,940 $ 3,910
======= ======= ======= ======= ======= ======== ========
Earnings per common and
common equivalent
share.................. $ 0.16 $ 0.14 $ 0.08 $ 0.13 $ 0.31 $ 0.17 $ 0.33
======= ======= ======= ======= ======= ======== ========
Average common and
common
equivalent shares
outstanding
during the year
(period)............... 11,191 11,564 11,990 11,607 11,573 11,363 11,700
======= ======= ======= ======= ======= ======== ========
BALANCE SHEET DATA (END
OF PERIOD):
Working capital......... $ (590) $ 289 $(1,614) $(1,520) $(2,357) $ 717 $ (313)
Total assets............ 34,632 36,413 38,325 40,620 63,604 38,465 50,080
Long-term debt,
excluding current
maturities............. 3,969 3,167 3,100 2,500 5,320 2,700 3,695
Stockholders' equity.... 15,347 17,236 18,381 19,921 23,072 21,442 27,010
</TABLE>
13
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion should be read in conjunction with the Consolidated
Financial Statements of the Company and related notes included therein.
OVERVIEW
The Company is a regional independent energy company engaged primarily in
the development, production and marketing of natural gas. The Company has
drilled and produced natural gas and oil in the Appalachian Basin since 1969,
and currently operates approximately 1,170 natural gas wells in West Virginia,
Ohio, Pennsylvania, Michigan and Tennessee. While early activities included
drilling and operating producing oil wells, all of the Company's current
drilling activities, and more than 95% of its reserve and production value,
result from natural gas operations. In 1997, the Company expanded its drilling
activities to include drilling in the Antrim shale formation of the Michigan
Basin.
The Company derives the majority of its revenues from natural gas drilling
operations and natural gas sales, and also generates revenues from natural gas
marketing (aggregating and reselling) and natural gas gathering and
transportation. The Company drills wells for Company-sponsored drilling
partnerships as well as for Company-owned properties. The Company also engages
in the marketing of third party natural gas production and earns operating and
pipeline fees for managing wells and gathering natural gas.
Cost of oil and gas well drilling operations includes the direct costs of
drilling wells. Oil and gas purchases and production costs include natural gas
purchased for resale in the Company's marketing activities as well as the
costs of production for Company-owned and other wells.
The Company's results will vary based in part on changes in the market price
of natural gas. Since 1992, the Company's annual average natural gas sales
price has ranged from a high of $3.04 per Mcf in 1996 to a low of $1.75 per
Mcf in 1995. For the year ended December 31, 1996, and for the six months
ended June 30, 1997, the Company's average sales prices for natural gas were
$3.04 per Mcf and $3.14 per Mcf, respectively. Natural gas drilled in the
Appalachian Basin 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, due to the Appalachian Basin's proximity to the large demand
centers in the northeastern United States. From October 1996 to September
1997, Appalachian natural gas on the CNG system received a premium which
varied from $0.20 per Mcf to $0.55 per Mcf and averaged almost $0.33 per Mcf
for that time period.
As part of its business strategy, during 1996 the Company made two
acquisitions. On April 1, 1996, the Company acquired RNG in exchange for
shares of the Company's Common Stock having a market value of $449,100. RNG is
an Appalachian Basin natural gas marketing company that specializes in the
acquisition and aggregation of Appalachian Basin natural gas production. The
acquisition was accounted for by the Company as a purchase and is reflected as
such in the Company's financial statements for 1996. Natural gas purchased
from third parties is resold with a lower margin than natural gas produced by
the Company.
In July 1996, the Company completed the acquisition of 188 natural gas wells
located primarily in Gilmer County, West Virginia from Angerman Associates,
Inc., a Pittsburgh-based production company, for a cash purchase price of $3.3
million. Independent petroleum engineers have estimated remaining proved
developed reserves in these properties at 4.3 Bcf of natural gas and 27,000
barrels of oil on December 31, 1996. Net production per day from the
acquisition averaged approximately 750 Mcf and 8 Bbls during 1996.
The Company believes that its available funds, together with cash flow
expected to be generated from operations, existing credit facilities and the
net proceeds of this offering will be adequate to satisfy operations for at
least 24 months following the completion of this offering.
14
<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 periods indicated.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------------- -----------------
1992 1993 1994 1995 1996 1996 1997
------ ------ ------ ------ ------ -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Production(1):
Oil (MBbls)............. 16 10 11 11 7 3 4
Natural Gas (MMcf)...... 948 965 1,195 1,336 1,495 666 878
Equivalent MMcfs(2)..... 1,044 1,025 1,261 1,402 1,537 684 902
Average sales price(3):
Oil (per Bbl)........... $18.21 $16.62 $14.41 $15.80 $16.35 $ 17.78 $ 16.48
Natural gas (per Mcf)... $ 2.41 $ 2.24 $ 2.01 $ 1.75 $ 3.04 $ 3.15 $ 3.14
Average production cost
(lifting cost) per
equivalent Mcf(4)........ $ 0.48 $ 0.57 $ 0.58 $ 0.53 $ 0.63 $ 0.80 $ 0.66
</TABLE>
- --------
(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) Average sale price does not include the effect of hedge transactions.
(4) Production costs represent oil and gas operating expenses as reflected in
the financial statements of the Company.
RESULTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1997 COMPARED WITH JUNE 30, 1996
Revenues. Total revenues for the six months ended June 30, 1997 were $38.3
million compared to $21.8 million for the six months ended June 30, 1996, an
increase of approximately $16.5 million, or 75.7%. Such increase was a result
of increased drilling revenues and oil and gas sales. Drilling revenues for
the six months ended June 30, 1997 were $19.3 million compared to $10.7
million for the six months ended June 30, 1996, an increase of approximately
$8.6 million, or 80.4%. Such increase resulted from higher volumes of drilling
and completion activities, due to increased levels of drilling partnership-
related financing. Oil and gas sales for the six months ended June 30, 1997
were $16.3 million compared to $9.0 million for the six months ended June 30,
1996, an increase of approximately $7.3 million, or 81.1%. Such increase was
due primarily to the natural gas marketing activities of RNG, which accounted
for $6.9 million of the increase. Increased natural gas production was offset
in part by lower average sales prices from the Company's producing properties.
Well operations and pipeline income for the six months ended June 30, 1997
were $2.2 million compared to $1.8 million for the six months ended June 30,
1996, an increase of approximately $400,000, or 22.2%. Such increase resulted
from an increase in the number of wells operated by the Company. Other income
for the six months ended June 30, 1997 was $452,000 compared to $231,000 for
the six months ended June 30, 1996, an increase of approximately $221,000, or
95.7%. Such increase resulted from interest earned on higher average cash
balances together with a gain on the sale of equipment.
Costs and expenses. Costs and expenses for the six months ended June 30,
1997 were $33.0 million compared to $19.3 million for the six months ended
June 30, 1996, an increase of approximately $13.7 million, or 71.0%. Oil and
gas well drilling operations costs for the six months ended June 30, 1997 were
$15.8 million compared to $8.8 million for the six months ended June 30, 1996,
an increase of approximately $7.0 million, or
15
<PAGE>
79.5%. Such increase resulted from additional expenses resulting from
increased drilling activity. Oil and gas purchases and production costs for
the six months ended June 30, 1997 were $14.7 million compared to $8.1 million
for the six months ended June 30, 1996, an increase of approximately $6.6
million, or 81.5%. Such increase was due primarily to purchases of natural gas
for resale by RNG. General and administrative expenses for the six months
ended June 30, 1997 remained relatively constant at $1.1 million.
Net income. Net income for the six months ended June 30, 1997 was $3.9
million compared to net income of $1.9 million for the six months ended June
30, 1996, an increase of approximately $2.0 million, or 105.3%.
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 the 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 ENDED DECEMBER 31, 1995 COMPARED WITH DECEMBER 31, 1994
Revenues. Total revenues for the year ended December 31, 1995 were $22.3
million compared with $23.8 million for the year ended December 31, 1994, a
decrease of approximately $1.5 million, or 6.3%. Drilling revenues for the
year ended December 31, 1995 were $13.9 million compared with $15.2 million
for the year ended December 31, 1994, a decrease of approximately $1.3
million, or 8.6%. This decrease was due to a slight decrease in drilling and
completion activities in 1995 compared to 1994. Oil and gas sales for the year
ended December 31, 1995 were $4.2 million compared to $4.4 million for the
year ended December 31, 1994, a decrease of approximately $200,000, or 4.5%.
This decrease was the result of lower average natural gas sales prices offset
by increased volumes of natural gas sold. Well operations and pipeline income
for the year ended December 31, 1995 remained relatively constant at $3.7
million. Other income for the year ended December 31, 1995 was $504,000
compared to $524,000 for the year ended December 31, 1994, a decrease of
approximately $20,000, or 3.8%.
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<PAGE>
Costs and expenses. Costs and expenses for the year ended December 31, 1995
were $20.5 million, compared to $22.7 million for the year ended December 31,
1994, a decrease of approximately $2.2 million, or 9.7%. Oil and gas well
drilling operations costs for the year ended December 31, 1995 were $11.9
million compared to $14.3 million for the year ended December 31, 1994, a
decrease of approximately $2.4 million, or 16.8%. Such decrease resulted from
decreased drilling and completion activities. Oil and gas purchases and
production costs for the year ended December 31, 1995 were $4.1 million
compared to $4.0 million for the year ended December 31, 1994, an increase of
approximately $100,000, or 2.5%. General and administrative expenses for the
year ended December 31, 1995 were $2.0 million, compared to $2.2 million for
the year ended December 31, 1994, a decrease of approximately $200,000, or
9.1%. This decrease was a result of a general Company-wide cost-cutting
program.
Net income. Net income for the year ended December 31, 1995 was $1.5 million
compared to $922,000 for the year ended 1994, an increase of approximately
$578,000, or 62.7%.
QUARTERLY RESULTS OF OPERATIONS
The following table presents certain condensed unaudited quarterly financial
information for each of the ten most recent quarters in the period ended June
30, 1997. This information is derived from unaudited consolidated financial
statements of the Company that include, in the opinion of the Company, all
adjustments (consisting only of normal recurring adjustments) necessary for a
fair presentation of results of operations for such periods, when read in
conjunction with the audited Consolidated Financial Statements of the Company
and notes thereto appearing elsewhere in this Prospectus. All information is
in thousands, except per share data.
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------------------------------------------
MAR. 31, JUNE 30, SEPT. 30, DEC. 31, MAR. 31, JUNE 30, SEPT. 30, DEC. 31, MAR. 31, JUNE 30,
1995 1995 1995 1995 1996 1996 1996 1996 1997 1997
-------- -------- --------- -------- -------- -------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
REVENUES:
Oil and gas well
drilling operations.. $7,294 $2,379 $1,857 $2,411 $7,987 $2,746 $2,991 $4,974 $13,261 $6,016
Oil and gas sales..... 1,162 1,018 800 1,171 2,467 6,497 7,168 9,919 8,767 7,581
Well operations and
pipeline income...... 1,002 970 869 909 902 946 1,018 1,063 1,131 1,118
Other income.......... 79 66 56 303 85 145 140 566 249 203
------ ------ ------ ------ ------ ------ ------ ------ ------- ------
Total revenues........ 9,537 4,433 3,582 4,794 11,441 10,334 11,317 16,522 23,408 14,918
------ ------ ------ ------ ------ ------ ------ ------ ------- ------
COSTS AND EXPENSES:
Costs of oil and gas
well drilling
operations........... 6,136 1,990 1,355 2,462 6,502 2,268 2,455 4,555 11,319 4,439
Oil and gas purchases
and production costs. 1,310 1,096 818 915 2,035 6,049 6,958 9,148 7,561 7,155
General and
administrative
expenses............. 450 521 601 389 542 571 651 541 499 593
Depreciation,
depletion, and
amortization......... 588 536 591 436 666 542 583 519 610 611
Interest.............. 84 76 71 89 72 67 107 134 103 102
------ ------ ------ ------ ------ ------ ------ ------ ------- ------
Total costs and
expenses............. 8,568 4,219 3,436 4,291 9,817 9,497 10,754 14,897 20,092 12,900
------ ------ ------ ------ ------ ------ ------ ------ ------- ------
Income before income
taxes................. 969 214 146 503 1,624 837 563 1,625 3,316 2,018
Income taxes........... 240 53 36 21 344 177 153 426 812 612
------ ------ ------ ------ ------ ------ ------ ------ ------- ------
Net income............. $ 729 $ 161 $ 110 $ 482 $1,280 $ 660 $ 410 $1,199 $ 2,504 $1,406
====== ====== ====== ====== ====== ====== ====== ====== ======= ======
Earnings per common and
common equivalent
share................. $ 0.06 $ 0.02 $ 0.01 $ 0.04 $ 0.11 $ 0.06 $ 0.04 $ 0.10 $ 0.21 $ 0.12
====== ====== ====== ====== ====== ====== ====== ====== ======= ======
</TABLE>
The Company historically has received the majority of its total annual
revenues during the first and fourth quarters of each year. Such pattern is
attributable to (i) the seasonal demand for natural gas, which is typically
greatest during the winter months of the first and fourth quarters and (ii)
the generation of funds from the drilling
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<PAGE>
activities of the Company-sponsored limited partnerships. The Company
recognizes revenues from drilling operations on the percentage of completion
method as wells are drilled, rather than when funds are received. As the last
partnership to close in a given year is typically the largest partnership of
the year, the Company receives substantial funds during the fourth quarter
from its year-end drilling partnerships and recognizes revenues from such
receipt in the subsequent first quarter as the wells for such drilling
partnership are drilled. Therefore, the Company's quarterly earnings may vary
considerably due to the impact of seasonality and the timing of receipt of
investment funds.
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 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
June 30, 1997, the Company had futures contracts for the sale of $2.4 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
$51,100 at June 30, 1997. The Company is required to maintain margin deposits
($300,000 as of June 30, 1997) with brokers for outstanding futures contracts.
On January 31, 1996, the Company repurchased 1,200,000 shares of its Common
Stock, for $0.83 per share, from PNC Bank, N.A. This repurchase was pursuant
to an option agreement, which was obtained in connection with a debt
restructuring in 1990. These shares, which represented approximately 11% of
the shares of the Company's Common Stock then outstanding, were retired by the
Company.
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 September 15, 1997, the balance
available under the line was $6.5 million. 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 its first public drilling partnership of 1997 in the
second quarter and drilled the wells funded thereby in the second and third
quarters of 1997. The Company closed its second public drilling partnership of
1997 in September 1997 and plans to drill the wells funded thereby during the
remainder of 1997. The Company's first and second drilling programs of 1997
closed with funding approximately 62% and 152%, respectively, higher than the
first and second drilling programs of 1996. The Company expects to close two
additional partnerships in 1997. Typically, the last partnership closed during
each year is the largest partnership of the year; the last partnership of 1996
raised $15.3 million. 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.
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<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.
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 cost efficiencies. Management believes that the
Company has adequate capital to meet its operating requirements.
NEW ACCOUNTING STANDARDS
In February 1997, the Financial Accounting Standards Board issued 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 is not permitted. Accordingly, EPS for the three- and six-
month periods ended June 30, 1997 and 1996 presented on the accompanying
statements of income are calculated under the guidance of Opinion 15.
Under SFAS No 128, basic EPS would have been $0.37 and $0.19 and diluted EPS
would have been $0.33 and $0.17 per share for the six months ended June 30,
1997 and 1996, respectively. Also under SFAS No. 128, basic EPS would have
been $0.13 and $0.06 and diluted EPS would have been $0.12 and $0.06 per share
for the quarters ended June 30, 1997 and 1996, respectively.
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.
19
<PAGE>
BUSINESS
INTRODUCTION
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 June 30, 1997, the
Company operated approximately 1,170 natural gas wells located in the
Appalachian Basin and in the Michigan Basin, and had net proved reserves of
47.3 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 August 31, 1997, had drilled 24 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 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 1996, the Company raised $24.6
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.
. 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.
20
<PAGE>
. 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. Appalachian Basin producers have recently
experienced price differentials averaging $0.15 per Mcf to $0.30 per Mcf on an
annual average as compared to production in the Gulf Coast and Mid-Continent
regions of the United States. From October 1996 to September 1997, Appalachian
natural gas on the CNG system received a premium ranging from $0.20 per Mcf to
$0.55 per Mcf and averaged almost $0.33 per Mcf for that time period.
In the early 1990'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 450 shallow natural
gas wells since 1992. In the first six months of 1997, the Company drilled 106
wells, compared to 97 for the entire 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 June 30, 1997, the Company had 22,075 net
undeveloped acres in the Michigan Basin and 37,800 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.
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.
Toward that end, in 1996, in order to further penetrate its existing
development area, the Company purchased 188 producing wells in the Appalachian
Basin. 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 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.
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<PAGE>
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 drilling development, rather than exploratory, wells, shallow wells 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, in 1996, the Company
acquired RNG, an experienced Appalachian Basin natural gas marketer. The
Company intends to continue to expand its market 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 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 June 30, 1997, the
Company had a total leasehold inventory of approximately 129,835 gross acres
and 128,175 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 1996, the Company drilled a total of 97
wells, of which five were dry holes. In 1997, through June 30, the Company
drilled a total of 106 wells, of which six 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
22
<PAGE>
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.
WELL OPERATIONS AND PRODUCTION
The Company currently operates approximately 1,170 natural gas wells in the
Appalachian Basin and 24 wells in the Michigan 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.
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
23
<PAGE>
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.
PROPERTIES
DRILLING ACTIVITY
The following table summarizes the Company's drilling activity for the years
ended December 31, 1992, 1993, 1994, 1995 and 1996 and the six months ended
June 30, 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>
<CAPTION>
DEVELOPMENT WELLS
1992 1993 1994 1995 1996 1997*
------------- ------------- ------------- ------------- ------------- --------------
DRILLED NET DRILLED NET DRILLED NET DRILLED NET DRILLED NET DRILLED NET
------- ----- ------- ----- ------- ----- ------- ----- ------- ----- -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total wells............. 80 15.86 56 10.00 75 13.76 72 13.40 97 17.44 106 26.42
Productive natural gas
wells.................. 73 14.47 49 8.75 71 13.00 64 11.80 92 16.46 100 24.80
Dry holes............... 7 1.39 7 1.25 4 0.76 8 1.60 5 0.98 6 1.62
</TABLE>
- --------
*Through June 30, 1997
SUMMARY OF PRODUCTIVE WELLS
The table below shows the number of the Company's productive gross and net
wells at June 30, 1997.
