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CONFORMED COPY
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
Commission File Number 0-7246
Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transaction period from to
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
Nevada 95-2636730
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
103 East Main Street, Bridgeport, West Virginia 26330
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code (304) 842-3597
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Petroleum Development Corporation Common Stock, $.01 par value
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation
S-K is not contained herein, and will be contained, to the best of registrant's
knowledge,
in definitive proxy or information statements incorporated by reference in Part
III of this
Form 10-K or any amendment to this Form 10-K. [ ]
As of March 15, 1997, 10,485,753 shares of the Registrant's Common Stock were
issued
and outstanding, and the aggregate market value of such shares held by
non-affiliates of the
Registrant on such date was $31,788,724 (based on the last traded price of
$4.00).
DOCUMENTS INCORPORATED BY REFERENCE
Document Form 10-K Part III
Proxy Items 11 and 12
PART I
Item 1. Business
General
Petroleum Development Corporation (PDC) is a Nevada corporation which
was formed in 1955 and commenced gas and oil operations in 1969. The
Company and its subsidiaries (the Company) are engaged in the leasing of
natural gas and oil mineral rights, the development of these rights by
drilling exploratory and development gas and oil wells, the production and
sale of gas and oil from these wells, the operation of gas and oil wells
for a fee, the marketing of natural gas for itself and other producers, and
the distribution of natural gas to residential, commercial and industrial
customers.
The Company typically develops its oil and gas properties in
conjunction with outside investors through partnerships, joint ventures, or
similar arrangements. These arrangements allow the Company to reduce the
risk of its development investments through increased diversification. In
addition the Company is compensated for its management of the development
process through payments for services rendered to the investor partners and
through an increased share in the revenues produced by the developed
properties.
Prior to 1984, virtually all of the outside investment capital was
contributed by unaffiliated partnerships and joint ventures. Beginning in
1984 the Company began sponsoring as the managing general partner drilling
partnerships which have invested their proceeds in Company development
projects. Currently a majority of the investment in Company development
programs originates from this source, however, a majority of the wells
operated by the Company continue to be associated with non-affiliated
investors.
In order to facilitate the marketing of natural gas from the wells
operated by PDC, the Company constructs and operates gas gathering systems
which interconnect to industrial customers, interstate pipeline company
facilities, and/or local distribution utilities. The Company receives
gathering fees for the use of these systems.
Gas and oil produced by wells are primarily marketed by the Company,
and its gas marketing subsidiary, Riley Natural Gas (RNG). RNG also
purchases natural gas from other producers and resells it to utilities, end-
users or other marketers.
The Company has an Ohio subsidiary, Paramount Natural Gas Company
(PNG), which commenced operations in October of 1992 as a regulated Ohio
distribution utility. Paramount Transmission Corporation (PTC), another
Ohio subsidiary of the Company focuses its efforts on the acquisition and
marketing of Ohio gas production.
Exploration and Development Activities
Prospect Generation and Leasing
PDC's staff of professional geologists is responsible for identifying
areas with potential for economic production of natural gas and oil. To
further this end the Company has collected and continues to collect logs,
core data, production information and other raw data available from state
and private agencies, other companies and individuals actively drilling in
the region. From this information the geologists develop models of the
subsurface structures and stratigraphy which are used to predict areas with
above average prospects for economic development.
On the basis of these models the geologists instruct the land
department to obtain available gas and oil leaseholds in these prospective
areas. These leases are then obtained, if possible, by the Company's land
department or contract landmen under the direction of the Company's land
manager. In most cases, these leases are obtained for a lease bonus and
annual rental payments changing to a 12.5% royalty on gross production
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revenue. In some instances additional overriding royalty payments may be
made to third parties or royalty owners with particularly attractive
prospects. As of December 31, 1996, the Company had a total leasehold
inventory of approximately 127,050 gross acres and 125,250 net acres. See
"Properties - Oil and Gas Leases".
Drilling Activities
When prospects have been identified and leased, the Company develops
these properties by drilling exploratory or development wells. Typically
the Company will act as driller-operator for these prospects, entering into
contracts with partnerships, including Company sponsored partnerships, and
other entities that are interested in exploration or development of the
prospects. The Company generally retains an interest in each well it
drills. This arrangement is beneficial to all parties, which benefit from
the diversification of risk. See "Financing of Exploration and Development
Activities".