<TABLE>
<CAPTION>
WELLS
---------------------------
GAS OIL
------------- -------------
LOCATION GROSS NET GROSS NET
-------- ------ ------ ------ ------
<S> <C> <C> <C> <C>
Michigan...................................... 23 9.89 -- --
Ohio.......................................... 16 5.50 9 2.03
Pennsylvania.................................. 163 35.63 -- --
Tennessee..................................... 1 0.57 44 16.73
West Virginia................................. 967 421.90 10 4.46
------ ------ ------ ------
Total....................................... 1,170 473.49 63 23.22
====== ====== ====== ======
</TABLE>
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 the
Company's petroleum engineers for 1994 and 1995 and by Wright & Company, Inc.
independent petroleum engineers ("Wright & Company"), for 1996 and 1997, to be
47,333,000 Mcf of natural gas and 41,000 Bbls of oil at June 30, 1997;
43,312,000 Mcf of natural gas and 81,000 Bbls of oil at December 31, 1996;
33,829,000 Mcf of natural gas and 140,000 Bbls of oil at December 31, 1995;
and 32,225,000 Mcf of natural gas and 79,000 Bbls of oil at December 31, 1994.
24
<PAGE>
The Company's approximate net proved developed reserves were estimated, by
the Company for 1994 and 1995 and by Wright & Company for 1996 and 1997, to be
38,240,000 Mcf of natural gas and 41,000 Bbls of oil at June 30, 1997;
35,516,000 Mcf of natural gas and 81,000 Bbls of oil at December 31, 1996;
29,326,000 Mcf of natural gas and 140,000 Bbls of oil at December 31, 1995;
and 27,746,000 Mcf of natural gas and 79,000 Bbls of oil at December 31, 1994.
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 June 30, 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 in 1994 and 1995 and by
Wright & Company in 1996 and 1997, to be $16.9 million as of June 30, 1997,
$34.3 million as of December 31, 1996, $21.1 million as of December 31, 1995,
and $14.4 million as of December 31, 1994. These amounts are based on period-
end prices at the respective dates. Since December 31, 1996, prices have
decreased due to seasonal demand. 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 June 30, 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 period-end prices. An analysis of the change
in estimated quantities of natural gas and oil reserves from January 1, 1997
to June 30, 1997, all of which are located within the United States, is shown
below:
<TABLE>
<CAPTION>
NATURAL GAS (MCF)
-----------------
<S> <C>
Proved developed and undeveloped reserves:
Beginning of year (January 1, 1997)......................... 43,312,000
Revisions of previous estimates............................. (3,299,000)
----------
Beginning of year as revised................................ 40,013,000
New discoveries and extensions.............................. 8,198,000
Dispositions................................................ --
Acquisitions................................................ --
Production.................................................. (878,000)
----------
End of period (June 30, 1997)............................... 47,333,000
==========
Proved developed reserves:
Beginning of year (January 1, 1997)......................... 35,516,000
==========
End of period (June 30, 1997)............................... 38,240,000
==========
</TABLE>
25
<PAGE>
<TABLE>
<CAPTION>
OIL (BBLS)
----------
<S> <C>
Proved developed and undeveloped reserves:
Beginning of year (January 1, 1997)................................ 81,000
Revisions of previous estimates.................................... (36,000)
-------
Beginning of year as revised....................................... 45,000
Dispositions....................................................... --
Acquisitions....................................................... --
Production......................................................... (4,000)
-------
End of period (June 30, 1997)...................................... 41,000
=======
Proved developed reserves:
Beginning of year (January 1, 1997)................................ 81,000
=======
End of period (June 30, 1997)...................................... 41,000
=======
</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
derived by applying current natural gas and oil prices to estimated future
production. Future production, development, site restoration and abandonment
costs are derived based on current costs, assuming continuation of existing
economic conditions. Future income tax expenses are computed by applying the
statutory rate in effect at June 30, 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>
<CAPTION>
JUNE 30, 1997
-------------
<S> <C>
Future estimated cash flows...................................... $114,836,000
Future estimated production and development costs................ (51,448,000)
Future estimated income tax expense.............................. (17,495,000)
------------
Future net cash flows............................................ 45,893,000
10% annual discount for estimated timing of cash flows........... (28,969,000)
------------
Standardized measure of discounted future estimated net cash
flows........................................................... $ 16,924,000
============
</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 June 30, 1997:
<TABLE>
<S> <C>
Sales of oil and natural gas production, net of production costs. $ (2,242,000)
Net changes in prices and production costs....................... (66,622,000)
Extensions, discoveries and improved recovery, less related cost. 9,348,000
Acquisitions..................................................... --
Development costs incurred during the period..................... 1,152,000
Revisions of previous quantity estimates......................... (10,588,000)
Changes in estimated income taxes................................ 16,004,000
Accretion of discount............................................ 37,264,000
Other............................................................ (1,654,000)
------------
$(17,338,000)
============
</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
26
<PAGE>
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 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 June 30, 1997, the acres of developed
and undeveloped natural gas and oil properties in which the Company had an
interest, listed alphabetically by state.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
ACREAGE ACREAGE
------------- -------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Michigan............................................ 4,150 4,150 22,075 22,075
Ohio................................................ 1,200 800 -- --
Pennsylvania........................................ 250 250 13,900 13,160
Tennessee........................................... 3,600 3,600 -- --
West Virginia....................................... 59,900 59,500 24,760 24,640
------ ------ ------ ------
Total............................................. 69,100 68,300 60,735 59,875
====== ====== ====== ======
</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.
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 30.9% of the Company's revenues from oil and gas sales (13.2% of total
revenues) during the first six months of 1997; 30.7% of the Company's revenues
from oil and
27
<PAGE>
gas sales (16.1% of total revenues) in 1996; 39.7% of the Company's revenues
from oil and gas sales (7.4% of total revenues) in 1995; and 43.3% of the
Company's revenues from oil and gas sales (7.9% of total revenues) in 1994.
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 the first six months of 1997 or in 1996, 1995
or 1994.
At December 31, 1996, natural gas produced by the Company sold at prices per
Mcf ranging from $1.75 to $6.31, 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 1996 was $3.04 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 alternative
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.
For nearly a decade, the United States has experienced an oversupply of
natural gas. This oversupply has been caused primarily by deregulation,
imports and unusually warm weather conditions. Seasonal variations exist to
the extent that the demand for natural gas is somewhat lower during the summer
months than during the winter season.
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 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.
28
<PAGE>
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
June 30, 1997, there were 111 existing hedge positions. Total natural gas
purchased and sold under hedging arrangements during the year ended December
31, 1996 and the six months ended June 30, 1997 were 1,280,000 MMbtu and
1,620,000 MMbtu, respectively. Under such hedging arrangements, the Company
realized a loss of $146,008 for the year ended December 31, 1996 and a gain of
$73,013 for the six months ended June 30, 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 $24.6 million in subscriptions in 1996.
Funds received pursuant to drilling contracts were $25.0 million in 1996,
$13.6 million in 1995 and $14.9 million in 1994. 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 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.
29
<PAGE>
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 7,000 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 1996, 1995 or 1994.
At December 31, 1996, oil produced by the Company sold at prices ranging from
$21.50 to $22.50 per barrel, depending upon the location and quality of oil.
In 1996, the weighted net average price per barrel of oil sold by the Company
was $16.35.
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, countermeasures 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 lability 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.
30
<PAGE>
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 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. Inasmuch 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
31
<PAGE>
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.
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 be 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.
The Company's expenses relating to preserving the environment during 1996
were not significant in relation to operating costs and the Company expects no
material change in 1997. Environmental regulations have had no materially
adverse effect on the Company's operations to date, but no assurance can be
given that environmental
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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 1996, 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.
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,
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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 June 30, 1997, the Company had 74 employees, including 12 in finance,
seven in administration, 12 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.
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.
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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<PAGE>
MANAGEMENT
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:
<TABLE>
<CAPTION>
NAME AGE POSITIONS AND OFFICES HELD
- ---- --- --------------------------
<S> <C> <C>
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 E. Riley 44 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
</TABLE>
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 KPMG 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.
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.
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<PAGE>
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.
COMMITTEES OF THE BOARD OF DIRECTORS
The Company has three standing committees of the Board of Directors: the
Executive Committee; the Audit Committee; and the Stock Option and Executive
Compensation Committee. The Audit Committee is comprised of Messrs.
D'Annunzio, Ryan and Swoveland. The Executive Committee is comprised of
Messrs. Ryan, Williams and Rettinger. The Stock Option and Executive
Compensation Committee is comprised of Messrs. D'Annunzio and Swoveland. The
Company does not have a formal Nominating Committee, and the full Board of
Directors handles these responsibilities.
The functions performed by the Executive Committee include handling
important Board of Directors matters that arise between Board of Directors
meetings, serving as a liaison between the Board of Directors and senior
management on important matters requiring Board of Directors attention and
recommending to the Board of Directors nominations for election of new and
existing members of the Board of Directors.
The Audit Committee is comprised of a majority of outside Directors of the
Company. The functions performed by the Audit Committee include recommending
the selection of independent accountants, reviewing with the Company's
independent accountants the results of audits performed by them and overseeing
and reviewing monthly and quarterly unaudited financial statements. These
reviews include the adequacy of cash flow and the status of credit
arrangements of the Company.
The Stock Option and Executive Compensation Committee is comprised entirely
of outside Directors of the Company. The functions performed by this committee
include recommending to the Board of Directors compensation levels of senior
management and directing and recommending levels of corporate stock options
and other benefit plans of the Company. In this regard, the committee monitors
trends to ensure the Company's compensation levels are competitive in the oil
and natural gas industry.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The members of the Stock Option and Executive Compensation Committee are
Messrs. D'Annunzio and Swoveland. There are no Stock Option and Executive
Compensation Committee interlocks.
INDEMNIFICATION OF DIRECTORS AND OFFICERS
The Company's By-Laws provide that the Company shall indemnify any director,
officer, employee, or other agent of the Company who is or was a party, or is
threatened to be made a party, to any proceeding (other than an action by or
in the right of the Company to procure a judgment in its favor) by reason of
the fact that such person is or was an agent of the Company against expenses,
judgments, fines, settlements, and other amounts actually and reasonably
incurred in connection with such proceeding, if that person acted in good
faith and in a manner that person reasonably believed to be in the best
interest of the Company, and in the case of a criminal proceeding, had no
reasonable cause to believe the conduct of that person was unlawful.
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<PAGE>
The Company has entered into separate indemnification agreements with each
of its directors and officers whereby the Company has agreed to indemnify the
director or officer against all expenses, including attorneys' fees, and other
amounts reasonably incurred by the officer or director in connection with any
threatened, pending or completed civil, criminal, administrative or
investigative action or proceeding to which such person is party by reason of
the fact he is or was a director or officer, as the case may be, of the
Company, if the person acted in good faith and in a manner reasonably believed
to be in or not opposed to the best interests of the Company, and, with
respect to any criminal action or proceeding, the person had no reasonable
cause to believe such conduct to be unlawful. The agreements provide for the
advancement of expenses and that the Company has the right to purchase and
maintain insurance on behalf of the director or officer against any liability
or liabilities asserted against him, whether or not the Company would have the
power to indemnify the person against such liability under any provision of
the agreement. The Company has agreed to indemnify such person against
expenses actually and reasonably incurred in connection with any action in
which the person has been successful on the merits or otherwise.
Indemnification must also be provided by the Company (unless ordered otherwise
by a court) only as authorized in the specific case upon a determination that
the indemnification of the person is appropriate because he has met the
applicable standard of conduct described in the agreement made by (i) the
Board of Directors, by a majority vote of a quorum consisting of directors who
are not parties to such action or proceeding, (ii) by independent legal
counsel in a written opinion or (iii) the shareholders of the Company.
DIRECTOR COMPENSATION
Each non-salaried employee director and outside director of the Company is
paid an annual fee of $20,000. Each inside director is paid an annual fee of
$10,000.
EXECUTIVE COMPENSATION
The following table sets forth in summary form the compensation received
during each of the Company's last three fiscal years by the Chief Executive
Officer and by each other executive officer of the Company whose salary and
bonus exceeded $100,000 in 1996 (the "Named Executives").
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
ANNUAL COMPENSATION LONG TERM COMPENSATION
----------------------------------------- -----------------------------------------
OTHER SECURITIES ALL OTHER
NAME AND ANNUAL COMPEN- RESTRICTED STOCK UNDERLYING COMPENSA-
PRINCIPAL POSITION YEAR SALARY($) BONUS($)(1) SATION($)(2) AWARD(S)($)(3) OPTIONS(#)(4) TION($)(5)
- -------------------- ---- --------- ----------- -------------- ---------------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
James N. Ryan 1996 164,295 153,383 10,000 10,897
Chairman and Chief 1995 159,330 100,000 10,000 33,750 70,000 4,111
Executive Officer 1994 154,078 107,500 10,000 4,086
Steven R. Williams 1996 125,895 153,383 10,000 10,862
President and 1995 120,930 100,000 10,000 33,750 70,000 4,125
Director 1994 115,678 107,500 10,000 4,017
Dale G. Rettinger
Executive Vice
President, 1996 125,895 153,383 10,000 10,862
Treasurer 1995 120,930 100,000 10,000 33,750 70,000 4,125
and Director 1994 115,678 107,500 10,000 4,017
</TABLE>
- --------
(1) During 1994, the Board of Directors approved a deferred compensation
arrangement for the Named Executives. See "Employment and Other Agreements
and Arrangements." Under the arrangements, each Named Executive may choose
to defer any portion of his bonus compensation until retirement or
separation from the Company. The Named Executives voluntarily deferred
$80,000, $60,000 and $60,000, respectively, in 1996; $30,000 each in 1995;
and $30,000 each in 1994. In 1996 and 1995, $30,000 of the deferred bonus
compensation of Messrs. Williams and Rettinger was utilized to pay the
premiums of split-dollar life insurance policies for Messrs. Williams and
Rettinger.
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<PAGE>
(2) The respective Named Executives receive fees as directors of the Company
of $10,000 per year.
(3) In 1995, the Company granted a restricted stock award of 30,000 shares of
Common Stock to each of the Named Executives at the grant date market
price of $1.125 per share. These shares will vest upon a Named Executive's
retirement or involuntary separation from employment with the Company, or
upon a change of control of the Company. The aggregate value of the
holdings of each individual as of December 31, 1996 was $125,640.
(4) The exercise price of these options is $1.125 per share. In July 1997, the
Company granted each Named Executive options to purchase 108,000 shares of
Common Stock at an exercise price of $5.125 per share, the fair market
value of such shares of Common Stock at the date of grant. The options may
be exercised with respect to one-half of the shares granted thereunder on
or after July 15, 1998 and with respect to one-half of the shares granted
thereunder on or after July 15, 1999, provided that the grantee is
employed with the Company on the exercise date. Such options expire on
July 15, 2007.
(5) This amount includes contributions made by the Company under the Company's
Employee Profit Sharing Plan and 401(k) plan. In 1996 and 1995 the Company
contributed $50,000 and $28,500, respectively, to the Employee Profit
Sharing Plan. Of these contributions, each of the Named Executives was
credited $3,071 in 1996 and $1,815 in 1995. The Company provided a
matching of 401(k) contributions based upon varying rates of the Named
Executives' respective contributions. Of the total Company matching
contribution of $139,800, $70,800 and $68,700 in 1996, 1995 and 1994, the
Named Executives were credited with matching contributions of $7,826,
$7,791 and $7,791, respectively, in 1996; $4,111, $4,125 and $4,125,
respectively, in 1995; and $4,086, $4,017 and $4,017, respectively, in
1994.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION
VALUES
The following table provides certain information with respect to options
exercised during 1996 by the persons named in the Summary Compensation Table
under the Company's stock option plans. The table also represents information
as to the number of options outstanding as of December 31, 1996 with respect
to options granted pursuant to the Company's Employee Stock Option Plans. No
options were granted in 1996. The table does not include stock options granted
in 1997.
<TABLE>
<CAPTION>
VALUE OF UNEXERCISED
NUMBER OF UNEXERCISED OPTIONS IN-THE-MONEY OPTIONS AT
NUMBER OF YEAR-END(#) YEAR-END(1)($)
OF SHARES VALUE ----------------------------- -------------------------
NAME EXERCISED REALIZED($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- --------- ----------- ---------------- --------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
James N. Ryan -- -- 401,000 -- 1,290,125 --
Steven R. Williams -- -- 391,000 -- 1,257,625 --
Dale G. Rettinger -- -- 391,000 -- 1,257,625 --
</TABLE>
- --------
(1) For all unexercised options held as of December 31, 1996, the aggregate
dollar value is equal to the excess of the market value of the stock
underlying those options over the exercise price of those unexercised
options. On December 31, 1996, the closing sales price of the Common Stock
was $4.1875 per share.
In July 1997, the Company granted each Named Executive options to purchase
108,000 shares of Common Stock at an exercise price of $5.125 per share, the
fair market value of such shares of Common Stock at the date of grant. The
options may be exercised with respect to one-half of the shares granted
thereunder on or after July 15, 1998 and with respect to one-half of the
shares granted thereunder on or after July 15, 1999, provided that the grantee
is employed with the Company on the exercise date. Such options expire on July
15, 2007.
EMPLOYMENT AND OTHER AGREEMENTS AND ARRANGEMENTS
The Company has entered into employment agreements with each of the Named
Executives, each of which has a term that has been extended to December 31,
2000. Pursuant to the respective terms of the employment agreements, each of
the Named Executives is entitled to receive the basic annual salary set forth
therein that is subject to increase, but not decrease (unless dire economic
circumstances as declared by the Board of Directors requires a reduction for
all senior executive employees of the Company), as the Board of Directors may
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<PAGE>
determine to reflect changes in the cost of living, the financial success of
the Company and the performance of such Named Executive. For 1997, the basic
salary has been set by the Board of Directors under the respective agreements
as $170,760 for Mr. Ryan, $132,360 for Mr. Williams and $132,360 for Mr.
Rettinger. Each Named Executive is also entitled to be paid an annual bonus
equal to 2.5% of the Company's net pre-tax earnings for any year in which the
Company's net pre-tax earnings exceed $300,000. The Company has been required
to establish a deferred compensation plan, described below, for the Named
Executives and to fund such plan with an annual contribution of $30,000
commencing in 1994, subject to adjustment for inflation.
In the event of a change in control of the Company, each Named Executive has
the right within six months after such change of control to elect to terminate
his employment under his employment agreement and receive severance
compensation equal to the sum of his basic salary plus an amount equal to the
average bonus paid to him over the preceding three years as provided in the
agreement multiplied by the remaining years of the employment agreement,
provided, however, that the minimum severance compensation must not be less
than the amount equal to three years of basic compensation plus an amount
equal to three times the average bonus paid to such person over the preceding
three-year period.
Each employment agreement also provides that if the Company obtains the
right to sell working interests in any drilling program, the Named Executive
is entitled to participate as an investor in such oil and gas drilling project
subject to the prior approval by the Board of Directors of the terms of any
such participation.
Each employment agreement contains a standard non-disclosure covenant. Each
employment agreement also provides that the Named Executive is prohibited
during the term of his employment and for a period of one year following his
termination from engaging in any business that is competitive with the
Company's oil and gas drilling business in West Virginia, unless his
termination results from a change of control of the Company. During any period
for which the non-competition provision prohibits the officer from pursuing
activities that would compete with the Company's business as provided in the
agreement following termination of the agreement, the Company is required to
pay the officer his basic salary and bonus as provided in the agreement.
In the event of termination under the terms of the agreement, the Company
will be required to loan to the officer funds equal to the exercise price of
all options held by the Named Executive under the Company's stock option
plans, which loan, if made, must be repaid within nine months and will bear
interest at the prime rate then in effect.
Each employment agreement may be terminated for cause for willful
misfeasance or malfeasance, disregard of the Named Executive's duties or
negligence related to the performance of his duties, if so determined by a
court of competent jurisdiction. Also, the Company may terminate the
employment agreement without cause, in which case the Company must either (i)
reassign the Named Executive to a comparable executive position or designate
him as a consultant for the remaining term of his agreement or (ii) pay him
liquidated damages in an amount equal to his then basic salary for the
remaining term of the employment agreement, with a minimum payment equal to
twelve months of basic salary.
The Company has entered into an employment agreement with Thomas E. Riley.
The term of the employment agreement expires on March 31, 2000. Mr. Riley's
compensation under the employment agreement includes an annual base salary of
$70,000, a guaranteed annual bonus of $40,000 and an annual performance bonus
based on Mr. Riley's contribution to the Company and the overall success and
status of the Company, as determined by the Compensation Committee and as
approved by the Board of Directors.
The Company has entered into stock redemption agreements with each of the
Named Executives. The agreements require the Company to maintain life
insurance policies on each of them in the amount of $1 million. At the
election of the Named Executive's estate or heirs made within one year of such
person's death, the Company must utilize the proceeds from such insurance
policies to purchase from his estate or heirs all or a portion of his shares
of the Company's Common Stock owned by him, including shares subject to
outstanding stock options or warrants owned by such Named Executive at the
time of his death, up to an aggregate sale price of $1 million. The purchase
price for such shares of Common Stock will be based upon the average closing
asked price for the Company's Common Stock as quoted by Nasdaq during a
specified period. The Company is
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<PAGE>
not required to purchase any shares in excess of the amount provided by such
insurance policies. If the Named Executive's estate or heirs elect not to sell
any or all of the shares to the Company, the estate or heirs will be precluded
from selling the shares to anyone for a period of two years after the date of
the person's death, except that the shares may be transferred into the names
of the decedent's heirs and beneficiaries and the stock sold pursuant to Rule
144 under the Securities Act. If the Named Executive terminates his employment
with the Company or disposes of all or substantially all of his shares of
Common Stock in the Company, the Named Executive has the right to purchase his
respective insurance policy for a price equal to the cash surrender value of
the policy as of the date of such event. If the Named Executive fails to
purchase the policy within ninety days after such event, the Company may
cancel all policies covering the life of the Named Executive. The stock
redemption agreements will terminate upon bankruptcy or cessation of business
by the Company.
Mr. Ryan, Mr. Williams and Mr. Rettinger are also the participants in the
Company's deferred bonus compensation plan. Under this plan, the Company's
Board of Directors must declare a year-end bonus for each participant, the
receipt of which is automatically deferred pursuant to the plan, unless prior
to the beginning of a particular year, the participant enters into a voluntary
bonus compensation agreement under which he irrevocably elects to receive his
year-end bonus as cash compensation, payable as soon as practicable following
the end of the year. The amount of the participant's year-end bonus is a
minimum of $30,000 or such greater amount as may be declared by the Board of
Directors. The participant also has the right to elect to defer receipt of his
other bonus compensation under this plan. Any bonus compensation deferred
under this plan will not be paid until such participant's retirement, or upon
termination of employment, disability or death or upon hardship, as provided
in the plan. A trustee selected by the Board of Directors maintains accounts
for each participant under the plan. The Company has reserved the right to
terminate the deferred bonus compensation plan, in whole or in part, at any
time and without liability for such termination or discontinuance.
STOCK OPTION PLANS
Under the Company's incentive stock option plans, options to purchase shares
of Common Stock of the Company may be granted to certain officers and key
employees of the Company, which options are intended to qualify as incentive
stock options under the provisions of the Internal Revenue Code. Under the
plan adopted in 1997, the Company may grant options for up to an aggregate of
500,000 shares of Common Stock at an exercise price of not less than 100% of
the fair market value per share of the Company's Common Stock on the date of
grant. The options may be exercised with respect to one-half of the shares
granted on or after the first anniversary of the date of grant and with
respect to the other one-half of the shares granted on or after the second
anniversary of the date of grant. Options generally will expire ten years from
the date of grant if not exercised. A dissolution or liquidation of the
Company or a merger or consolidation in which the Company is not the surviving
corporation will cause each outstanding option to terminate, provided that
each optionee, in such event, will have the right immediately prior to said
dissolution or liquidation or merger or consolidation to exercise his option
in whole or in part without regard to any installment vesting provisions with
respect to such options. Options have been granted for all shares available
under the plan. Under the plan adopted in 1990, the Company may grant options
for up to an aggregate of 500,000 shares of Common Stock at an exercise price
of not less than 100% of the fair market value per share of the Company's
Common Stock on the date of grant. Options generally will expire five years
from the date of grant if not exercised. A dissolution or liquidation of the
Company or a merger or consolidation in which the Company is not the surviving
corporation will cause each outstanding option to terminate, provided that
each optionee, in such event, will have the right immediately prior to said
dissolution or liquidation or merger or consolidation to exercise his option
in whole or in part without regard to any installment vesting provisions with
respect to such options. Options have been granted for all shares available
under the plan.
KEY-MAN LIFE INSURANCE
The Company maintains key-man life insurance policies on the lives of
Messrs. Ryan, Williams and Rettinger in the amounts of $5.0 million, $1.0
million and $1.0 million, respectively. The Company is the beneficiary of each
policy.
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<PAGE>
CERTAIN TRANSACTIONS
In January 1996, the Company repurchased 1,200,000 shares of Common Stock
(approximately 11% of the then outstanding shares of Common Stock) from PNC
Bank, N.A. ("PNC") for a purchase price of $1.0 million, or $0.83 per share,
pursuant to the Second Amended and Restated Option Agreement dated April 30,
1993 between the Company and PNC. PNC had acquired 1,562,500 shares of the
Company's Common Stock (of which 1,381,250 shares were owned by PNC at the
date of the repurchase) in exchange for the partial forgiveness of certain
indebtedness of the Company to PNC pursuant to the Fourth Amended and Restated
Loan Agreement between the Company and PNC. The shares were retired by the
Company immediately following the repurchase.
In April 1996, the Company acquired RNG in a stock-for-stock exchange for
236,094 shares of the Company's Common Stock, which had a market value of
$449,100 at that time. RNG is an Appalachian Basin natural gas marketing
company that specializes in the acquisition and aggregation of Appalachian
Basin production. Thomas E. Riley, Donna Riley, Mr. Riley's wife, and a co-
founder and an employee of RNG, and three other employees of RNG joined the
Company at that time.
Roger J. Morgan, Secretary and Director of the Company, is a senior partner
of Young, Morgan & Cann, a law firm which the Company has retained to provide
various legal services for the Company, including during the year ended
December 31, 1996.
With respect to transactions with Messrs. Ryan, Williams and Rettinger, see
"Management--Executive Compensation--Employment and Other Agreements and
Arrangements."
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<PAGE>
PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information regarding ownership of
the Company's Common Stock as of September 15, 1997, and as adjusted to
reflect the sale of the Common Stock offered hereby, by: (a) each person known
by the Company to own beneficially more than 5% of the outstanding shares of
Common Stock; (b) each director of the Company; (c) each Named Executive; (d)
a selling stockholder who does not own more than 5% of the Company's Common
Stock and who is not a director or executive officer of the Company; and (e)
all directors and executive officers as a group.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP
PRIOR TO THE OFFERING(1) AFTER THE OFFERING(1)
--------------------------- SHARES BEING -------------------------
NAME AND ADDRESS NUMBER PERCENT OFFERED NUMBER PERCENT
- ---------------- -------------- ------------ ------------ ------------- -----------
<S> <C> <C> <C> <C> <C>
James N. Ryan(2)........ 1,030,474 9.0% 100,000 930,474 6.3%
103 East Main Street
Bridgeport,WV26330
Fidelity Management..... 995,000 9.1 -- 995,000 6.9
82 Devonshire Street
Boston, MA 02109
Steven R. Williams(3)... 649,000 5.7 100,000 549,000 3.7
103 East Main Street
Bridgeport, WV 26330
Dale G. Rettinger(3).... 617,834 5.4 100,000 517,834 3.5
103 East Main Street
Bridgeport, WV 26330
Thomas E. Riley......... 236,094 2.1 50,000 186,094 1.3
Roger J. Morgan(4)...... 132,504 1.2 -- 132,504 *
Vincent F.
D'Annunzio(5)........... 53,600 * -- 53,600 *
Jeffrey C. Swoveland(6). 23,550 * -- 23,550 *
All directors and
executive officers as a
group
(6 persons)(7)......... 2,506,962 20.4 300,000 2,206,962 14.0
</TABLE>
- --------
* Less than 1%
(1) Includes shares over which the person currently holds or shares voting or
investment power. Unless otherwise indicated in the footnotes to this
table, the persons named in this table have sole voting and investment
power with respect to the shares beneficially owned. Percentage of
beneficial ownership is calculated assuming 10,985,753 shares of Common
Stock outstanding on September 15, 1997 (including 500,000 shares issued
and sold by the Company in the Private Placement) and 14,485,753 shares of
Common Stock outstanding after completion of this offering.
(2) Includes 406,250 shares owned jointly with Mr. Ryan's wife, 118,119 shares
owned by Mr. Ryan's wife and 64,258 shares owned by Mr. Ryan's wife as
guardian for their minor grandchildren. The balance of the shares are
owned solely by Mr. Ryan. The shares to be sold in this offering are
registered in the name of Mr. Ryan's wife. Also includes options to
purchase 401,000 shares of Common Stock that Mr. Ryan can currently
exercise or that will become exercisable within 60 days. Excludes 108,000
shares underlying options granted on July 15, 1997 exercisable after such
60-day period.
(3) Includes options to purchase 391,000 shares that such person can currently
exercise or that will become exercisable within 60 days. Excludes 108,000
shares underlying option granted to such person on July 15, 1997
exercisable after such 60-day period.
(4) Includes options to purchase 77,500 shares that Mr. Morgan can currently
exercise or that will become exercisable within 60 days.
(5) Includes options to purchase 43,600 shares that Mr. D'Annunzio can
currently exercise or that will become exercisable within 60 days.
(6) Includes options to purchase 23,550 shares that Mr. Swoveland can
currently exercise or that will become exercisable within 60 days.
(7) Includes options to purchase an aggregate of 1,327,650 shares that such
persons can currently exercise or that will become exercisable within 60
days.
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<PAGE>
DESCRIPTION OF CAPITAL STOCK
The Company's authorized capital stock consists of 22,250,000 shares of
Common Stock, par value $.01 per share, and 2,750,000 shares of Common Stock,
Class A, par value $0.01 per share ("Class A Common Stock"). Following
consummation of this offering, there will be approximately 14,485,753 shares
of Common Stock outstanding, and no shares of Class A Common Stock will be
outstanding.
COMMON STOCK
Holders of Common Stock are entitled to one vote for each share held on all
matters submitted to vote of stockholders and do not have cumulative voting
rights. Accordingly, a holder of a majority of the outstanding shares of
Common Stock entitled to vote in any election of Directors may elect all the
Directors standing for election. Holders of Common Stock are entitled to
receive ratably such dividends, if any, as may be declared by the Board of
Directors out of funds legally available therefor. Upon the liquidation,
dissolution or winding up of the Company, holders of Common Stock are entitled
to receive ratably the net assets of the Company available for distribution
after the payment of all debts and other liabilities of the Company. Holders
of Common Stock have no preemptive, subscription, redemption or conversion
rights. The outstanding shares of Common Stock are, and the shares offered
hereby when issued and paid for will be, fully paid and nonassessable.
CLASS A COMMON STOCK
The Board of Directors is empowered by the Company's Articles of
Incorporation to designate and issue from time to time one or more classes or
series of Class A Common Stock without any action of the stockholders. The
Class A Common Stock is identical in all respects to the Common Stock, except
that the Class A Common Stock shares (i) carry no right to vote for the
election of directors of the Company and no right to vote on any matter
presented to the shareholders for their vote or approval and (ii) are
convertible at the option of the holder thereof into shares of Common Stock on
a one-for-one basis. No shares of Class A Common Stock have been issued and
the Company does not presently contemplate the issuance of such shares.
WARRANTS
Warrants to purchase up to an aggregate of 125,000 shares of Common Stock
are outstanding. Each warrant is exercisable for one share of Common Stock at
a price of $6.00 per share and is exercisable prior to September 15, 1999.
CERTAIN CORPORATE ANTI-TAKEOVER PROVISIONS
The Company's By-Laws provide for the Board of Directors to be divided into
three classes of directors serving staggered three-year terms. The
classification system of electing directors may discourage a third party from
making a tender offer or otherwise attempting to obtain control of the Company
and may maintain the incumbency of the Board of Directors, as it generally
makes it more difficult for stockholders to replace a majority of the members
of the Board of Directors.
The Nevada general corporation law (the "NGCL") provides that directors and
officers may, in discharging their duties, consider the interests of a number
of different constituencies, including stockholders, employees, suppliers,
customers and creditors; the economy of the state and nation; the interests of
the community and society; and the long-term as well as short-term interest of
the Company and its stockholders. Directors and officers are not required to
consider the interests of the stockholders to a greater degree than other
constituencies' interests.
The NGCL also contains several other anti-takeover provisions identified
below that will be applicable to the Company. The NGCL's "Combinations with
Interested Stockholders" statute, which applies to a Nevada corporation having
at least 200 stockholders, and which, unless the Articles of Incorporation
provide otherwise, has a class of voting shares registered under the Exchange
Act, prohibits an "interested stockholder" from entering into a "combination"
with the corporation, unless certain conditions are met. A "combination"
includes (a) any merger or consolidation with an interested stockholder, (b)
any sale, lease, exchange, mortgage,
43
<PAGE>
pledge, transfer or other disposition of assets, in one transaction or a
series of transactions, to an interested stockholder, having: (i) an aggregate
market value equal to 5% or more of the aggregate market value of the
corporation's assets; (ii) an aggregate market value equal to 5% or more of
the aggregate market value of all outstanding shares of the corporation; or
(iii) representing 10% or more of the earning power or net income of the
corporation, or (c) any issuance or transfer of shares of the corporation or
its subsidiaries to an interested stockholder having an aggregate market value
equal to 5% or more of the aggregate market value of all the outstanding
shares of the corporation. An "interested stockholder" is a person who,
together with affiliates and associates, beneficially owns directly or
indirectly (or within the prior three years, did beneficially own) 10% or more
of the corporation's voting stock. A stockholder who owned 10% or more of the
corporation's stock on January 1, 1991 is not an interested stockholder.
A corporation to which the statute applies may not engage in a "combination"
with the interested stockholder within three years after the interested
stockholder acquired its shares, unless the combination or the interested
stockholder's acquisition of the shares making the stockholder an interested
stockholder was approved by the board of directors before the interested
stockholder acquired such shares. If this prior approval is not obtained, then
after the three-year period expires, the combination may be consummated either
by the approval of the board of directors or a majority of the voting power
held by disinterested stockholders at a meeting called after expiration of the
three-year period, or if the consideration to be paid by the interested
stockholder is at least equal to the higher of: (i) the highest price per
share paid by the interested stockholder within the three years immediately
preceding the date of the announcement of the combination or in the
transaction in which it became an interested stockholder, whichever is higher,
plus interest as provided in the statute; or (ii) the market value per common
share on the date of announcement of the combination or the date the
interested stockholder acquired the shares, whichever is higher; plus interest
as provided in the statute.
Nevada's "Acquisition of Controlling Interest" statute prohibits a person or
group owning or offering to acquire voting shares of a corporation, under
certain circumstances, from voting shares of a target corporation's stock
after crossing certain threshold ownership percentages, unless such
corporation's Articles of Incorporation or By-Laws are amended to make the
statute inapplicable to the acquisition or unless the acquiror obtains the
approval of the target corporation's disinterested stockholders. The statute
specifies three thresholds: at least one-fifth but less than one-third, at
least one-third but less than a majority, and a majority or more, of the
outstanding voting power. Once an acquiror crosses one of the above
thresholds, shares which it acquired in the transaction taking it over the
threshold or within ninety days become "Control Shares" which are deprived of
the right to vote until a majority of the disinterested stockholders restore
that right. If an acquiror does not make certain timely demands on the target
corporation or if the stockholders fail to restore voting rights to the
acquiror, then the corporation may, if so provided in its Articles of
Incorporation or By-Laws, call certain of the acquiror's shares for
redemption. The Company's Articles of Incorporation and By-Laws do not
currently permit it to call an acquiror's shares for redemption under these
circumstances. The Acquisition of Controlling Interest statute also provides
that in the event the stockholders restore full voting rights to a holder of
Control Shares which owns a majority of the voting stock, then all other
stockholders who do not vote in favor of restoring voting rights to the
Control Shares may demand payment for the "fair value" of their shares (which
is generally equal to the highest price paid in the transaction subjecting the
stockholder to the statute). The Acquisition of Controlling Interest statute
applies only to a Nevada corporation with at least 200 stockholders, including
at least 100 record stockholders who are Nevada residents, and which does
business directly or indirectly in Nevada. As of the date of this Prospectus,
the Company does not have 100 record stockholders in Nevada and does not
conduct business in Nevada, although there can be no assurance that in the
future the Acquisition of Controlling Interest statute will not be applicable
to the Company.