The Company enters into a development agreement with each of its
investor partners, wherein the Company agrees to assign rights in the
property to be drilled to the partnership or other entity which thereby
becomes owner of a working interest in the property. The Company also
agrees to supervise and manage all drilling activities on the property and
to supply, either directly or through subcontractors, all necessary drilling
and related services and equipment. All work associated with drilling,
completing and connecting wells is performed under the direct supervision of
the Company. However, much of the work, including drilling, fracturing,
logging and pipeline construction is performed by subcontractors
specializing in those operations, as is common in the industry. Because the
prices paid to the Company by its investor partners are frequently fixed
before the wells are drilled, the Company is subject to risk that prices of
goods or services used in the development process could increase, rendering
its contracts with its investor partners less profitable or unprofitable.
In addition, problems encountered in the process can substantially increase
development costs, sometimes without recourse for the Company to recover its
costs from its partners. To minimize these risks, the Company seeks to lock
in its costs in advance of drilling and when possible at the same time it is
committing to its investor partners. A large part of the materials and
services used by the Company in the development process is acquired through
competitive bidding by approved vendors. The company also negotiates rates
and costs for services and supplies when conditions indicate that such an
approach is warranted.
The Company's development contracts with its investor partners are
negotiated with each partner and have historically taken many different
forms. Generally the agreements can be classified as "turnkey", in which a
specified amount is paid for drilling and another amount for completion;
"cost-plus", in which the Company is reimbursed for its actual cost of
drilling plus some additional amount for overhead and profit, or a "footage
based" rate whereby the Company receives drilling and completion payments
based on the depth of the well. As part of its compensation for its
services, the Company also generally receives some interest in the
production from the well in the form of an overriding royalty interest,
working interest or other proportionate share of revenue or profits.
Development Agreements with Partnerships sponsored by the Company
provide for a combination of several of the aforementioned payment options.
Basic drilling and completion operations are performed on a footage-based
rate, with leases and gathering pipelines being contributed at Company cost.
The Company also purchases a working interest in the properties.
The majority of the activity currently being pursued by the Company is
focused on the development of natural gas production in West Virginia,
Michigan, eastern Ohio, and western Pennsylvania. During 1996 the Company
was one of the most active drilling companies in the state of West Virginia.
Despite the level of activity, the Company was able to maintain a high level
of environmental sensitivity and was previously selected for four years in
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a row by the West Virginia Department of Environmental Protection for the
state's top award for the quality of the environmental and reclamation work
in its drilling activities. As a matter of corporate policy and commitment,
the Company attempts to minimize the adverse environmental impact of all its
operations.
The sale of natural gas requires that wells be connected by pipeline to
gas markets. Over the years the Company has developed extensive gathering
systems in its areas of operations. The Company also continues to construct
new trunklines as necessary to provide for the marketing of gas being
developed from new areas, and to enhance or maintain its existing systems.
The Company is paid a transportation fee for gas which is moved through
these pipeline systems. In many cases the Company has been able to receive
higher gas prices as a result of its ability to move gas to more attractive
markets through this pipeline system, to the benefit of both the Company and
its investor partners.
Acquisitions of Producing Properties
In addition to drilling new wells, the Company continues to pursue
opportunities to purchase existing producing wells from other producers and
interests in the wells it operates. Generally, outside interests purchased
include a majority interest in the wells and well operations.
In 1996 the Company purchased approximately 188 producing wells from
Angerman Associates. The wells, located primarily in Gilmer County, West
Virginia, added over 4 Bcf of proved producing reserves at December 31,
1996, in addition to several proved undeveloped locations.
Production Operations
The Company currently operates approximately 1,150 wells in the
Appalachian Basin. On average, the Company has an approximate 40% ownership
interest in the wells it operates, with the balance belonging to investor
partners. The Company employs engineers, supervisors and well tenders who
are responsible for the day to day operation of the wells and pipeline
systems. Currently these wells produce an aggregate of about 19 million
cubic feet of gas per day, including the Company's share of about 4.1
million cubic feet per day. The Company's share of oil production is about
7,000 barrels per year. See "Properties - Production"
The Company is paid a monthly operating charge for each well it
operates. The rate is competitive with rates charged by other operators in
the area. The charge covers monthly operating and accounting costs,
insurance and other recurring costs. The Company may also receive
additional compensation for special non-recurring activities like reworks
and recompletions.
Oil and Gas Marketing
In West Virginia, the Company markets the gas from its own and its
investor partner interests directly, or in some cases with assistance from
Riley Natural Gas, a subsidiary of the Company, as a part of the services
provided under the basic monthly operating charge. RNG was acquired in a
stock for stock exchange in early 1996. The acquisition of RNG added five
employees to the Company's work force and brings substantial experience in
natural gas marketing and hedging of natural gas transactions. In addition
to gas produced by the Company, RNG also purchases gas from other producers
for resale. The gas is marketed to gas utilities, pipelines and industrial
and commercial customers, either directly through the Company's gathering
system, or utilizing transportation services provided by regulated
interstate pipeline companies. Generally the Company negotiates its own
contacts with customers. However, occasionally the services of outside gas
brokers or marketers are used.
In Ohio, the Company's subsidiary, Paramount Transmission Company
(PTC), purchases gas from local producers and gas brokers and sells gas to
industrial and commercial customers utilizing open access transportation
services provided by interstate pipelines and the Company's subsidiary,
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Paramount Natural Gas Company (PNG), which is a regulated Ohio distribution
utility. The majority of PNG's throughput is attributable to gas
transported for PTC and industrial customers, for a transportation tariff,
with the balance being sales to residential, commercial and industrial
customers.
The Company produces oil from wells in Tennessee, Ohio and West
Virginia. All of the oil produced is sold on a spot basis to local refinery
customers. See "Market for Oil and Gas".
Financing of Exploration and Development Activities
The Company conducts drilling activities for its own account and for
other investors. In 1984 the Company began sponsoring private limited
partnerships, and in 1989 the Company began to register public drilling
programs with the Securities and Exchange Commission. Because of the
Company's success with its own partnerships, and declining sales nationwide
of unaffiliated partnerships, most drilling and development funds now come
from partnerships in which the Company serves as Managing General Partner.
However, because wells produce for a number of years, the Company continues
to serve as operator for a large number of unaffiliated parties.
The level of the Company's drilling and development activity is
dependent upon the amount of subscriptions in its public drilling
partnerships and investment from other partnerships or other joint venture
partners. Funds received pursuant to drilling contracts were $24,965,000 in
1996, $13,619,000 in 1995 and $14,858,000 in 1994. While funds were
received by the Company pursuant to drilling contracts in the years
indicated, the Company recognizes revenues from drilling operations on the
percentage of completion method as the wells are drilled, rather than when
funds are received.
The Company believes that investments in drilling activities, whether
through Company-sponsored partnerships or other sources, are influenced by
the favorable treatment which such investments enjoy under the Federal
income tax laws.
The Company invests in drilling activities through a 20% investment in
the partnerships it sponsors, and through direct working interest
investments. Certain conflict of interest provisions in joint venture and
partnership agreements limit the Company's ability to benefit
disproportionately from discoveries made through partnership activities.
Company investments in drilling activities are funded from internally
generated funds.
Market for Oil and Gas
The market for the Company's oil and gas depends upon a number of
factors including the availability of other domestic production, crude oil
and natural gas imports, the proximity of oil and gas pipelines and general
fluctuations in the supply and demand for oil and gas.
For nearly a decade the United States has experienced an oversupply of
natural gas. This oversupply was caused primarily by a decrease in market
demand and unusually warm weather conditions. Seasonal variations exist to
the extent that the demand for natural gas is somewhat lower during the
summer months than during the winter season.
Generally, the Company, along with its marketing subsidiary, Riley
Natural Gas, has been and expects to continue to be able to produce and
market gas from its wells without curtailment by providing gas to purchasers
at competitive prices. Open access transportation on the country's
interstate pipeline system has greatly increased the range of potential
markets. Whenever feasible the Company allows for multiple market
possibilities from each of its gathering systems, while seeking the best
available market for its gas at any point in time.
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Natural gas is sold by the Company under contracts ranging from month
to month spot to a 3 year term. Virtually all of the Company's contracts
have pricing tied to a market index, so the price of the gas moves to remain
competitive with other available gas supplies. As a result the revenue from
the sale of gas will suffer if market prices decline or benefit if they
increase. The provisions of the Company's gas contracts are believed by the
Company to be customary in the industry.
The Company's sales of natural gas are to various customers, one
customer, Hope Gas, Inc., accounted for 30.7% of the Company's revenues from
oil and gas sales (16.1% of total revenues) in 1996. Hope Gas, Inc. is a
regulated public utility. In general, the prices it pays for gas, and the
producers from which it purchases gas, are influenced by the state and
federal agencies that regulate them. No other single purchaser of the
Company's natural gas accounted for 10% or more of the Company's revenues
from oil and gas sales in 1996.
Gas produced by the Company sold at December 31, 1996 at prices per Mcf
ranging from $1.75 to $6.31, depending upon the location, the date of the
sales contract and whether the gas was sold in interstate or intrastate
commerce. The weighted net average price of gas sold by the Company in 1996
was $3.04 per Mcf at the wellhead.