The provisions described above, together with the staggered Board of
Directors, may have the effect of delaying or deterring a change in the
control or management of the Company.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Company's Common Stock is OTR Stock
Transfer, Portland, Oregon.
44
<PAGE>
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of this offering, the Company will have outstanding
14,485,753 shares of Common Stock. See "Capitalization." Of these shares, an
aggregate of 13,015,739 shares, consisting of (i) the 3,850,000 shares sold in
this offering (plus any additional shares sold upon the Underwriters' exercise
of their over-allotment option); and (ii) an aggregate of 9,165,739 shares,
without taking into account the lock-up agreements referred to below, that are
currently issued and outstanding, will be freely transferable by persons other
than "affiliates" of the Company without restriction or further registration
under the Securities Act. The remaining 1,470,014 shares of Common Stock are
"restricted securities" (the "Restricted Shares") within the meaning of Rule
144 and may not be sold in the absence of registration under the Securities
Act unless an exemption from registration is available, including an exemption
afforded by Rule 144.
The Company and all of the Company's officers and directors and the Selling
Stockholders have entered into lock-up agreements with the Representative
providing that they will not offer, sell, contract to sell or grant any option
to purchase or otherwise dispose of any of the shares of Common Stock owned by
them without the prior written consent of the Representative. This restriction
will apply to all of the shares owned by them for 180 days after the date of
this Prospectus.
Rule 144 provides that an affiliate of the Company or a person (or persons
whose sales are aggregated) who beneficially owned Restricted Shares for at
least one year but less than two years is entitled to sell, within any three-
month period, a number of shares that does not exceed the greater of one
percent of the then outstanding shares of Common Stock (144,858 shares
immediately after this offering) or the average weekly trading volume in the
Common Stock during the four calendar weeks preceding such sale. Sales under
Rule 144 also are subject to certain manner-of-sale provisions, notice
requirements and the availability of current public information about the
Company. However, a person who is not an "affiliate" of the Company at any
time during the three months preceding a sale, and who has beneficially owned
Restricted Shares for at least two years, is entitled to sell such shares
under Rule 144 without regard to the limitations described above.
The Common Stock has been traded on the Nasdaq National Market.
Nevertheless, sales of a substantial amount of the Common Stock in the public
market, or the perception that such sales could occur, could adversely affect
the market price of the shares of Common Stock and could impair the Company's
future ability to raise capital through an offering of its equity securities.
See "Risk Factors--Shares Eligible for Future Sale."
45
<PAGE>
UNDERWRITING
Subject to the terms and conditions contained in an underwriting agreement
(the "Underwriting Agreement"), the Underwriters named below, for whom
Pennsylvania Merchant Group Ltd is acting as representative (the
"Representative"), have severally agreed to purchase from the Company and the
Selling Stockholders, the respective number of shares of Common Stock set
forth opposite their names below.
<TABLE>
<CAPTION>
NUMBER OF SHARES
UNDERWRITER OF COMMON STOCK
----------- ----------------
<S> <C>
Pennsylvania Merchant Group Ltd...............................
---------
Total.................................................... 3,850,000
=========
</TABLE>
The Underwriting Agreement provides that the obligations of the several
Underwriters to pay for and accept delivery of the shares of Common Stock
offered hereby are subject to approval of certain legal matters by their
counsel and to certain other conditions. The Underwriters are obligated to
take and pay for all the shares of Common Stock offered hereby (other than
those covered by the over-allotment option described below) if any such shares
of Common Stock are taken.
The Company and Selling Stockholders have been advised by the Representative
that the Underwriters propose initially to offer the shares of Common Stock,
in part, directly to the public at the price set forth on the cover page of
this Prospectus and, in part, to certain dealers at such price less a
concession not in excess of $ per share. The Underwriters may allow, and
such dealers may reallow, a concession not in excess of $ per share to
certain other dealers. After the initial offering of the Common Stock, the
offering price and other selling terms may be changed by the Representative.
The Company has granted to the Underwriters an option, exercisable within 30
days after the date of this Prospectus, to purchase, from time to time in
whole or in part, up to 577,500 additional shares of Common Stock at the
public offering price, less the underwriting discounts and commissions, all as
set forth on the cover page of this Prospectus. The Underwriters may exercise
such option solely for the purpose of covering over-allotments, if any, made
in connection with the offering. To the extent such option is exercised, each
Underwriter will become obligated, subject to certain conditions, to purchase
approximately the same percentage of such additional shares as the number of
shares of Common Stock to be purchased by such Underwriter shown in the above
table bears to the total number of shares of Common Stock shown in the above
table.
Each of the Company and the Selling Stockholders have agreed to indemnify
the Underwriters against certain liabilities, including liabilities under the
Securities Act.
The Company has agreed to pay the Representative a non-accountable expense
allowance of $150,000 upon consummation of this offering.
In connection with the offering, the Underwriters may engage in transactions
that stabilize, maintain or otherwise effect the price of the Common Stock.
Specifically, the Underwriters may over-allot the offering, creating a
syndicate short position. In addition, the Underwriters may bid for and
purchase shares of Common Stock in the open market to cover such syndicate
short position or to stabilize the price of the Common Stock. These activities
may stabilize or maintain the market price of the Common Stock above
independent market levels. The Underwriters are not required to engage in
these activities, and may end any of these activities at any time.
The Underwriters and dealers may engage in passive market making
transactions in the Common Stock in accordance with Rule 103 of Regulation M
promulgated by the SEC. In general, a passive market maker may not bid for, or
purchase, the Common Stock at a price that exceeds the highest independent
bid. In addition, the net daily purchases made by any passive market maker
generally may not exceed 30% of its average daily trading
46
<PAGE>
volume in the Common Stock during a specified two-month prior period, or 200
shares, whichever is greater. A passive market maker must identify passive
market making bids as such on the Nasdaq electronic inter-dealer reporting
system. Passive market making may stabilize or maintain the market price of
the Common Stock above independent market levels. Underwriters and dealers are
not required to engage in passive market making and may end passive market
making activities at any time.
Each of the Company, its executive officers and directors and certain
stockholders of the Company (including the Selling Stockholders) has agreed,
subject to certain exceptions, not to (i) offer, pledge, sell, contract to
sell, sell any option or contract to purchase, purchase any option or contract
to sell, grant any option, right or warrant to purchase or otherwise transfer
or dispose of, directly or indirectly, any shares of Common Stock or any
securities convertible into or exercisable or exchangeable for Common Stock or
(ii) enter into any swap or other arrangement that transfers all or a portion
of the economic consequences associated with the ownership of any Common Stock
(regardless of whether any of the transactions described in clause (i) or (ii)
is to be settled by the delivery of Common Stock, or such other securities, in
cash or otherwise) for a period of 180 days after the date of this Prospectus
without the prior written consent of the Representative. In addition, during
such 180-day period, without the Representative's prior written consent, the
Company has also agreed not to file any registration statement with respect
to, and each of its executive officers and directors and certain stockholders
of the company (including the Selling Stockholders) has agreed not to make any
demand for, or exercise any right with respect to, the registration of any
shares of Common Stock or any securities convertible into or exercisable or
exchangeable for Common Stock.
LEGAL MATTERS
The validity of the Common Stock offered hereby will be passed upon for the
Company by Duane, Morris & Heckscher LLP, Washington, DC. Certain legal
matters in connection with the offering will be passed on for the Underwriters
by Buchanan Ingersoll, Princeton, New Jersey.
EXPERTS
The consolidated financial statements and schedule of the Company as of
December 31, 1996 and 1995, and for each of the years in the three-year period
ended December 31, 1996, included herein and elsewhere in the registration
statement, have been included herein and in the registration statement in
reliance upon the reports of KPMG Peat Marwick LLP, independent auditors,
appearing elsewhere herein and in the registration statement, and upon the
authority of such firm as experts in accounting and auditing.
With respect to the unaudited interim financial information for the periods
ended March 31, 1997 and 1996 and June 30, 1997 and 1996, incorporated by
reference herein, the independent certified public accountants have reported
that they applied limited procedures in accordance with professional standards
for a review of such information. However, their separate reports included in
the Company's quarterly reports on Form 10-Q for the quarters ended March 31,
1997 and June 30, 1997, and incorporated by reference herein, state that they
did not audit and they do not express an opinion on that interim financial
information. Accordingly, the degree of reliance on their reports on such
information should be restricted in light of the limited nature of the review
procedures applied. The accountants are not subject to the liability
provisions of Section 11 of the Securities Act for their reports on the
unaudited interim financial information because the reports are not a "report"
or a "part" of the registration statement prepared or certified by the
accountants within the meaning of Sections 7 and 11 of the Securities Act.
The Summary Reserve Report of Wright & Company, Inc., independent petroleum
engineers, annexed hereto as Appendix A, containing estimates of proved
natural gas and oil reserves and related future net revenues and the present
value thereof, and the estimates of proved natural gas and oil reserves and
related future net revenues and the present value thereof as of December 31,
1996 and June 30, 1997 included in the registration statement, have been
derived from the reserve report of such firm and certain engineering reports
prepared by the Company and reviewed by such firm. All of such information has
been so included herein in reliance upon the authority of such firm as experts
in such matters.
47
<PAGE>
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith files reports, proxy statements and other information with the SEC.
Such reports, proxy statements and other information filed by the Company with
the SEC can be inspected and copies at the public reference facilities
maintained by the SEC at Room 1024, 450 Fifth Street, N.W., Judiciary Plaza,
Washington, DC 20549, and at the following regional offices of the SEC: 7
World Trade Center, Suite 1300, New York, NY 10048; and Citicorp Center, 500
West Madison Street, Suite 1400, Chicago, IL 60661-2511. In addition, such
materials can also be obtained from the SEC's web site at http://www.sec.gov.
The Common Stock of the Company is traded on the Nasdaq National Market under
the symbol PETD, and copies of the above reports, proxy statements and other
information may also be inspected at the offices of Nasdaq Operations, 1735 K
Street, Washington, DC 20006.
The Company has filed with the SEC a Registration Statement on Form S-2 (the
"Registration Statement") under the Securities Act with respect to the
securities offered hereby. This Prospectus does not contain all of the
information set forth in the Registration Statement and the exhibits and
schedules thereto. For further information with respect to the Company and the
securities offered hereby, reference is hereby made to the Registration
Statement and the exhibits and schedules filed therewith. Statements contained
herein as to the content of any contract or other document are not necessarily
complete and, in each instance, reference is made to the copy of such contract
or other document filed as an exhibit to the Registration Statement, and each
such statement shall be deemed qualified in its entirety by such references.
The Registration Statement and any amendments thereto, including exhibits
filed or incorporated by reference as a part thereof, may be obtained from the
principal office of the SEC in Washington, DC, upon payment of the fees
prescribed by the SEC.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Company hereby incorporates into this Prospectus by reference its Annual
Report on Form 10-K for the fiscal year ended December 31, 1996 and its
Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997 and June
30, 1997 filed with the SEC pursuant to Section 13 or 15(d) of the Exchange
Act.
The Company will provide without charge to each person, including any
beneficial owner, to whom a copy of this Prospectus is delivered, upon the
written or oral request of any such person, a copy of any and all of the
documents incorporated herein by reference, other than exhibits to such
documents (except for exhibits that are specifically incorporated herein by
reference herein). Requests for such copies shall be directed to Steven R.
Williams, President, Petroleum Development Corporation, 103 East Main Street,
Bridgeport, West Virginia, 26330, telephone number (304) 842-6256.
48
<PAGE>
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used
in this Prospectus. All volumes of natural gas referred to herein are stated
at the legal pressure base of the state or area where the reserves exist and
at 60 degrees Fahrenheit and in most instances are rounded to the nearest
multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
CNG system. Consolidated Natural Gas Transmission Company pipeline system.
Completion. The installation of permanent equipment for the production of
oil or natural gas or, in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled to extend the limits of an already
developed pool, or within a proved area of an oil or gas reservoir to the
depth of a stratigraphic horizon known to be productive.
Drilled well. A well for which the Company supervised the drilling activity
or in which it has a working interest.
Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production fail
to exceed production expenses and taxes.
Dth. One decatherm. One decatherm is equal to one million British Thermal
Units.
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or natural gas in another reservoir
or to extend a known reservoir.
Farm-in or farm-out. An agreement whereunder the owner of a working interest
in an oil and natural gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to
earn its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Mcf. One thousand cubic feet.
MMBtu. One million British Thermal Units.
Net acres or net wells. When the sum of the fractional working interests
owned in gross acres or gross wells equals one.
NYMEX. New York Mercantile Exchange.
Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development
49
<PAGE>
costs, using prices and costs in effect as of the date indicated, without
giving effect to nonproperty-related expenses such as general and
administrative expenses, debt service and future income tax expense or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved developed reserves. Proved reserves that are expected to be recovered
through existing wells with existing equipment and operating equipment.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
Spot market. The cash market for natural gas. Generally, the Company's
natural gas contracts are based on a day-to-day or month-to-month spot.
Tcf. Trillion cubic feet.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and share of
production.
Workover. Operations on a producing well to restore or increase production.
50
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
PAGE
----
CONSOLIDATED FINANCIAL STATEMENTS:
Independent Auditors' Report.............................................. F-2
Consolidated Balance Sheets at December 31, 1995 and 1996 and June 30,
1997..................................................................... F-3
Consolidated Statements of Income for the years ended December 31, 1994,
1995
and 1996 and six months ended June 30, 1996 and 1997..................... F-4
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1994,
1995 and 1996 and six months ended June 30, 1997......................... F-5
Consolidated Statements of Cash Flow for the years ended December 31,
1994, 1995
and 1996 and six months ended June 30, 1996 and 1997..................... F-6
Notes to Consolidated Financial Statements................................ F-7
</TABLE>
F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Stockholders and Board of Directors
Petroleum Development Corporation:
We have audited the consolidated balance sheets of Petroleum Development
Corporation and subsidiaries as of December 31, 1996 and 1995, and the related
consolidated statements of income, stockholders' equity and cash flows for
each of the years in the three-year period ended December 31, 1996. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the 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, 1996 and 1995, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1996, in conformity with generally
accepted accounting principles.