The Company is presently able to sell all the oil which it can produce
under existing sales contracts with petroleum refiners and marketers. The
Company's crude oil production is sold to purchasers at or near the
Company's wells under short-term purchase contracts at prices and in
accordance with arrangements which are customary in the oil industry. None
of the Company's oil production is sold under long-term contracts. The
Company does not refine any of its oil production. No single purchaser of
the Company's crude oil accounted for 10% or more of the Company's revenues
from oil and gas sales in 1996.
Oil produced by the Company sold at December 31, 1996 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.
Use of Commodities Markets to Hedge Natural Gas Transactions
The Company has established a policy which allows the use of NYMEX
natural gas futures to reduce the risk of volatility in natural gas prices.
These uses include coordinating fixed and variable priced purchases and
sales by RNG and "locking in" fixed prices from time to time for the
Company's share of production. The policy prohibits the use of natural gas
futures for speculative purposes and can be utilized only if there is an
underlying physical position.
Governmental Regulation
The Company's business and the oil and gas industry in general are
highly regulated. The Company's services to investor partnerships include
taking the steps necessary to comply with applicable regulations.
Local Regulation. All of the Company's oil and gas production is from
properties in states in which drilling activities and well operations are
regulated by state authorities. These regulations, among other things,
require the Company to obtain permits to build roads and drill wells and
impose land restoration and minimum spacing requirements. See also
"Environmental Matters".
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.
-6-
Federal Regulations. Pricing of gas sold by the Company is now fully
deregulated from Federal Price controls, and no proposals currently exist to
reimpose controls.
All of the interstate pipelines which the Company uses to transport gas
from wells to markets are regulated by the Federal Energy Regulatory
Commission (FERC). Over the past few years FERC has changed regulations on
these interstate pipeline systems, forcing them, among other things, to
offer open access transportation service, to unbundle the various services
they provide to allow customers to pay only for those services which they
use, and to change the structure of the rates which they charge. These
policy changes have not yet been fully determined or implemented, and it is
impossible at this time to predict the impact on the Company's business.
Also, the Company cannot determine to what extent future operations and
earnings of the Company may be affected by new legislation, new regulations
or changes in existing regulations.
Environmental Matters
The oil and gas industry is subject to numerous federal and state
environmental statutes, regulations and other pollution controls. In
general, the Company is and will continue to be subject to present and
future environmental statutes and regulations, and in the future the cost of
its drilling and exploration and other activities may materially increase as
a result.
The Company's expenses relating to preserving the environment during
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 regulations will not, in the
future, result in a curtailment of production or otherwise have a materially
adverse effect on the Company's operations or financial condition.
Competition
The Company competes with many other companies in the search for and
acquisition of oil and gas properties and leases for exploration and
development, and also competes with other companies in its activities as
drilling contractor and natural gas marketers. Many of these companies have
substantially greater financial, technical and other resources than the
Company. Competition among oil and gas companies for favorable oil and gas
prospects can be expected to continue. It is anticipated that the cost of
acquiring oil and gas properties will increase appreciably. The Company is
not a significant factor in the oil and gas industry.
Likewise, the Company competes with a number of other companies which
offer interests in drilling partnerships with a wide range of investment
objectives and program structures. Competition for investment capital for
both public and private drilling programs is intense.
Other Industry Factors
Oil and gas drilling operations are subject to hazards such as fire,
explosion, blowouts, cratering and oil spills, each of which could result in
substantial damage to oil and gas wells, producing facilities, other
property and the environment or in personal injury. Although the Company
maintains liability insurance in an amount which it considers adequate, the
nature of these risks is such that liabilities could exceed policy limits in
which event the Company could incur significant costs that could have a
materially adverse effect upon its financial condition.
Employees
As of December 31, 1996, the Company had 72 employees. The Company's
employees are not covered by a collective bargaining agreement. The Company
considers relations with its employees to be excellent.
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Item 2. Properties
Drilling Activity
The following table summarizes the Company's drilling activity for the
past five years. There is no correlation between the number of productive
wells completed during any period and the aggregate reserves attributable to
those wells.
Exploratory Wells Drilled
Total Productive Gas Dry
Drilled Net Drilled Net Drilled Net
1992 - - - - - -
1993 3 .75 - - 3 .75
1994 - - - - - -
1995 - - - - - -
1996 - - - - - -
Total 3 .75 - - 3 .75
Development Wells Drilled
Total Productive Gas Dry
Drilled Net Drilled Net Drilled Net
1992 80 15.86 73 14.47 7 1.39
1993 56 10.00 49 8.75 7 1.25
1994 75 13.76 71 13.00 4 .76
1995 72 13.40 64 11.80 8 1.60
1996 97 17.44 92 16.46 5 .98
Total 380 70.46 349 64.48 31 5.98
The term "exploratory well" means a well drilled with the hope of
greatly extending the limits of an already developed pool or in search of an
undiscovered pool of oil or gas. A "development well" is one drilled to
extend the limits of an already developed pool, or within a proved area of
an oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive. A "dry well (hole)" is an exploratory or a development well
found to be incapable of producing either oil or gas in sufficient
quantities to justify completion as an oil or gas well.