KPMG PEAT MARWICK
Pittsburgh, Pennsylvania
March 13, 1997
F-2
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------ JUNE 30,
1995 1996 1997
----------- ----------- -----------
<S> <C> <C> <C>
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents (includes
restricted cash of $1,734,900 in
1996)................................ $10,053,600 $20,615,400 $ 8,461,600
Notes and accounts receivable......... 2,016,600 6,696,000 4,851,800
Inventories........................... 217,900 567,200 273,400
Prepaid expenses...................... 868,800 740,900 813,100
----------- ----------- -----------
Total current assets................ 13,156,900 28,619,500 14,399,900
Properties and equipment:
Oil and gas properties (successful
efforts accounting method)........... 37,992,000 46,525,700 48,028,600
Pipelines............................. 6,851,900 7,186,900 7,277,400
Transportation and other equipment.... 2,546,900 2,151,200 1,980,900
Land and buildings.................... 849,200 1,098,200 1,136,900
----------- ----------- -----------
48,240,000 56,962,000 58,423,800
Less accumulated depreciation,
depletion and amortization........... 21,127,100 22,522,300 23,336,300
----------- ----------- -----------
27,112,900 34,439,700 35,087,500
Other assets............................ 350,300 545,000 592,500
----------- ----------- -----------
$40,620,100 $63,604,200 $50,079,900
=========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable...................... $ 2,119,100 $ 9,703,800 $ 6,882,700
Accrued taxes......................... 155,100 506,000 694,900
Other accrued expenses................ 1,628,800 1,505,900 2,136,600
Advances for future drilling
contracts............................ 10,069,600 18,397,000 3,954,400
Funds held for future distribution.... 704,000 864,000 1,043,900
----------- ----------- -----------
Total current liabilities........... 14,676,600 30,976,700 14,712,500
Long-term debt, excluding current
maturities............................. 2,500,000 5,320,000 3,695,000
Other liabilities....................... 601,700 1,094,200 1,242,500
Deferred income taxes................... 2,920,900 3,140,800 3,419,900
Commitments and contingencies
Stockholders' equity:
Common stock, par value $.01 per
share; authorized
22,250,000 shares; issued and
outstanding 11,208,627, 10,460,753
and 10,485,753....................... 112,100 104,600 104,900
Common stock, Class A, par value $.01
per share; authorized 2,750,000
shares; issued and outstanding--none. -- -- --
Additional paid-in capital............ 7,019,800 6,617,300 6,638,900
Retained earnings..................... 12,878,000 16,427,400 20,336,900
Unamortized stock award............... (89,000) (76,800) (70,700)
----------- ----------- -----------
Total stockholders' equity.......... 19,920,900 23,072,500 27,010,000
----------- ----------- -----------
$40,620,100 $63,604,200 $50,079,900
=========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
----------------------------------- -----------------------
1994 1995 1996 1996 1997
----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas well
drilling operations.. $15,190,200 $13,941,000 $18,698,200 $10,732,600 $19,276,800
Oil and gas sales..... 4,361,300 4,150,600 26,051,100 8,964,600 16,348,800
Well operations and
pipeline income...... 3,730,300 3,750,900 3,928,800 1,847,100 2,248,100
Other income.......... 524,400 504,000 935,600 230,700 451,500
----------- ----------- ----------- ----------- -----------
23,806,200 22,346,500 49,613,700 21,775,000 38,325,200
Costs and expenses:
Cost of oil and gas
well drilling
operations........... 14,288,700 11,943,000 15,779,800 8,770,200 15,758,800
Oil and gas purchases
and
production cost...... 4,067,000 4,138,700 24,190,300 8,084,300 14,716,400
General and
administrative
expenses............. 2,203,800 1,960,600 2,304,000 1,111,900 1,091,500
Depreciation,
depletion and
amortization......... 1,848,200 2,152,100 2,309,600 1,207,400 1,220,400
Interest.............. 300,200 319,700 380,000 139,400 204,500
----------- ----------- ----------- ----------- -----------
22,707,900 20,514,100 44,963,700 19,313,200 32,991,600
----------- ----------- ----------- ----------- -----------
Income before income
taxes.............. 1,098,300 1,832,400 4,650,000 2,461,800 5,333,600
Income taxes............ 176,700 350,900 1,100,600 521,900 1,424,100
----------- ----------- ----------- ----------- -----------
Net income............ $ 921,600 $ 1,481,500 $ 3,549,400 $ 1,939,900 $ 3,909,500
=========== =========== =========== =========== ===========
Earnings per common and
common equivalent
share.................. $ 0.08 $ 0.13 $ 0.31 $ 0.17 $ 0.33
=========== =========== =========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
COMMON STOCK ISSUED
--------------------
ADDITIONAL
NUMBER PAID-IN RETAINED UNAMORTIZED
OF SHARES AMOUNT CAPITAL EARNINGS STOCK AWARD TOTAL
---------- -------- ---------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31,
1993................... 10,831,921 $108,300 $6,652,500 $10,474,900 $ -- $17,235,700
---------- -------- ---------- ----------- -------- -----------
Issuance of common
stock:
Purchase of
properties........... 55,000 500 109,500 -- -- 110,000
Exercise of employee
stock options........ 153,706 1,600 111,600 -- -- 113,200
Net income.............. -- -- -- 921,600 -- 921,600
---------- -------- ---------- ----------- -------- -----------
Balance, December 31,
1994................. 11,040,627 110,400 6,873,600 11,396,500 -- 18,380,500
---------- -------- ---------- ----------- -------- -----------
Issuance of common
stock:
Exercise of employee
stock options........ 78,000 800 45,800 -- -- 46,600
Stock award........... 90,000 900 100,400 -- (101,300) --
Amortization of stock
award................ -- -- -- -- 12,300 12,300
Net income.............. -- -- -- 1,481,500 -- 1,481,500
---------- -------- ---------- ----------- -------- -----------
Balance, December 31,
1995................. 11,208,627 112,100 7,019,800 12,878,000 (89,000) 19,920,900
---------- -------- ---------- ----------- -------- -----------
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:
Exercise of employee
stock options
(unaudited).......... 25,000 300 21,600 -- -- 21,900
Amortization of stock
award (unaudited).... -- -- -- -- 6,100 6,100
Net income (unaudited).. -- -- -- 3,909,500 -- 3,909,500
---------- -------- ---------- ----------- -------- -----------
Balance June 30, 1997
(unaudited).......... 10,485,753 $104,900 $6,638,900 $20,336,900 $(70,700) $27,010,000
========== ======== ========== =========== ======== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------------- -----------------------
1994 1995 1996 1996 1997
----------- ----------- ----------- ---------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from
operating activities:
Net income............. $ 921,600 $ 1,481,500 $ 3,549,400 $1,939,900 $ 3,909,500
Adjustment to net
income to reconcile
to cash provided by
operating activities:
Deferred income
taxes............... 97,400 112,600 213,900 43,300 279,100
Depreciation,
depletion and
amortization........ 1,848,200 2,152,100 2,309,600 1,207,400 1,220,400
Disposition of
leasehold acreage... 173,600 201,300 151,700 100,300 120,000
Employee compensation
paid in stock....... 108,200 12,300 17,900 11,800 6,100
Decrease (increase)
in notes and
accounts receivable. 39,400 (41,200) (1,480,600) 254,700 1,844,200
(Increase) decrease
in inventories...... (38,100) 172,300 (349,300) (15,800) 293,800
(Increase) decrease
in prepaid expenses. (211,000) 10,600 203,300 16,900 (72,200)
Decrease (increase)
in other assets..... 65,100 65,800 (226,400) (144,600) (54,800)
Increase (decrease)
in accounts payable
and accrued
expenses............ 92,200 42,300 3,938,200 (480,700) (1,853,100)
Increase (decrease)
in advances for
future drilling
contracts........... 1,071,900 869,700 8,327,400 (7,834,400) (14,442,600)
(Decrease) increase
in funds held for
future distribution. (474,300) 337,300 160,000 13,000 179,900
Other................ 18,300 (95,800) 90,700 (9,800) (58,800)
----------- ----------- ----------- ---------- -----------
Total adjustments... 2,790,900 3,839,300 13,356,400 (6,837,900) (12,538,000)
----------- ----------- ----------- ---------- -----------
Net cash provided by
(used in)
operating
activities......... 3,712,500 5,320,800 16,905,800 (4,898,000) (8,628,500)
----------- ----------- ----------- ---------- -----------
Cash flows from
investing activities:
Capital expenditures... (5,606,500) (3,910,400) (10,415,500) (1,092,700) (2,711,500)
Proceeds from sale of
leases................ 282,100 289,400 655,400 327,100 729,000
Proceeds from sale of
fixed assets.......... 34,200 36,700 10,800 9,000 60,300
Net cash acquired from
purchase
of subsidiary......... -- -- 1,450,000 1,450,000 --
----------- ----------- ----------- ---------- -----------
Net cash (used in)
provided by
investing
activities......... (5,290,200) (3,584,300) (8,299,300) 693,400 (1,922,200)
----------- ----------- ----------- ---------- -----------
Cash flows from
financing activities:
Proceeds from debt..... 800,000 -- 4,200,000 1,000,000 --
Proceeds from issuance
of stock.............. 5,000 46,600 135,300 120,300 21,900
Purchase of treasury
stock................. -- -- (1,000,000) (1,000,000) --
Retirement of debt..... (899,300) (636,300) (1,380,000) (800,000) (1,625,000)
----------- ----------- ----------- ---------- -----------
Net cash (used in)
provided by
financing
activities......... (94,300) (589,700) 1,955,300 (679,700) (1,603,100)
----------- ----------- ----------- ---------- -----------
Net (decrease) increase
in cash and
cash equivalents....... (1,672,000) 1,146,800 10,561,800 (4,884,300) (12,153,800)
Cash and cash
equivalents, beginning
of year................ 10,578,800 8,906,800 10,053,600 10,053,600 20,615,400
----------- ----------- ----------- ---------- -----------
Cash and cash
equivalents, end of
year................... $ 8,906,800 $10,053,600 $20,615,400 $5,169,300 $ 8,461,600
=========== =========== =========== ========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(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 segements. The different segments
are oil and gas well drilling, production and related property management 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 the Appalachian
Basin area of West Virginia, Tennessee, Pennsylvania and Ohio.
Cash Equivalents
For purposes of the statement of cash flows, the Company considers all
highly liquid debt instruments with original maturities of three months or
less to be cash equivalents.
Inventories
Inventories of well equipment, parts and supplies are valued at the lower of
average cost or market. 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.
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.
F-7
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
Upon sale or retirement of complete units of depreciable or depletable
property, the net cost thereof, less proceeds or salvage value, is credited or
charged to income. Upon retirement of a partial unit of property, the cost
thereof is charged to accumulated depreciation and depletion.
Based on the Company's experience, management believes site restoration,
dismantlement and abandonment costs 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.
Maintenance and repairs are charged to expense as incurred. Major renewals
and betterments are capitalized. Upon the sale or other disposition of assets,
the cost and related accumulated depreciation, depletion and amortization are
removed from the accounts, the proceeds applied thereto and any resulting gain
or loss is reflected in income.
Buildings
Buildings are carried at cost and depreciated on the straight-line method
over estimated useful lives of 30 years.
Retirement Plans
The Company has a 401(k) contributory retirement plan (401(k) Plan) covering
full-time employees. The Company provides a discretionary matching of employee
contributions to the plan.
The Company also has a profit sharing plan covering full-time employees. The
Company's contributions to this plan are discretionary.
During 1994, the Company established a deferred compensation arrangement
covering executive officers of the Company as a supplemental retirement
benefit.
During 1995, the Company established split-dollar life insurance
arrangements with certain executive officers. Under these arrangements,
advances are made to these officers equal to the premiums due. The advances
are collateralized by the cash surrender value of the policies. The Company
records as other assets its share of the cash surrender value of the policies.
Revenue Recognition
Oil and gas wells are drilled primarily on a contract basis. The Company
follows the percentage-of-completion method of income recognition for drilling
operations in progress.
Well operations income consists of operation charges for well upkeep,
maintenance and operating lease income on tangible well equipment.
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
F-8
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
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.
(2) NOTES AND ACCOUNTS RECEIVABLE
The Company held notes receivable from officers, directors and employees
with interest from 8% to 12% as of December 31, 1995 in the amount of $33,300
of which $200 is current.
Included in other assets are noncurrent notes and accounts receivable as of
December 31, 1995 and 1996, in the amounts of $168,400 and $5,930, net of the
allowance for doubtful accounts of $368,800 and $147,200, respectively.
The allowance for doubtful current accounts receivable as of December 31,
1995 and 1996 was $20,200 and $140,600, respectively.
(3) LONG-TERM DEBT
The Company is party to a bank credit agreement dated November 17, 1993
which, as amended, provides a borrowing base of $10,000,000 subject to
adequate natural gas reserve levels. At the request of the Company, the bank,
at its sole discretion, may increase the amount of the commitment to
$20,000,000. The Company has activated $7.5 million of the facility.
As of December 31, 1995 and 1996, the balance outstanding was $2,500,000 and
$5,320,000, respectively. No principal payments are required under the credit
agreement until maturity on December 31, 1999. Interest
F-9
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
accrues at prime with LIBOR (London Interbank Market) rate alternatives
available at the discretion of the Company. At December 31, 1996, interest
accrues at prime (8 1/4%) plus 1/4%. The Company is required to pay a
commitment fee of 1/8% to 1/4% on the unused portion of the credit facility.
The loan is 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>
<CAPTION>
1994 1995 1996
-------- -------- ----------
<S> <C> <C> <C>
Current:
Federal......................................... $ 66,600 $128,400 $ 545,600
State........................................... 12,700 109,900 341,100
-------- -------- ----------
Total current income taxes.................... 79,300 238,300 886,700
-------- -------- ----------
Deferred:
Federal......................................... 75,500 87,300 165,800
State........................................... 21,900 25,300 48,100
-------- -------- ----------
Total deferred income taxes................... 97,400 112,600 213,900
-------- -------- ----------
Total taxes................................... $176,700 $350,900 $1,100,600
======== ======== ==========
</TABLE>
Income tax expense attributable to income from continuing operations was
$176,700, $350,900 and $1,100,600 for the years ended December 31, 1994, 1995
and 1996, respectively, and differed from the amounts computed by applying the
U.S. federal income tax rate of 34 percent to pretax income from continuing
operations as a result of the following:
<TABLE>
<CAPTION>
1994 1995 1996
--------- -------- ----------
AMOUNT AMOUNT AMOUNT
--------- -------- ----------
<S> <C> <C> <C>
Computed "expected" tax........................ $ 373,400 $623,000 $1,581,000
State income tax............................... 71,200 108,800 249,900
Percentage depletion........................... (136,000) (155,900) (205,800)
Nonconventional source fuel credit............. (18,000) (127,300) (510,500)
Adjustment to oil and gas properties........... (132,700) -- --
Adjustments to valuation allowance............. -- (100,700) --
Other.......................................... 18,800 3,000 (14,000)
--------- -------- ----------
$ 176,700 $350,900 $1,100,600
========= ======== ==========
</TABLE>
F-10
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at December
31, 1995 and 1996 are presented below:
<TABLE>
<CAPTION>
1995 1996
----------- -----------
<S> <C> <C>
Deferred tax assets:
Drilling notes, principally due to allowance for
doubtful accounts................................. $ 671,300 $ 465,800
Investment tax credit carryforwards................ 233,300 45,200
Alternative minimum tax credit carryforwards
(Section 29)...................................... 909,400 926,600
Other.............................................. 440,600 550,800
----------- -----------
Total gross deferred tax assets.................. 2,254,600 1,988,400
Less valuation allowance......................... (941,300) (926,600)
----------- -----------
Deferred tax assets.............................. 1,313,300 1,061,800
Less current deferred tax assets (included in
prepaid expenses)............................... (386,200) (376,100)
----------- -----------
Net non-current deferred tax assets.................. 927,100 685,700
Deferred tax liabilities:
Plant and equipment, principally due to differences
in depreciation
and amortization.................................. (3,848,000) (3,826,500)
----------- -----------
Total gross deferred tax liabilities............. (3,848,000) (3,826,500)
----------- -----------
Net deferred tax liability....................... $(2,920,900) $(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 net changes in the total valuation allowance were for the years ended
December 31, 1994 and 1995, an increase of $45,000 and $98,600, respectively,
and for the year ended December 31, 1996 a decrease of $14,700.
At December 31, 1996, the Company has investment tax credit carryforwards
for federal income tax purposes of approximately $45,200 which are available
to reduce future federal income taxes through 2000. In addition, the Company
has alternative minimum tax credit carryforwards (Section 29) of approximately
$926,600 which are available to reduce future federal regular income taxes
over an indefinite period.
(5) COMMON STOCK
Options
Options amounting to 210,000 shares were granted during 1995 to certain
employees and directors under the Company's Stock Option Plans. These options
were granted at market value as of the date of grant and vest over a two year
period. The outstanding options expire from 1997 to 2005.
The estimated fair value of the options granted during 1995 was $0.67 per
option. The fair value was estimated using the Black-Scholes option pricing
model with the following assumptions: risk-free interest rate of 5.8%,
expected dividend yield of 0%, expected volatility of 51% and expected life of
7 years.
F-11
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
<TABLE>
<CAPTION>
NUMBER
OF SHARES AVERAGE RANGE
--------- ------- -----------
<S> <C> <C> <C>
Outstanding December 31, 1993................... 2,182,250 $0.71 $ 0.38-1.63
Granted......................................... -- -- --
Exercised....................................... (226,250) 0.50 0.44-0.69
Expired......................................... -- -- --
--------- ===== -----------
Outstanding December 31, 1994................... 1,956,000 0.77 0.38-1.63
Granted......................................... 210,000 1.13 1.13-1.13
Exercised....................................... (78,000) 0.60 0.56-0.72
Expired......................................... (235,350) 0.68 0.38-1.63
--------- ----- -----------
Outstanding December 31, 1995................... 1,852,650 0.91 0.50-1.63
Granted......................................... -- -- --
Exercised....................................... (230,000) 0.72 0.50-1.125
Expired......................................... (40,000) 0.80 0.50-1.625
--------- ----- -----------
Outstanding December 31, 1996................... 1,582,650 $0.94 $0.50-1.625
========= ===== ===========
</TABLE>
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>
<CAPTION>
1995 1996
---------------------- ----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Net income........................ $1,481,500 $1,474,400 $3,549,400 $3,473,250
========== ========== ========== ==========
Earnings per share................ $ 0.13 $ 0.13 $ 0.31 $ 0.30
========== ========== ========== ==========
</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
National Market 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.
F-12
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(6) EMPLOYEE BENEFIT PLANS
The Company made 401(k) Plan contributions of $68,700, $71,800 and $139,800
for 1994, 1995 and 1996, respectively.
The Company has a profit sharing plan (the Plan) covering full-time
employees. The Company contributed $28,500 and $50,000 to the plan in cash
during 1995 and 1996, respectively. The Company did not make a contribution to
the Plan during 1994.
During 1995 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 $12,200 in 1995 and
1996.
At December 31, 1995 and 1996, the Company has recorded as other assets
$60,000 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
Earnings per share is based on the weighted average number of common and
common equivalent shares outstanding of 11,990,497 for 1994, 11,606,690 for
1995 and 11,573,429 for 1996. Stock options are considered to be common stock
equivalents and, to the extent appropriate, have been added to the weighted
average common shares outstanding. Fully diluted earnings per share have not
been presented as the inclusion of such additional shares would not create
significant dilution.
(8) TRANSACTIONS WITH AFFILIATES
As part of its duties as well operator, the Company received $12,834,300 in
1994, $11,397,000 in 1995 and $18,234,200 in 1996 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 $4,041,600 in 1994, $4,003,500 in 1995 and $6,435,700 in
1996 for those services. During 1994, 1995 and 1996, the Company paid
$127,900, $38,500 and $35,400, respectively to the Corporate Secretary's law
firm for various legal services.
(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 16.1% of total revenues in 1996.
The Company is not party to any legal action that would materially affect
the Company's operations or financial statements.
F-13
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(10) SUPPLEMENTAL DISCLOSURE OF CASH FLOWS
The Company paid $300,200, $319,700 and $380,000 for interest in 1994, 1995
and 1996, respectively. The Company paid income taxes in 1994 and 1996 in the
amounts of $312,500 and $664,300, respectively.
(11) NONCASH FINANCING AND INVESTING ACTIVITIES
In 1994 the Company issued 55,000 shares of common stock for the purchase of
producing properties. Also in 1994, employees exercised stock options for
143,706 shares of common stock and surrendered options for 72,544 common
shares in lieu of cash payments in connection with the options exercised. This
resulted in compensation expense of $108,200.
(12) 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>
<CAPTION>
1995 1996
----------- -----------
<S> <C> <C>
Revenues................................................ $35,361,800 $53,091,400
=========== ===========
Net income.............................................. $ 1,546,900 $ 3,592,800
=========== ===========
Earnings per share...................................... $ 0.13 $ 0.31
=========== ===========
</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.
(13) 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, 1996, the Company had futures contracts for the sale of
$3,869,900 of natural gas maturing in 1997. 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 $217,770 at December 31, 1996.
F-14
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
The Company is required to maintain margin deposits with brokers for
outstanding futures contracts. As of December 31, 1996, cash in the amount of
$1,734,900 was on deposit.
(14) 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>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
---------- ---------- ----------
<S> <C> <C> <C>
Property acquisition cost:
Proved undeveloped properties............... $ 426,200 $ 167,800 $ 543,600
Producing properties........................ 1,332,100 218,500 3,211,800
Development costs........................... 2,260,800 2,977,700 5,344,900
---------- ---------- ----------
$4,019,100 $3,364,000 $9,100,300
========== ========== ==========
</TABLE>
Property acquisition costs include costs incurred to purchase, lease or
otherwise acquire a property. Exploration costs include the cost of geological
and geophysical activity, dry holes and drilling and equipping exploratory
wells. Development costs include costs incurred to gain access to and prepare
development well locations for drilling, to drill and equip development wells
and to provide facilities to extract, treat, gather and store oil and gas.
(15) 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>
<CAPTION>
DECEMBER 31,
-----------------------
1995 1996
----------- -----------
<S> <C> <C>
Proved properties:
Intangible drilling costs............................ $16,582,000 $19,572,400
Tangible well equipment.............................. 16,831,800 21,999,600
Well equipment leased to others...................... 4,063,600 4,063,600
Undeveloped properties............................... 514,600 890,100
----------- -----------
37,992,000 46,525,700
Less accumulated depreciation, depletion and
amortization...................................... 14,529,900 15,837,800
----------- -----------
$23,462,100 $30,687,800
=========== ===========
</TABLE>
F-15
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(16) 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>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
---------- ---------- ----------
<S> <C> <C> <C>
Revenue:
Oil and gas sales........................... $2,610,100 $2,534,000 $4,674,900
Expenses:
Production costs............................ 734,700 596,000 963,600
Depreciation, depletion and amortization.... 922,300 1,000,700 1,248,200
---------- ---------- ----------
1,657,000 1,596,700 2,211,800
---------- ---------- ----------
Results of operations for oil and gas
producing activities before provision for
income taxes............................... 953,100 937,300 2,463,100
Provision for income taxes.................... 146,600 137,800 519,600
---------- ---------- ----------
Results of operations for oil and gas
producing activities
(excluding corporate over-head and interest
costs)..................................... $ 806,500 $ 799,500 $1,943,500
========== ========== ==========
</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.
F-16
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(17) NET PROVED OIL AND GAS RESERVES (UNAUDITED)
The proved reserves of oil and gas of the Company as estimated by the
Company's petroleum engineers at December 31, 1994 and 1995 and by an
independent petroleum engineer, Wright & Company, Inc., at December 31, 1996.
These reserves have been prepared in compliance with the Securities and
Exchange Commission rules based on year end prices. Since December 31, 1996
prices have declined to seasonal levels. 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>
<CAPTION>
OIL (BBLS)
----------------------------------
1994 1995 1996
---------- ---------- ----------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year........................ 91,000 79,000 140,000
Revisions of previous estimates.......... (1,000) 72,000 (30,000)
---------- ---------- ----------
Beginning of year as revised............. 90,000 151,000 110,000
Dispositions............................. -- -- (49,000)
Acquisitions............................. -- -- 27,000
Production............................... (11,000) (11,000) (7,000)
---------- ---------- ----------
End of year.............................. 79,000 140,000 81,000
========== ========== ==========
Proved developed reserves:
Beginning of year........................ 91,000 79,000 140,000
========== ========== ==========
End of year.............................. 79,000 140,000 81,000
========== ========== ==========
<CAPTION>
GAS (MCF)
----------------------------------
1994 1995 1996
---------- ---------- ----------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year........................ 24,660,000 32,225,000 33,829,000
Revisions of previous estimates.......... 4,472,000 686,000 (1,037,000)
---------- ---------- ----------
Beginning of year as revised............. 29,132,000 32,911,000 32,792,000
New discoveries and extensions........... 2,345,000 2,119,000 2,613,000
Disposition.............................. -- -- (127,000)
Acquisitions............................. 1,943,000 135,000 9,529,000
Production............................... (1,195,000) (1,336,000) (1,495,000)
---------- ---------- ----------
End of year.............................. 32,225,000 33,829,000 43,312,000
========== ========== ==========
Proved developed reserves:
Beginning of year........................ 20,181,000 27,746,000 29,326,000
========== ========== ==========
End of year.............................. 27,746,000 29,326,000 35,516,000
========== ========== ==========
</TABLE>
(18) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED)
Summarized in the following table is information for the Company with
respect to the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves. Future cash inflows are derived by
applying current oil and gas prices to estimated future production. Future
production, development, site restoration and abandonment costs are derived
based on current costs assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the statutory rate in
effect at the
F-17
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
end of each year to the future pretax net cash flows, less the tax basis of
the properties and gives effect to permanent differences, tax credits and
allowances related to the properties.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------
1994 1995 1996
------------ ------------ ------------
<S> <C> <C> <C>
Future estimated cash flows.......... $ 73,316,000 $ 99,478,000 $193,800,000
Future estimated production and
development costs................... (24,370,000) (29,288,000) (59,806,000)
Future estimated income tax expense.. (13,950,000) (20,004,000) (33,499,000)
------------ ------------ ------------
Future net cash flows.............. 34,996,000 50,186,000 100,495,000
10% annual discount for estimated
timing of cash flows................ (20,551,000) (29,126,000) (66,233,000)
------------ ------------ ------------
Standardized measure of discounted
future estimated
net cash flows.................... $ 14,445,000 $ 21,060,000 $ 34,262,000
============ ============ ============
</TABLE>
The following table summarizes the principal sources of change in the
standardized measure of discounted future estimated net cash flows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1994 1995 1996
----------- ----------- ------------
<S> <C> <C> <C>
Sales of oil and gas production, net of
production costs...................... $(1,875,000) $(1,938,000) $ (3,711,000)
Net changes in prices and production
costs................................. (9,560,000) 17,024,000 42,384,000
Extensions, discoveries and improved
recovery, less related cost........... 3,875,000 4,609,000 9,659,000
Acquisitions........................... 2,745,000 294,000 17,775,000
Development costs incurred during the
period................................ 2,261,000 2,978,000 5,345,000
Revisions of previous quantity
estimates............................. 8,222,000 1,700,000 (2,902,000)
Changes in estimated income taxes...... (882,000) (6,054,000) (13,495,000)
Accretion of discount.................. (1,785,000) (8,575,000) (37,107,000)
Other.................................. (2,574,000) (3,423,000) (4,746,000)
----------- ----------- ------------
$ 427,000 $ 6,615,000 $ 13,202,000
=========== =========== ============
</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.
F-18
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(19) BUSINESS SEGMENTS
Information on the Company's operations by business segment are as follows for
the years ended December 31:
<TABLE>
<CAPTION>
1994 1995 1996
----------- ------------ -----------
<S> <C> <C> <C>
Revenues:
Drilling and production................. $21,250,800 $ 20,360,100 $27,940,200
Marketing and pipeline.................. 2,031,000 1,482,400 20,737,900
----------- ------------ -----------
$23,281,800 $ 21,842,500 $48,678,100
=========== ============ ===========
Operating profit:
Drilling and production................. $ 3,302,800 $ 3,714,300 $ 6,207,000
Marketing and pipeline.................. (224,900) (105,600) 191,400
----------- ------------ -----------
3,077,900 3,608,700 6,398,400
----------- ------------ -----------
General and administrative expense...... (2,203,800) (1,960,600) (2,304,000)
Interest expense........................ (300,200) (319,700) (380,000)
Interest income and other............... 524,400 504,000 935,600
----------- ------------ -----------
Income before income taxes................ $ 1,098,300 $ 1,832,400 $ 4,650,000
=========== ============ ===========
Depreciation, depletion and amortization:
Drilling and production................. $ 1,696,800 $ 2,008,000 $ 2,153,900
Marketing and pipeline.................. 151,400 144,100 155,700
----------- ------------ -----------
$ 1,848,200 $ 2,152,100 $ 2,309,600
=========== ============ ===========
Identifiable assets:
Drilling and production................. $36,381,000 $ 39,016,000 $54,847,000
Marketing and pipeline.................. 1,383,600 1,067,700 8,005,100
Corporate............................... 560,700 536,400 752,100
----------- ------------ -----------
$38,325,300 $ 40,620,100 $63,604,200
=========== ============ ===========
Capital expenditures:
Drilling and production................. $ 5,478,000 $ 3,817,700 $10,059,900
Marketing and pipeline.................. 112,200 86,900 124,200
Corporate............................... 16,300 5,800 231,400
----------- ------------ -----------
$ 5,606,500 $ 3,910,400 $10,415,500
=========== ============ ===========
</TABLE>
F-19
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(20) QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 1995 and
1996, are as follows:
<TABLE>
<CAPTION>
1995
-----------------------------------------------------------
QUARTER YEAR
----------------------------------------------- -----------
FIRST SECOND THIRD FOURTH
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues................ $ 9,537,000 $ 4,432,800 $ 3,582,500 $ 4,794,200 $22,346,500
Cost of operations...... 8,034,500 3,621,700 2,764,500 3,813,100 18,233,800
----------- ----------- ----------- ----------- -----------
Gross profit.......... 1,502,500 811,100 818,000 981,100 4,112,700
General and
administrative
expenses............... 450,300 520,900 600,700 388,700 1,960,600
Interest expense........ 83,400 76,300 71,000 89,000 319,700
----------- ----------- ----------- ----------- -----------
533,700 597,200 671,700 477,700 2,280,300
----------- ----------- ----------- ----------- -----------
Income before income
taxes.................. 968,800 213,900 146,300 503,400 1,832,400
Income taxes............ 240,300 53,000 36,300 21,300 350,900
----------- ----------- ----------- ----------- -----------
Net income............ $ 728,500 $ 160,900 $ 110,000 $ 482,100 $ 1,481,500
=========== =========== =========== =========== ===========
Primary earnings per
share................ $ 0.06 $ 0.02 $ 0.01 $ 0.04 $ 0.13
=========== =========== =========== =========== ===========
<CAPTION>
1996
-----------------------------------------------------------
QUARTER YEAR
----------------------------------------------- -----------
FIRST SECOND(1) THIRD(1) FOURTH(1)
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
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
=========== =========== =========== =========== ===========
Primary earnings per
share................ $ 0.11 $ 0.06 $ 0.04 $ 0.10 $ 0.31
=========== =========== =========== =========== ===========
</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 12.
F-20
<PAGE>
Appendix A
Letterhead of Wright & Company, Inc.
September 19, 1997
Petroleum Development Corporation
103 East Main Street
P. O. Box 26
Bridgeport, WV 26330
ATTENTION: Mr. Steven R. Williams
SUBJECT: SUMMARY REPORT
Evaluation of Oil and Gas Reserves to the
Interests of Petroleum Development Corporation
Effective July 1, 1997
Pursuant to the Requirements of the
Securities and Exchange Commission
Job 7.411
Wright and Company, Inc. (Wright) has performed an evaluation to estimate
proved reserves and cash flow from certain oil and gas properties to the subject
interest. This evaluation was authorized by Mr. Steven R. Williams of Petroleum
Development Corporation (PDC). Projections of the reserves and cash flow to the
evaluated interests were based on economic parameters and operating conditions
considered applicable as of July 1, 1997, and are pursuant to the financial
reporting requirements of the Securities and Exchange Commission. The results
of the evaluation are presented in detail in the attached summary tables. The
following is a summary of results effective July 1, 1997:
<TABLE>
<CAPTION>
Proved
Proved Proved Developed
Developed Developed Nonproducing Proved Total
Producing Nonproducing Behind Pipe Undeveloped Proved
(PDP) (PDNP) (PDNP-BP) (PUD)
<S> <C> <C> <C> <C> <C>
Net Reserves to the
Evaluated Interests
Oil, MBBL: 41.174 0.000 0.000 0.000 41.174
Gas, MMCF: 21,107.380 5,044.289 12,088.450 9,092.687 47,332.800
Cash Flow (BTAX), M$
Undiscounted:
Discounted at 10% 30,891.650 5,132.763 18,370.590 8,994.116 63,389.120
Per Annum: 15,320.300 2,484.540 2,988.330 2,516.036 23,309.200
</TABLE>
5200 Maryland Way . Suite 100 2959 Briarpark Drive . Suite 138
Brentwood, Tennessee 37027 Houston, Texas 77042
(615)370-0755 Fax:(615)370-0756 (713)977-7655 Fax:(713)789-3591
A-1
<PAGE>
Mr. Steven R. Williams
Petroleum Development Corporation
September 19, 1997
Page 2
All data utilized in the preparation of this report with respect to
ownership, well information, and economic parameters, as applicable, were
provided by PDC. All data have been reviewed for reasonableness and, unless
obvious errors were detected, have been accepted as correct by Wright and
Company without further independent verification.
Oil and gas reserves were evaluated for the proved developed producing
(PDP), proved developed non producing (PDNP), proved developed nonproducing
behind pipe (PDNP-BP), and proved undeveloped (PUD) reserves categories. The
attached Definitions of Oil and Gas Reserves describe all categories of proved
reserves.
The individual projections of lease reserves and economics utilized to
generate these summaries contain certain data that describe the production
forecasts and all associated evaluation parameters, such as interests, severance
and ad valorem taxes, product prices, operating expenses, investments, salvage
values, and abandonments costs, as applicable.
It should be noted that revisions to the projections of reserves and
economics included in this SUMMARY REPORT may be required if the provided data
are revised for any reason.
Wright is an independent consulting firm and does not own any interests in
the properties covered by this report. No employee, officer, or director of
Wright is an employee, office, or director of PDC. Neither the employment of,
nor the compensation received by Wright, is contingent upon the values assigned
to the properties covered by this report.
It has been a pleasure to serve you by preparing this evaluation. All
related data will be retained in our files and are available for your review.
Very truly yours,
/s/ Wright & Company, Inc.
Wright & Company, Inc.
DRW/JDD/jrw
Job 7.411/PDCLT2.doc
A-2
<PAGE>
DEFINITIONS OF OIL AND GAS RESERVES1
PURSUANT TO THE REQUIREMENTS OF THE
SECURITIES EXCHANGE ACT
I. PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on
escalations based upon future conditions.
A. Reservoirs are considered proved if economic
producibility is supported by either actual production
or conclusive formation test. The area of a reservoir
considered proved includes:
1. that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any; and
2. the immediately adjoining portions not yet
drilled, but which can be reasonably judged as
economically productive on the basis of available
geological and engineering data. In the absence
of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
B. Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was
based.
C. Estimates of proved reserves do not include the following:
1. oil that may become available from known reservoirs but
is classified separately as "indicated additional
reserves";
2. crude oil, natural gas, and natural gas liquids, the
recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics,
or economic factors:
3. crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; nor those quantities
being held in underground or surface storage.
4. crude oil, natural gas, and natural gas liquids, that
may be recovered from oil shales, coal and other such
sources.
II. PROVED DEVELOPED OIL AND GAS RESERVES*
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas
expected to be obtained through the application of fluid
<PAGE>
injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves"
only after testing by a pilot project or after the operation
of an installed program has confirmed through production
response that increased recovery will be achieved.
III. PROVED UNDEVELOPED OIL AND GAS RESERVES
Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where
it can be demonstrated with certainty that there is continuity
of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same
reservoir.
- ---------------
1SEC Accounting Rules, Commerce Clearing House, Inc. October 1981,
Paragraph 290, Regulation 210.4-10, p.329.
2Wright & Company, Inc. may separate proved developed reserves into
proved developed producing and proved
developed nonproducing reserves. This is to identify proved developed
producing reserves as those to be recovered from actively producing wells.
Proved developed nonproducing reserves are those to be recovered from
wells or intervals within wells, which are completed but shut-in waiting
on equipment or pipeline connections, or wells where a relatively minor
expenditure is required for recompletion to another zone.
Wright & Company, Inc.
Petroleum Consultants
A-3
<PAGE>
<TABLE>
<CAPTION>
TOTAL PROVED DATE : 09/18/97
PDP, PDNP, PDNP-BP, & PU TIME : 15:04:57
TO THE INTERESTS OF DBS FILE : PDC997
PETROLEUM DEVELOPMENT CORP. SETUP FILE : PDC997
SEQ NUMBER : ******
R E S E R V E S A N D E C O N O M I C S
- - - - - - - - - - - - - - - - - - - -
JOB 7.411 PURSUANT TO SEC
AS OF 7/97
---PRICES--- --------- OPERATIONS M$ -------- 10.0%
-END- --GROSS PRODUCTION-- ---NET PRODUCTION--- OIL GAS NET OPER SEV + ADV NET OPER CAPITAL CASH FLOW CUM. DISC
MO-YR OIL, MBBL GAS, MMCF OIL, MBBL GAS, MMCF $/B $/M REVENUES TAXES EXPENSES COSTS M$ BTAX, M$ BTAX, M$
----- --------- --------- --------- --------- ----- ----- ---------- --------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12-97 8.305 4109.860 2.852 1012.067 16.00 2.388 2462.399 178.538 456.119 3533.945 (1706.199) (1665.231)
12-98 15.294 8776.428 5.219 2462.081 16.00 2.404 6003.422 440.206 1256.306 3029.642 1277.264 (508.487)
12-99 13.209 8982.012 4.410 2764.384 16.00 2.414 6744.882 503.322 1491.402 276.770 4473.386 3185.963
12-00 11.511 8424.032 3.672 2676.639 16.00 2.417 6527.270 489.592 1482.624 64.029 4491.027 6559.202
12-01 9.349 7817.690 2.760 2512.219 16.00 2.420 6123.513 460.759 1445.235 50.454 4167.063 9405.206
12-02 8.492 7197.508 2.465 2305.010 16.00 2.423 5623.679 423.477 1396.554 38.026 3765.622 11743.210
12-03 7.621 6650.317 2.194 2087.999 16.00 2.423 5094.206 383.465 1322.520 56.073 3332.147 13623.920
12-04 6.497 6219.932 1.843 1925.071 16.00 2.422 4691.305 353.175 1279.677 61.428 2997.027 15161.580
12-05 5.831 5871.442 1.660 1802.269 16.00 2.423 4392.900 330.784 1247.533 89.769 2724.816 16431.890
12-06 5.287 5508.369 1.497 1680.939 16.00 2.421 4094.262 308.219 1219.341 38.341 2528.361 17504.060
12-07 4.719 5177.555 1.338 1558.428 16.00 2.421 3794.502 285.604 1174.335 39.715 2294.845 18388.850
12-08 4.284 4923.301 1.223 1464.686 16.00 2.420 3564.794 268.247 1135.537 40.852 2120.155 19131.670
12-09 3.873 4692.421 1.107 1382.390 16.00 2.419 3361.492 252.993 1107.091 39.380 1962.029 19756.620
12-10 3.482 4508.674 .990 1309.865 16.00 2.418 3182.553 239.526 1083.466 66.511 1793.050 20275.780
12-11 3.167 4326.484 .883 1244.429 16.00 2.416 3020.812 227.356 1053.325 41.970 1698.159 20722.850
S TOT 110.920 93186.020 34.112 28188.480 16.00 2.417 68681.980 5145.264 18151.070 7466.904 37918.750 20722.850
AFTER 21.923 81373.010 7.062 19144.330 16.00 2.405 46154.130 3497.193 15849.250 1337.299 25470.370 23309.200
TOTAL 132.843 174559.000 41.174 47332.800 16.00 2.412 114836.100 8642.457 34000.320 8804.203 63389.120 23309.200
</TABLE>
<TABLE>
<CAPTION>
CUM. 636.889 64878.080 NET OIL REVENUES (M$) 658.787 --------- PRESENT WORTH PROFILE ---------
NET GAS REVENUES (M$) 114177.300 DISC PW OF NET DISC PW OF NET
ULT. 769.732 239437.100 TOTAL REVENUES (M$) 114836.100 RATE BTAX, M$ RATE BTAX, M$
---- --------- ---- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
BTAX RATE OF RETURN (PCT) 100.00 PRODUCT LIFE (YEARS) 90.417 .0 63389.100 35.0 7417.075
BTAX PAYOUT YEARS 1.60 DISCOUNT RATE (PCT) 10.000 5.0 34684.510 40.0 6296.193
BTAX PAYOUT YEARS (DISC) 1.64 GROSS OIL WELLS 40.0 10.0 23309.200 50.0 4669.705
BTAX NET INCOME/INVEST 8.20 GROSS GAS WELLS 1657.0 15.0 17196.380 60.0 3556.656
BTAX NET INCOME/INVEST(DISC) 4.39 GROSS WELLS 1697.0 20.0 13370.610 70.0 2755.139
25.0 10752.880 80.0 2155.726
INITIAL W.I. % 28.2432 INITIAL NET OIL % 34.4241 30.0 8853.597 90.0 1694.113
FINAL W.I. % 19.8792 FINAL NET OIL % 72.8336 100.0 1330.211
PRODUCTION START DATE 1/94 INITIAL NET GAS % 25.3540
REPORT DATE 7/97 FINAL NET GAS % 19.7882
</TABLE>
JOHN D. DYER/PROJ. MANAGER
WRIGHT & COMPANY, INC.