A "drilled" well is a well for which the Company supervised drilling
activity or in which it has a working interest. A "net" well is deemed to
be held when the sum of the fractional working interests owned by the
Company in wells equals one.
Production
The following table shows the Company's net production in barrels
("Bbls") of crude oil and in thousands of cubic feet ("Mcf") of natural gas
and the costs and weighted average selling prices thereof, for the periods
indicated.
Year Ended December 31,
1996 1995 1994 1993 1992
Production (1):
Oil (Bbls) 7,000 11,000 11,000 10,000 16,000
Natural Gas (Mcf) 1,495,000 1,336,000 1,195,000 965,000 948,000
Equivalent
Mcfs (2) 1,537,000 1,402,000 1,261,0001,025,000 1,044,000
Average sales price
per equivalent
Mcf (3) $3.04 $1.81 $2.07 $2.15 $2.20
Average production
cost (lifting cost) per
equivalent Mcf (4) $ .63 $ .53 $ .58 $ .57 $ .48
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(1) Production as shown in the table, which is net after the royalty
interests of others, is determined by multiplying the gross production
volume of properties in which the Company has an interest by the percentage
of the leasehold or other property interest owned by the Company.
(2) The ratio of energy content of oil and gas (six Mcf of gas equals
one barrel of oil) was used to obtain a conversion factor to convert oil
production into equivalent Mcfs of natural gas.
(3) The average sales price per barrel of oil sold by the Company was
$16.35 in 1996, $15.80 in 1995, $14.41 in 1994, $16.62 in 1993 and $18.21 in
1992 and the average sales price per Mcf of gas was $3.04 in 1996, $1.75 in
1995, $2.01 in 1994, $2.24 in 1993 and $2.41 in 1992.
(4) Production costs represent oil and gas operating expenses as
reflected in the financial statements of the Company plus depreciation of
support equipment and facilities.
Summary of Productive Wells. The table below gives the number of the
Company's productive gross and net wells at December 31, 1996.
WELLS
Gas Oil
Location Gross Net Gross Net
Ohio 16 5.50 9 2.03
Tennessee 1 .57 55 20.37
Pennsylvania 98 23.93 - -
West Virginia 961 423.92 10 4.46
Total 1,076 453.92 74 26.86
Reserves
All of the Company's oil and gas reserves are located in the United
States.
"Proved reserves" are those quantities of crude oil and natural gas
which, upon analysis of geologic and engineering data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs on leases held by the Company under existing economic and
operating conditions. The Company's approximate net proved reserves were
estimated by the Company to be 79,000 barrels of oil and 32,225,000 Mcf of
gas at December 31, 1994 and 140,000 barrels of oil and 33,829,000 Mcf of
gas at December 31, 1995 and 81,000 barrels of oil and 43,312,000 Mcf of gas
at December 31, 1996.
"Proved developed reserves" are proved reserves which are expected to
be recovered through existing wells with existing equipment and operating
methods. The Company's approximate net proved developed reserves were
estimated by the Company to be 79,000 barrels of oil and 27,746,000 Mcf of
gas at December 31, 1994 and 140,000 barrels of oil and 29,326,000 Mcf of
gas at December 31, 1995 and 81,000 barrels of oil and 35,516,000 Mcf of gas
at December 31, 1996.
No major discovery or other favorable or adverse event which would
cause a significant change in estimated reserves is believed by the Company
to have occurred since December 31, 1996. Reserves cannot be measured
exactly as reserve estimates involve subjective judgment. The estimates
must be reviewed periodically and adjusted to reflect additional information
gained from reservoir performance, new geological and geophysical data and
economic changes.
The standardized measure of discounted future net cash flows
attributable to the Company's proved oil and gas reserves giving effect to
future estimated income tax expenses, was estimated by the Company to be
$14,445,000 as of December 31, 1994, and $21,060,000 as of December 31, 1995
and $34,262,000 as of December 31, 1996. These amounts are based on year-
end prices at the respective dates. Since December 31, 1996, prices have
decreased to seasonal levels. The values expressed are estimates only, and
may not reflect realizable values or fair market values of the oil and gas
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ultimately extracted and recovered. The standardized measure of discounted
future net cash flows may not accurately reflect proceeds of production to
be received in the future from the sale of oil and gas currently owned and
does not necessarily reflect the actual costs that would be incurred to
acquire equivalent oil and gas reserves.