BRENTWOOD, TN/HOUSTON, TX
A-4
<PAGE>
<TABLE>
<CAPTION>
TOTAL PROVED DEV. PRODUCING DATE : 09/18/97
PDP TIME : 15:02:37
TO THE INTERESTS OF
DBS FILE : PDC997
PETROLEUM DEVELOPMENT CORP. SETUP FILE : PDC997
SEQ NUMBER : ******
R E S E R V E S A N D E C O N O M I C S
- - - - - - - - - - - - - - - - - - - -
JOB 7.411 PURSUANT TO SEC
AS OF 7/97
---PRICES--- --------- OPERATIONS M$ -------- 10.0%
-END- --GROSS PRODUCTION-- ---NET PRODUCTION--- OIL GAS NET OPER SEV + ADV NET OPER CAPITAL CASH FLOW CUM. DISC
MO-YR OIL, MBBL GAS, MMCF OIL, MBBL GAS, MMCF $/B $/M REVENUES TAXES EXPENSES COSTS M$ BTAX, M$ BTAX, M$
----- --------- --------- --------- --------- ----- ----- ---------- --------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12-97 8.305 3752.487 2.852 865.840 16.00 2.380 2106.434 154.982 397.720 .000 1553.736 1517.153
12-98 15.294 6632.159 5.219 1557.207 16.00 2.383 3794.332 280.164 784.897 .000 2729.268 3998.308
12-99 13.209 5820.304 4.410 1384.330 16.00 2.387 3375.158 250.107 757.198 .000 2367.852 5955.232
12-00 11.511 5228.007 3.672 1251.899 16.00 2.390 3050.440 226.488 722.914 .000 2101.039 7533.782
12-01 9.349 4771.799 2.760 1148.870 16.00 2.390 2790.247 207.867 691.779 .000 1890.599 8825.089
12-02 8.492 4399.210 2.465 1062.612 16.00 2.391 2580.165 192.459 672.613 .000 1715.095 9890.045
12-03 7.621 4078.892 2.194 979.080 16.00 2.394 2378.929 177.493 634.761 .000 1566.675 10774.390
12-04 6.497 3811.395 1.843 916.755 16.00 2.395 2224.838 166.160 618.967 .000 1439.712 11513.200
12-05 5.831 3572.855 1.660 860.306 16.00 2.395 2087.265 155.923 604.086 .000 1327.257 12132.380
12-06 5.287 3368.366 1.497 810.541 16.00 2.396 1965.975 146.887 592.751 .000 1226.338 12652.460
12-07 4.719 3163.858 1.338 755.783 16.00 2.398 1833.577 137.073 562.370 .000 1134.131 13089.720
12-08 4.284 2976.448 1.223 706.200 16.00 2.399 1713.661 128.040 535.644 .000 1049.975 13457.740
12-09 3.873 2801.487 1.107 663.337 16.00 2.399 1608.942 120.251 517.466 .000 971.226 13767.200
12-10 3.482 2638.361 .990 623.530 16.00 2.399 1511.530 112.927 501.464 .000 897.140 14027.070
12-11 3.167 2476.193 .883 582.389 16.00 2.397 1410.192 105.259 477.353 .000 827.579 14245.000
S TOT 110.920 59491.820 34.112 14168.680 16.00 2.392 34431.680 2562.081 9071.981 .000 22797.620 14245.000
AFTER 21.923 31007.350 7.062 6938.697 16.00 2.395 16730.270 1249.658 7386.570 .000 8094.030 15320.300
TOTAL 132.843 90499.170 41.174 21107.380 16.00 2.393 51161.950 3811.739 16458.550 .000 30891.650 15320.300
</TABLE>
<TABLE>
<CAPTION>
CUM. 636.889 64623.180 NET OIL REVENUES (M$) 658.787 --------- PRESENT WORTH PROFILE ---------
NET GAS REVENUES (M$) 50503.150 DISC PW OF NET DISC PW OF NET
ULT. 769.732 155122.300 TOTAL REVENUES (M$) 51161.940 RATE BTAX, M$ RATE BTAX, M$
---- --------- ---- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
BTAX RATE OF RETURN (PCT) 100.00 PRODUCT LIFE (YEARS) 78.667 .0 30891.640 35.0 7384.313
BTAX PAYOUT YEARS .00 DISCOUNT RATE (PCT) 10.000 5.0 20378.510 40.0 6772.003
BTAX PAYOUT YEARS (DISC) .00 GROSS OIL WELLS 40.0 10.0 15320.290 50.0 5854.521
BTAX NET INCOME/INVEST .00 GROSS GAS WELLS 1155.0 15.0 12389.740 60.0 5197.513
BTAX NET INCOME/INVEST(DISC) .00 GROSS WELLS 1195.0 20.0 10484.310 70.0 4702.085
25.0 9145.684 80.0 4314.046
INITIAL W.I. % 28.3641 INITIAL NET OIL % 34.4241 30.0 8152.201 90.0 4001.140
FINAL W.I. % 22.5992 FINAL NET OIL % 72.8336 100.0 3742.980
PRODUCTION START DATE 1/94 INITIAL NET GAS % 24.5823
REPORT DATE 7/97 FINAL NET GAS % 19.8257
</TABLE>
JOHN D. DYER/PROJ. MANAGER
WRIGHT & COMPANY, INC.
BRENTWOOD, TN/HOUSTON, TX
A-5
<PAGE>
<TABLE>
<CAPTION>
PROVED DEV. NONPRODUCING DATE : 09/18/97
PDNP TIME : 15:02:45
TO THE INTERESTS OF DBS FILE : PDC997
PETROLEUM DEVELOPMENT CORP. SETUP FILE : PDC997
SEQ NUMBER : ******
R E S E R V E S A N D E C O N O M I C S
- - - - - - - - - - - - - - - - - - - -
JOB 7.411 PURSUANT TO SEC
AS OF 7/97
---PRICES--- --------- OPERATIONS M$ -------- 10.0%
-END- --GROSS PRODUCTION-- ---NET PRODUCTION--- OIL GAS NET OPER SEV + ADV NET OPER CAPITAL CASH FLOW CUM. DISC
MO-YR OIL, MBBL GAS, MMCF OIL, MBBL GAS, MMCF $/B $/M REVENUES TAXES EXPENSES COSTS M$ BTAX, M$ BTAX, M$
----- --------- --------- --------- --------- ----- ----- ---------- --------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12-97 .000 268.590 .000 70.170 .00 2.429 170.450 12.426 52.339 1371.349 (1265.664) (1235.070)
12-98 .000 1253.116 .000 393.871 .00 2.451 965.334 73.878 284.224 .000 607.231 (683.041)
12-99 .000 1442.077 .000 464.974 .00 2.454 1140.862 87.822 310.211 .000 742.828 (69.134)
12-00 .000 1406.666 .000 456.881 .00 2.454 1121.344 86.458 308.736 .000 726.150 476.434
12-01 .000 1333.511 .000 434.550 .00 2.455 1066.687 82.304 302.083 .000 682.299 942.453
12-02 .000 1160.508 .000 377.263 .00 2.454 925.971 71.410 283.413 .000 571.148 1297.091
12-03 .000 1018.256 .000 330.101 .00 2.454 810.115 62.437 268.017 .000 479.661 1567.847
12-04 .000 904.235 .000 292.313 .00 2.454 717.290 55.248 255.687 .000 406.355 1776.371
12-05 .000 811.079 .000 261.458 .00 2.454 641.499 49.379 245.626 .000 346.494 1938.013
12-06 .000 733.735 .000 235.860 .00 2.453 578.623 44.512 237.285 .000 296.826 2063.896
12-07 .000 668.589 .000 214.326 .00 2.453 525.731 40.418 230.277 .000 255.036 2162.224
12-08 .000 612.901 .000 195.968 .00 2.453 480.646 36.930 224.320 .000 219.396 2239.121
12-09 .000 564.691 .000 180.139 .00 2.452 441.778 33.926 219.203 .000 188.648 2299.230
12-10 .000 522.576 .000 166.366 .00 2.452 407.964 31.315 214.770 .000 161.879 2346.121
12-11 .000 485.492 .000 154.286 .00 2.452 378.313 29.028 210.897 .000 138.388 2382.563
S TOT .000 13186.020 .000 4228.525 .00 2.453 10372.610 797.492 3647.089 1371.349 4556.676 2382.563
AFTER .000 2875.430 .000 815.765 .00 2.439 1989.993 148.572 1265.335 .000 576.087 2484.540
TOTAL .000 16061.450 .000 5044.289 .00 2.451 12362.600 946.064 4912.424 1371.349 5132.763 2484.540
</TABLE>
<TABLE>
<CAPTION>
CUM. .000 254.902 NET OIL REVENUES (M$) .000 --------- PRESENT WORTH PROFILE ---------
NET GAS REVENUES (M$) 12362.600 DISC PW OF NET DISC PW OF NET
ULT. .000 16316.350 TOTAL REVENUES (M$) 12362.600 RATE BTAX, M$ RATE BTAX, M$
---- --------- ---- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
BTAX RATE OF RETURN (PCT) 56.75 PRODUCT LIFE (YEARS) 49.250 .0 5132.764 35.0 527.995
BTAX PAYOUT YEARS 2.39 DISCOUNT RATE (PCT) 10.000 5.0 3489.428 40.0 362.553
BTAX PAYOUT YEARS (DISC) 2.63 GROSS OIL WELLS .0 10.0 2484.540 50.0 116.339
BTAX NET INCOME/INVEST 4.74 GROSS GAS WELLS 49.0 15.0 1816.582 60.0 (56.070)
BTAX NET INCOME/INVEST(DISC) 2.86 GROSS WELLS 49.0 20.0 1345.744 70.0 (181.936)
25.0 998.986 80.0 (276.786)
INITIAL W.I. % 33.2506 INITIAL NET OIL % .0000 30.0 734.790 90.0 (350.065)
FINAL W.I. % 18.1265 FINAL NET OIL % .0000 100.0 (407.821)
PRODUCTION START DATE 1/94 INITIAL NET GAS % 26.9140
REPORT DATE 7/97 FINAL NET GAS % 15.7343
</TABLE>
JOHN D. DYER/PROJ. MANAGER
WRIGHT & COMPANY, INC.
BRENTWOOD, TN/HOUSTON, TX
A-6
<PAGE>
<TABLE>
<CAPTION>
TOTAL PROVED UNDEVELOPED DATE : 09/18/97
PU TIME : 15:04:56
TO THE INTERESTS OF DBS FILE : PDC997
PETROLEUM DEVELOPMENT CORP. SETUP FILE : PDC997
SEQ NUMBER : ******
R E S E R V E S A N D E C O N O M I C S
- - - - - - - - - - - - - - - - - - - -
JOB 7.411 PURSUANT TO SEC
AS OF 7/97
---PRICES--- --------- OPERATIONS M$ -------- 10.0%
-END- --GROSS PRODUCTION-- ---NET PRODUCTION--- OIL GAS NET OPER SEV + ADV NET OPER CAPITAL CASH FLOW CUM. DISC
MO-YR OIL, MBBL GAS, MMCF OIL, MBBL GAS, MMCF $/B $/M REVENUES TAXES EXPENSES COSTS M$ BTAX, M$ BTAX, M$
----- --------- --------- --------- --------- ----- ----- ---------- --------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12-97 .000 88.783 .000 76.058 .00 2.439 185.515 11.131 6.060 2162.596 (1994.272) (1947.315)
12-98 .000 541.932 .000 426.991 .00 2.448 1045.194 70.577 174.404 2854.125 (2053.912) (3814.506)
12-99 .000 1001.276 .000 743.221 .00 2.454 1824.199 133.627 388.877 .000 1301.694 (2738.726)
12-00 .000 1023.069 .000 753.415 .00 2.455 1849.907 136.958 402.498 .000 1310.451 (1754.165)
12-01 .000 991.155 .000 727.307 .00 2.456 1786.100 132.870 400.521 .000 1252.710 (898.547)
12-02 .000 909.155 .000 666.690 .00 2.456 1637.293 121.909 385.041 .000 1130.343 (196.694)
12-03 .000 793.213 .000 582.636 .00 2.456 1430.756 106.294 360.499 .000 963.964 347.439
12-04 .000 701.655 .000 516.243 .00 2.455 1267.618 93.964 341.144 .000 832.510 774.648
12-05 .000 627.737 .000 462.621 .00 2.455 1135.862 84.011 325.553 .000 726.297 1113.471
12-06 .000 566.959 .000 418.508 .00 2.455 1027.475 75.829 312.768 .000 638.878 1384.417
12-07 .000 516.210 .000 381.654 .00 2.455 936.925 68.999 302.126 .000 565.800 1602.558
12-08 .000 473.175 .000 350.371 .00 2.455 860.066 63.209 293.152 .000 503.705 1779.104
12-09 .000 435.982 .000 323.270 .00 2.455 793.491 58.209 285.500 .000 449.782 1922.418
12-10 .000 403.493 .000 299.538 .00 2.454 735.198 53.846 278.909 .000 402.442 2038.991
12-11 .000 374.871 .000 278.581 .00 2.454 683.725 50.006 273.184 .000 360.535 2133.931
S TOT .000 9448.665 .000 7007.104 .00 2.455 17199.320 1261.439 4530.237 5016.721 6390.928 2133.931
AFTER .000 2684.369 .000 2085.583 .00 2.449 5108.315 351.671 2153.455 .000 2603.188 2516.036
TOTAL .000 12133.030 .000 9092.687 .00 2.453 22307.640 1613.110 6683.692 5016.721 8994.116 2516.036
</TABLE>
<TABLE>
<CAPTION>
CUM. .000 .000 NET OIL REVENUES (M$) .000 --------- PRESENT WORTH PROFILE ---------
NET GAS REVENUES (M$) 22307.630 DISC PW OF NET DISC PW OF NET
ULT. .000 12133.030 TOTAL REVENUES (M$) 22307.630 RATE BTAX, M$ RATE BTAX, M$
---- --------- ---- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
BTAX RATE OF RETURN (PCT) 22.54 PRODUCT LIFE (YEARS) 40.750 .0 8994.114 35.0 (1042.729)
BTAX PAYOUT YEARS 4.66 DISCOUNT RATE (PCT) 10.000 5.0 4747.427 40.0 (1281.470)
BTAX PAYOUT YEARS (DISC) 5.86 GROSS OIL WELLS .0 10.0 2516.035 50.0 (1605.667)
BTAX NET INCOME/INVEST 2.79 GROSS GAS WELLS 30.0 15.0 1177.610 60.0 (1803.216)
BTAX NET INCOME/INVEST(DISC) 1.53 GROSS WELLS 30.0 20.0 305.383 70.0 (1926.026)
25.0 (295.380) 80.0 (2002.292)
INITIAL W.I. % 93.7571 INITIAL NET OIL % .0000 30.0 (725.641) 90.0 (2048.414)
FINAL W.I. % 100.0000 FINAL NET OIL % .0000 100.0 (2074.436)
PRODUCTION START DATE 1/94 INITIAL NET GAS % 77.6262
REPORT DATE 7/97 FINAL NET GAS % 85.6624
</TABLE>
JOHN D. DYER/PROJ. MANAGER
WRIGHT & COMPANY, INC.
BRENTWOOD, TN/HOUSTON, TX
A-7
<PAGE>
<TABLE>
<CAPTION>
PROVED DEV. NONPRODUCING DATE : 09/18/97
BEHIND PIPE (PDNP-BP) TIME : 15:04:51
TO THE INTERESTS OF DBS FILE : PDC997
PETROLEUM DEVELOPMENT CORP. SETUP FILE : PDC997
SEQ NUMBER : ******
R E S E R V E S A N D E C O N O M I C S
- - - - - - - - - - - - - - - - - - - -
JOB 7.411 PURSUANT TO SEC
AS OF 7/97
---PRICES--- --------- OPERATIONS M$ -------- 10.0%
-END- --GROSS PRODUCTION-- ---NET PRODUCTION--- OIL GAS NET OPER SEV + ADV NET OPER CAPITAL CASH FLOW CUM. DISC
MO-YR OIL, MBBL GAS, MMCF OIL, MBBL GAS, MMCF $/B $/M REVENUES TAXES EXPENSES COSTS M$ BTAX, M$ BTAX, M$
----- --------- --------- --------- --------- ----- ----- ---------- --------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12-97 .000 .000 .000 .000 .00 .000 .000 .000 .000 .000 .000 .000
12-98 .000 349.222 .000 84.013 .00 2.363 198.562 15.587 12.781 175.517 (5.323) (9.247)
12-99 .000 718.355 .000 171.859 .00 2.355 404.664 31.766 35.116 276.770 61.012 38.591
12-00 .000 766.290 .000 214.445 .00 2.358 505.579 39.688 48.476 64.029 353.386 303.151
12-01 .000 721.225 .000 201.492 .00 2.385 480.479 37.718 50.853 50.454 341.455 536.210
12-02 .000 728.636 .000 198.444 .00 2.420 480.250 37.700 55.487 38.026 349.037 752.765
12-03 .000 759.955 .000 196.182 .00 2.418 474.404 37.241 59.243 56.073 321.847 934.241
12-04 .000 802.647 .000 199.760 .00 2.411 481.558 37.802 63.878 61.428 318.450 1097.362
12-05 .000 859.771 .000 217.884 .00 2.425 528.275 41.470 72.269 89.769 324.768 1248.028
12-06 .000 839.308 .000 216.029 .00 2.417 522.188 40.992 76.536 38.341 366.319 1403.281
12-07 .000 828.898 .000 206.666 .00 2.411 498.269 39.114 79.562 39.715 339.878 1534.341
12-08 .000 860.778 .000 212.147 .00 2.406 510.420 40.068 82.421 40.852 347.079 1655.709
12-09 .000 890.261 .000 215.644 .00 2.399 517.281 40.607 84.922 39.380 352.373 1767.771
12-10 .000 944.244 .000 220.431 .00 2.395 527.860 41.437 88.323 66.511 331.588 1863.590
12-11 .000 989.928 .000 229.173 .00 2.394 548.582 43.064 91.891 41.970 371.657 1961.353
S TOT .000 11059.520 .000 2784.170 .00 2.399 6678.373 524.252 901.759 1078.834 4173.527 1961.353
AFTER .000 44805.870 .000 9304.281 .00 2.399 22325.550 1747.292 5043.889 1337.299 14197.070 2988.330
TOTAL .000 55865.390 .000 12088.450 .00 2.399 29003.920 2271.545 5945.648 2416.134 18370.590 2988.330
</TABLE>
<TABLE>
<CAPTION>
CUM. .000 .000 NET OIL REVENUES (M$) .000 --------- PRESENT WORTH PROFILE ---------
NET GAS REVENUES (M$) 29003.920 DISC PW OF NET DISC PW OF NET
ULT. .000 55865.390 TOTAL REVENUES (M$) 29003.920 RATE BTAX, M$ RATE BTAX, M$
---- --------- ---- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
BTAX RATE OF RETURN (PCT) 100.00 PRODUCT LIFE (YEARS) 90.417 .0 18370.580 35.0 547.496
BTAX PAYOUT YEARS 1.59 DISCOUNT RATE (PCT) 10.000 5.0 6069.142 40.0 443.107
BTAX PAYOUT YEARS (DISC) 1.69 GROSS OIL WELLS .0 10.0 2988.330 50.0 304.512
BTAX NET INCOME/INVEST 8.60 GROSS GAS WELLS 423.0 15.0 1812.450 60.0 218.429
BTAX NET INCOME/INVEST(DISC) 4.61 GROSS WELLS 423.0 20.0 1235.171 70.0 161.017
25.0 903.589 80.0 120.758
INITIAL W.I. % 20.9468 INITIAL NET OIL % .0000 30.0 692.247 90.0 91.452
FINAL W.I. % 18.9304 FINAL NET OIL % .0000 100.0 69.488
PRODUCTION START DATE 1/94 INITIAL NET GAS % 20.8839
REPORT DATE 7/97 FINAL NET GAS % 19.4672
</TABLE>
JOHN D. DYER/PROJ. MANAGER
WRIGHT & COMPANY, INC.
BRENTWOOD, TN/HOUSTON, TX
A-8
<PAGE>
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THIS OFFERING
OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY, THE SELLING STOCKHOLDERS OR ANY UNDERWRITER. THIS
PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER
TO BUY ANY SECURITIES OTHER THAN THE SHARES OF COMMON STOCK TO WHICH IT
RELATES OR AN OFFER TO, OR A SOLICITATION OF, ANY PERSON IN ANY JURISDICTION
WHERE SUCH OFFER OR SOLICITATION WOULD BE UNLAWFUL. NEITHER THE DELIVERY OF
THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES,
CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE
COMPANY, OR THAT INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME
SUBSEQUENT TO THE DATE HEREOF.
-----------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary........................................................ 1
Risk Factors.............................................................. 5
Use of Proceeds........................................................... 11
Price Range of Common Stock............................................... 11
Dividend Policy........................................................... 11
Capitalization............................................................ 12
Selected Consolidated Financial Data...................................... 13
Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 14
Business.................................................................. 20
Management................................................................ 35
Certain Transactions...................................................... 41
Principal and Selling Stockholders........................................ 42
Description of Capital Stock.............................................. 43
Shares Eligible for Future Sale........................................... 45
Underwriting.............................................................. 46
Legal Matters............................................................. 47
Experts................................................................... 47
Available Information..................................................... 48
Incorporation of Certain Documents by Reference........................... 48
Glossary of Certain Industry Terms........................................ 49
Index to Consolidated Financial Statements................................ F-1
Summary Reserve Report.................................................... A-1
</TABLE>
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
3,850,000 SHARES
[LOGO OF PETROLEUM DEVELOPMENT CORPORATION APPEARS HERE]
PETROLEUM DEVELOPMENT CORPORATION
COMMON STOCK
-------------------
PROSPECTUS
-------------------
PENNSYLVANIA MERCHANT GROUP LTD
, 1997
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
<TABLE>
<S> <C>
SEC Registration Fee.............................................. $ 11,699.34
NASD Filing Fee................................................... 4,360.78
Nasdaq Additional Listing Application Fee......................... 17,500.00
Blue Sky Qualification Fees and Expenses.......................... 12,000.00*
Registrar and Transfer Agent Fees................................. 10,000.00*
Legal Fees and Expenses........................................... 150,000.00*
Accountants' Fees and Expenses.................................... 60,000.00*
Printing and Engraving............................................ 100,000.00*
Miscellaneous..................................................... 34,439.88*
-----------
Total........................................................... $400,000.00*
===========
</TABLE>
- --------
* Estimated.
The Company will bear all of the foregoing expenses.
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
The Form of Underwriting Agreement filed as Exhibit 1.1 hereto contains
certain provisions relating to indemnification.
The Nevada general corporation law authorizes the registrant to grant
indemnities to directors and officers in terms sufficiently broad to permit
such indemnification under certain circumstances for liabilities (including
reimbursement for expenses incurred) arising under the Securities Act.
The Company's By-Laws provide that the Company shall indemnify any director,
officer, employee, or other agent of the Company who is or was a party, or is
threatened to be made a party, to any proceeding (other than an action by or
in the right of the Company to procure a judgment in its favor) by reason of
the fact that such person is or was an agent of the Company against expenses,
judgments, fines, settlements, and other amounts actually and reasonably
incurred in connection with such proceeding, if that person acted in good
faith and in a manner that person reasonably believed to be in the best
interests of the Company, and in the case of a criminal proceeding, had no
reasonable cause to believe that the conduct was unlawful. In an action by or
in the right of the Company to procure a judgment in its favor, the Company
shall provide indemnification only against expenses actually and reasonably
incurred in connection with the defense or settlement of the action, and, in
addition to the requirements of acting in good faith and in the best interest
of the Company, the Company shall provide indemnification only if the person
acted with such care, including reasonable inquiry, as an ordinarily prudent
person in a like position would use under similar circumstances. However, the
Company will not provide indemnification: (i) in actions by or in the right of
the Company if the person is adjudged to be liable to the Company in the
performance of the person's duty to the Company, unless and only to the extent
that the court in the proceeding determines that the person is fairly and
reasonably entitled to indemnity for expenses; (ii) against amounts paid in
settling or otherwise disposing of an action, with or without court approval;
or (iii) against expenses incurred in defending an action which is settled or
otherwise disposed of without court approval.
The Company has entered into separate indemnification agreements with each
of its officers and directors whereby the Company has agreed to indemnify the
director or officer against all expenses, including attorneys' fees, and other
amounts reasonably incurred by the officer or director in connection with any
threatened, pending or completed civil, criminal, administrative or
investigative action or proceeding to which such person is party by reason of
the fact he is or was a director or officer, as the case may be, of the
Company, if the person acted in good faith and in a manner reasonably believed
to be in or not opposed to the best interests of the Company, and, with
respect to any criminal action or proceeding, the person had no reasonable
cause to believe such conduct to be unlawful. The agreements provide for the
advancement of expenses and that the Company has the
II-1
<PAGE>
right to purchase and maintain insurance on behalf of the director or officer
against any liability or liabilities asserted against him, whether or not the
Company would have the power to indemnify the person against such liability
under any provision of the agreement. The Company has agreed to indemnify such
person against expenses actually and reasonably incurred in connection with
any action in which the person has been successful on the merits or otherwise.
Indemnification must also be provided by the Company (unless ordered otherwise
by a court) only as authorized in the specific case upon a determination that
the indemnification of the person is appropriate because he has met the
applicable standard of conduct described in the agreement made by (i) the
Board of Directors, by a majority vote of a quorum consisting of directors who
are not parties to such action or proceeding, (ii) by independent legal
counsel in a written opinion or (iii) the stockholders of the Company.
ITEM 16. EXHIBITS.
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
<C> <S>
1.1 Form of Underwriting Agreement.
3.1 Articles of Incorporation of the Company, as amended.
3.2 Amended and Restated By-Laws of the Company.
4.1 Form of Warrant (incorporated by reference to Exhibit 4 of the
Company's current report on Form 8-K filed on September 17, 1997).
5.1 Opinion of Duane, Morris & Heckscher LLP.
MANAGEMENT CONTRACTS
10.1 Employment Agreement dated as of July 1, 1988 between the Company
and James N. Ryan, and all amendments thereto.
10.2 Employment Agreement dated as of July 1, 1988 between the Company
and Steven R. Williams, and all amendments thereto.
10.3 Employment Agreement dated as of July 1, 1988 between the Company
and Dale G. Rettinger, and all amendments thereto.
10.4 Employment Agreement dated as of April 1, 1996 between the Company
and Thomas E. Riley.
10.5 The Company's Deferred Compensation Plan, dated December 29, 1994.
10.6 Stock Redemption Agreement dated October 15, 1991 between the
Company and James N. Ryan.
10.7 Stock Redemption Agreement dated October 15, 1991 between the
Company and Steven R. Williams.
10.8 Stock Redemption Agreement dated October 15, 1991 between the
Company and Dale G. Rettinger.
10.9 The Company's 1990 Employee Incentive Stock Option Plan.
10.10 The Company's 1997 Employee Incentive Stock Option Plan.
10.11 Form of Notice of Grant of Incentive Stock Options.
10.12 Profit Sharing Plan effective January 1, 1989, and all amendments
thereto.
10.13 Trust Agreement under the Company's Profit Sharing Plan, effective
January 1, 1992.
10.14 Savings and Protection Plan dated 1989, and all amendments
thereto.
</TABLE>
II-2
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
<C> <S>
10.15 Form of Indemnification Agreement between the Company and the
directors and officers of the Company, and all amendments thereto.
DATE: PARTY:
January 1, 1987 James N. Ryan
January 1, 1987 Steven R. Williams
January 1, 1987 Dale G. Rettinger
January 1, 1987 Roger J. Morgan
March 8, 1991 Vincent F. D'Annunzio
March 8, 1991 Jeffrey Swoveland
April 4, 1996 Ersel E. Morgan
April 4, 1996 Thomas E. Riley
April 4, 1996 Eric R. Stearns
April 4, 1996 Darwin L. Stump
10.16 Form of Rabbi Trust Agreement between the Company and Frontier
Trust Company.
DATE: PARTY:
October 15, 1995 James N. Ryan
October 15, 1995 Steven R. Williams
October 15, 1995 Dale G. Rettinger
OTHER MATERIAL CONTRACTS
10.17 Amended and Restated Credit Agreement between the Company and
First National Bank of Chicago, dated March 31, 1997.
10.18 Agreement and Plan of Exchange between and the Company, RNG
Holding Company, Thomas E. Riley and Donna R. Riley, dated April
1, 1996.
10.19 Purchase and Sale Agreement between the Company and Angerman
Associates, Inc. dated July 16, 1996.
11.1 Computation of Per Share Earnings.
15.1 Letter re: unaudited interim financial information.
21.1 Subsidiaries of the Company.
23.1 Consent of Duane, Morris & Heckscher LLP (included in their
opinion filed as Exhibit 5.1).
23.2 Consent of KPMG Peat Marwick LLP.*
23.3 Consent of Wright & Company, Inc.
</TABLE>
- --------
* Filed herewith. All other exhibits previously filed under this Registration
Statement.
ITEM 17. UNDERTAKINGS.
The Company undertakes that:
(a) The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Exchange Act (and, where applicable, each filing of an employee benefit plan's
annual report pursuant to Section 15(d) of the Exchange Act) that is
incorporated by reference in the Registration Statement shall be deemed to be
a new registration statement relating to the securities offered therein, and
the offering of such securities at that time shall be deemed to be the initial
bona fide offering thereof.
(b) For purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of
this registration statement in reliance upon Rule 430A and contained in a form
of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or
497(h) under the Securities Act of 1933 shall be deemed to be part of this
registration statement as of the time it was declared effective.
II-3
<PAGE>
(c) For the purpose of determining any liability under the Securities Act of
1933, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
(d) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the registrant of expenses
incurred or paid by a director, officer or controlling person of the
registrant in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with
the securities being registered, the registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent, submit to a
court of appropriate jurisdiction the question whether such indemnification by
it is against public policy as expressed in the Act and will be governed by
the final adjudication of such issue.
II-4
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-2 and has duly caused this Amendment to the
Registration Statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in Bridgeport, West Virginia on October 31, 1997.
PETROLEUM DEVELOPMENT CORPORATION
/s/ Steven R. Williams
By: _____________________________________
Steven R. Williams,
President
Pursuant to the requirements of the Securities Act of 1933, this Amendment
to the Registration Statement has been signed below by the following persons
in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
/s/ * Chairman of the Board, Chief
- ------------------------- Executive Officer and Director October 31,
James N. Ryan (principal executive officer) 1997
/s/ Steven R. Williams President and Director
- ------------------------- October 31,
Steven R. Williams 1997
/s/ Dale G. Rettinger Executive Vice President,
- ------------------------- Treasurer and Director, Chief October 31,
Dale G. Rettinger Financial Officer (principal 1997
financial and accounting
officer)
/s/ * Secretary and Director
- ------------------------- October 31,
Roger J. Morgan 1997
/s/ * Director
- ------------------------- October 31,
Vincent F. D'Annunzio 1997
/s/ * Director
- ------------------------- October 31,
Jeffrey C. Swoveland 1997
/s/ Dale G. Rettinger
*By:_____________________
- -------------------------
Dale G. Rettinger
Attorney-in-Fact
II-5
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
<C> <S>
1.1 Form of Underwriting Agreement.
3.1 Articles of Incorporation of the Company, as amended.
3.2 Amended and Restated By-Laws of the Company.
4.1 Form of Warrant (incorporated by reference to Exhibit 4 of the
Company's current report on Form 8-K filed on September 17, 1997).
5.1 Opinion of Duane, Morris & Heckscher LLP.
MANAGEMENT CONTRACTS
10.1 Employment Agreement dated as of July 1, 1988 between the Company
and James N. Ryan, and all amendments thereto.
10.2 Employment Agreement dated as of July 1, 1988 between the Company
and Steven R. Williams, and all amendments thereto.
10.3 Employment Agreement dated as of July 1, 1988 between the Company
and Dale G. Rettinger, and all amendments thereto.
10.4 Employment Agreement dated as of April 1, 1996 between the Company
and Thomas E. Riley.
10.5 The Company's Deferred Compensation Plan, dated December 29, 1994.
10.6 Stock Redemption Agreement dated October 15, 1991 between the
Company and James N. Ryan.
10.7 Stock Redemption Agreement dated October 15, 1991 between the
Company and Steven R. Williams.
10.8 Stock Redemption Agreement dated October 15, 1991 between the
Company and Dale G. Rettinger.
10.9 The Company's 1990 Employee Incentive Stock Option Plan.
10.10 The Company's 1997 Employee Incentive Stock Option Plan.
10.11 Form of Notice of Grant of Incentive Stock Options.
10.12 Profit Sharing Plan effective January 1, 1989, and all amendments
thereto.
10.13 Trust Agreement under the Company's Profit Sharing Plan, effective
January 1, 1992.
10.14 Savings and Protection Plan dated 1989, and all amendments
thereto.
10.15 Form of Indemnification Agreement between the Company and the
directors and officers of the Company, and all amendments thereto.
</TABLE>
DATE: PARTY:
----- ------
January 1, 1987 James N. Ryan
January 1, 1987 Steven R. Williams
January 1, 1987 Dale G. Rettinger
January 1, 1987 Roger J. Morgan
March 8, 1991 Vincent F. D'Annunzio
March 8, 1991 Jeffrey Swoveland
April 4, 1996 Ersel E. Morgan
April 4, 1996 Thomas E. Riley
April 4, 1996 Eric R. Stearns
April 4, 1996 Darwin L. Stump
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
<C> <S>
Form of Rabbi Trust Agreement between the Company and Frontier
10.16 Trust Company.
DATE: PARTY:
----- ------
October 15, 1995 James N. Ryan
October 15, 1995 Steven R. Williams
October 15, 1995 Dale G. Rettinger
OTHER MATERIAL CONTRACTS
10.17 Amended and Restated Credit Agreement between the Company and
First National Bank of Chicago, dated March 31, 1997.
10.18 Agreement and Plan of Exchange between and the Company, RNG
Holding Company, Thomas E. Riley and Donna R. Riley, dated April
1, 1996.
10.19 Purchase and Sale Agreement between the Company and Angerman
Associates, Inc. dated July 16, 1996.
11.1 Computation of Per Share Earnings.
15.1 Letter re: unaudited interim financial information.
21.1 Subsidiaries of the Company.
23.1 Consent of Duane, Morris & Heckscher LLP (included in their
opinion filed as Exhibit 5.1).
23.2 Consent of KPMG Peat Marwick LLP.*
23.3 Consent of Wright & Company, Inc.
</TABLE>
- --------
* Filed herewith. All other exhibits previously filed under this Registration
Statement.
<PAGE>
Exhibit 23.2
Independent Auditors' Consent
-----------------------------
The Board of Directors
Petroleum Development Corporation:
We consent to the use of our audit report dated March 13, 1997 on the
consolidated financial statements of Petroleum Development Corporation and
subsidiaries as of December 31, 1996 and 1995, and for each of the years in the
three-year period ended December 31, 1996 included herein and to the reference
to our firm under the heading "Experts" in the prospectus.
/s/ KPMG Peat Marwick LLP
Pittsburgh, Pennsylvania
October 31, 1997