Substantially all of the Company's oil and gas reserves have been
mortgaged or pledged as security for bank loans to the Company. See Note 3
of Notes to Consolidated Financial Statements.
For additional information concerning oil and gas reserves and
activities, see Notes 16, 17 and 18 of Notes to Consolidated Financial
Statements.
The Company has not filed any estimates (on a consolidated basis) of
its oil and gas reserves with, nor were such estimates included in any
reports to, any Federal or foreign governmental agency other than the
Securities and Exchange Commission within the 12 months prior to the date of
this filing.
Oil and Gas Leases
The following table sets forth, as of December 31, 1996, the acres of
developed and undeveloped oil and gas properties in which the Company had an
interest, listed alphabetically by state.
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
Michigan -0- -0- 26,200 26,200
Ohio 1,200 800 -0- -0-
Pennsylvania 250 250 10,200 9,500
Tennessee 3,600 3,600 - -
West Virginia 59,900 59,500 25,600 25,400
64,950 64,150 62,000 61,100
"Undeveloped acreage" is that leasehold acreage on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether or not such
acreage contains proved reserves.
A "gross" acre is an acre in which the Company owns a working interest.
A "net" acre is deemed to exist when the sum of the fractional working
interests owned by the Company in gross acres equals one.
As is customary in the oil and gas industry, only a perfunctory title
examination is conducted at the time the properties believed to be suitable
for drilling operations are acquired by the Company. Prior to the
commencement of drilling operations, a title examination is conducted and
curative work is performed with respect to defects which the Company deems
to be significant. A title examination has been performed with respect to
substantially all of the Company's producing properties. The Company
believes that the title to such properties is good and indefeasible in
accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions stated in the opinion of counsel employed in the
various areas in which the Company conducts its exploration activities
which, in the Company's judgment, are not so material as to detract
substantially from the use of such property. Also, no single property
represents a material portion of the Company's holdings.
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
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agreements, current taxes, development obligations under oil and gas leases,
farmout arrangements and other encumbrances, easements and restrictions.
The Company does not believe that any of these burdens will materially
interfere with the use of the properties.
Item 3. Legal Proceedings
Legal Proceedings
The Company is not party to any legal action that would materially
affect the Company's operations or financial statements.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the
fourth quarter of the fiscal year covered by this report.
PART II
Item 5. Market for the Company's Common Stock and Related Security Holder
Matters
The common stock of the Company is traded in the over-the-counter
market under the symbol PETD. The following table sets forth, for the
periods indicated, the high and low bid quotations per share of the
Company's common stock in the over-the-counter market, as reported by the
National Quotation Bureau Incorporated. These quotations represent inter-
dealer prices without retail markups, markdowns, commissions or other
adjustments and may not represent actual transactions.
High Low
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
1996
First Quarter 2 1/8 1 5/16
Second Quarter 2 13/16 1 7/8
Third Quarter 3 9/16 2 7/16
Fourth Quarter 6 3/16 3 3/8
As of December 31, 1996, there were approximately 2,463 record holders
of the Company's common stock.
The Company has not paid any dividends on its common stock and
currently intends to retain earnings for use in its business. Therefore, it
does not expect to declare cash dividends in the foreseeable future.
Further, the Company's Credit Agreement restricts the payment of dividends.
-11-
Item 6. Selected Financial Data (1)
Year Ended December 31,
1996 1995 1994 1993 1992
Revenues
Oil and gas well
drilling
operations $18,698,200 $13,941,000 $15,190,200 $12,073,500 $14,930,700
Oil and gas sales 26,051,100 4,150,600 4,361,300 4,471,200 4,867,300
Well operations
income 3,928,800 3,750,900 3,730,300 3,843,100 2,935,900
Other income 935,600 504,000 524,400 97,600 432,600
Total $49,613,700 $22,346,500 $23,806,200 $20,485,400 $23,166,500
Costs and Expenses
(excluding
interest and
depreciation,
depletion and
amortization) $42,274,100 $18,042,300 $20,559,500 $17,116,700 $18,826,000
Interest Expense $ 380,000 $ 319,700 $ 300,200 $ 55,500 $ 54,000
Depreciation,
Depletion and
Amortization $ 2,309,600 $ 2,152,100 $ 1,848,200 $ 1,717,400 $1,671,600
Income before
extraordinary
item $ 3,549,400 $ 1,481,500 $ 921,600 $ 1,320,800 $1,748,100
Extraordinary item
net of income
taxes - - - 269,000 -
Net Income $ 3,549,400 $ 1,481,500 $ 921,600 $ 1,589,800 $1,748,100
Primary earnings
per common and
common equivalent
share
Income before
extraordinary item $ .31 $ .13 $ .08 $ .11 $ .16
Net income $ .31 $ .13 $ .08 $ .14 $ .16
Average Common and
Common Equivalent
Shares Outstanding
During the Year 11,573,429 11,606,690 11,990,497 11,563,648 11,190,709
December 31,
1996 1995 1994 1993 1992
Total Assets $63,604,200 $40,620,100 $38,325,300 $36,412,900 $34,631,500
Working Capital $(2,357,200) $(1,519,700) $(1,613,700) $ 289,000 $ (590,100)
Long-Term Debt,
excluding current
maturities $ 5,320,000 $ 2,500,000 $ 3,100,000 $ 3,167,300 $ 3,968,900
Stockholders'
Equity $23,072,500 $19,920,900 $18,380,500 $17,235,700 $15,347,100
(1) See Consolidated Financial Statements elsewhere herein.
-12-
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Safe Harbor Statement Under the Private Securities
Litigation Reform Act of 1995
Statements, other than historical facts, contained in this Annual
Report on Form 10-K, including statements of estimated oil and gas
production and reserves, drilling plans, future cash flows, anticipated
capital expenditures and Management's strategies, plans and objectives, are
"forward looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. Although the Company believes that its
forward looking statements are based on reasonable assumptions, it cautions
that such statements are subject to a wide range of risks and uncertainties
incident to the exploration for, acquisition, development and marketing of
oil and gas, and it can give no assurance that its estimates and
expectations will be realized. Important factors that could cause actual
results to differ materially from the forward looking statements include,
but are not limited to, changes in production volumes, worldwide demand, and
commodity prices for petroleum natural resources; the timing and extent of
the Company's success in discovering, acquiring, developing and producing
oil and gas reserves; risks incident to the drilling and operation of oil
and gas wells; future production and development costs; the effect of
existing and future laws, governmental regulations and the political and
economic climate of the United States; the effect of hedging activities; and
conditions in the capital markets. Other risk factors are discussed
elsewhere in this Form 10-K, including those risk factors described under
the headings "Market for Oil and Gas", "Other Industry Factors" and
"Environmental Matters."
Results of Operations
1996 Compared with 1995
Total revenue increased $27,267,200 from $22,346,500 to $49,613,700 in
1996. Oil and gas sales increased $21,900,500 primarily due to the gas
marketing activities of Riley Natural Gas Company (RNG), a company acquired
on April 1, 1996, along with increased production and higher average sales
prices from the Company's producing properties and increased gas purchased
for resale. Revenues relating to the Company's drilling activities
increased $4,757,200 due to an increase in drilling and completion
activities in 1996 compared to 1995 which was a direct result of an increase
in drilling funds from the Company's public drilling programs.
Costs and expenses increased $24,449,600 from $20,514,100 to
$44,963,700 in 1996 as a result of increased oil and gas purchases and
production costs and to a lesser extent increased well drilling costs. Oil
and gas purchases and production costs increased $20,051,600 primarily due
to gas purchases by RNG for resale and to a lesser extent higher volumes of
gas purchased for resale at higher average prices. Oil and gas well
drilling costs increased $3,836,800 as a result of the higher volume of
drilling activity referred to above.
The foregoing resulted in income before income taxes of $4,650,000
compared to $1,832,400 in 1995. The net income for 1996 was $3,549,400
compared to net income of $1,481,500 in 1995.
1995 Compared with 1994
Total revenue decreased 6.1% from $23,806,200 to $22,346,500 in 1995.
Revenues relating to the Company's drilling activities decreased $1,249,200
due to a slight decrease in drilling and completion activities in 1995
compared to 1994. Overall oil and gas sales decreased 4.8% in 1995 compared
to 1994 as a result of lower average gas sales prices offset by increased
volumes of natural gas sold.
-13-
Costs and expenses decreased 9.7% from $22,707,900 to $20,514,100
principally as a result of decreased drilling activity. Cost of oil and gas
well drilling operations decreased $2,345,700 as a result of the decrease in
drilling and completion activities referred to above. General and
administrative expenses decreased 11.0% as a result of a general company
wide cost cutting program. Depreciation, depletion, and amortization
increased 16.4% in 1995 compared to 1994 as a result of an increase in the
Company's investment in natural gas wells and increased production levels.
The foregoing resulted in income before income taxes of $1,832,400
compared to $1,098,300 in 1994. Net income for 1995 was $1,481,500 compared
to net income of $921,600 in 1994.
Liquidity and Capital Resources
Sales volumes of natural gas continued to increase while the natural
gas prices fluctuated monthly but resulted in a higher average price than
the prior year. The Company's gas sales prices are subject to increase and
decrease based on various market sensitive indices. A major factor in the
variability of these indices is the seasonal variation of demand for natural
gas, which typically peaks during the winter months. The volumes of gas
sales are expected to continue to increase as a result of continued drilling
activities.
The Company closed its fourth 1996 drilling partnership on December 31,
1996 and will drill approximately 85 wells during the first quarter of 1997.
Typically, the Company's drilling activity peaks during the winter months.
The Company has commenced sales of units in the first public drilling
program partnership of 1997 which is scheduled to close in May, 1997. The
Company's public drilling programs continue to receive wide market
acceptance.
The acquisition of Riley Natural Gas Company (RNG) on April 1, 1996 in
a stock for stock exchange has, as expected, increased both oil and gas
sales revenues ($18.7 million) and oil and gas purchases. The RNG employees
added to PDC's work force have substantial experience in natural gas markets
and natural gas hedging transactions and have greatly expanded the Company's
capabilities in the gas marketing area.
On March 13, 1997 the Company executed an amendment to a bank credit
agreement which provides a borrowing base of $10,000,000 subject to adequate
oil and gas reserves, which at the request of the Company the bank may
increase the borrowing base to $20,000,000. 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 continues to pursue capital investment opportunities in
producing gas properties along with its commitment to participate in its
sponsored gas drilling partnerships. Management believes that the Company
has adequate capital to meet its investing and operating requirements and
continues to pursue opportunities for operating improvements and cost
efficiencies.
-14-
PART III
Item 8. Financial Statements and Supplementary Data:
The response to this Item is set forth herein in a separate section of
this Report, beginning on Page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item 10. Directors and Executive Officers of the Company
The executive officers and directors of the Company, their principal
occupations for the past five years and additional information are set forth
below:
Held Current
Name Age Positions and Offices Held Position Since
James N. Ryan 65 Chairman, Chief Executive
Officer and Director March, 1983
Steven R. Williams 45 President and Director March, 1983
Roger J. Morgan 69 Secretary and Director November, 1969
Vincent F. D'Annunzio 44 Director February, 1989
Dale G. Rettinger 52 Executive Vice President,
Treasurer and Director July, 1980
Jeffrey C. Swoveland 42 Director March, 1991
The term of directors is three years expiring in alternating years.
Executive officers have a term of one year and until a successor is elected.
Such elections are expected to occur at the Company's next annual meeting
presently scheduled for June, 1996. There is no family relationship between
any director or executive officer and any other director or executive
officer of the Company. There are no arrangements or understandings between
any director or officer and any other person pursuant to which such person
was selected as an officer.
The following is a brief account of the business experience during the
past five years of each director and executive officer:
James N. Ryan has served as President and Director of the Company from
1969 to 1983 and was elected Chairman and Chief Executive Officer in March,
1983.
Steven R. Williams has served as President and Director of the Company
since March 1983. Prior to joining the Company, Mr. Williams was employed
by Exxon until 1979 and attended Stanford Graduate School of Business,
graduating in 1981. He then worked with Texas Oil and Gas until July, 1982,
when he joined Exco Enterprises as Manager of Operations.
Roger J. Morgan has been a member of the law firm of Young, Morgan &
Cann, Clarksburg, West Virginia, for more than the past five years. Mr.
Morgan is not active in the day-to-day business of the Company, but his law
firm provides legal services to the Company.
Vincent F. D'Annunzio has for the past five years served as President
of Beverage Distributors, Inc. located in Clarksburg, West Virginia.
Dale G. Rettinger has served as Vice President and Treasurer of the
Company since July, 1980. Mr. Rettinger was elected Director in 1985.
Previously, Mr. Rettinger was a partner with KMG Main Hurdman, Certified
Public Accountants, having served in that capacity since 1976.
Jeffrey C. Swoveland has been with Equitable Resources since the fall
of 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 to late 1994.
-15-
Item 11. Management Remuneration and Transactions
There is incorporated by reference herein in response to this Item the
material under the heading "Election of Directors - Remuneration of Directors
and Officers", "Election of Directors - Stock Options" and "Election of
Directors - Interest of Management in Certain Transactions" in the Company's
definitive proxy statement for its 1997 annual meeting of stockholders filed
or to be filed with the Commission on or before April 30, 1997.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There is incorporated by reference herein in response to this Item, the
material under the heading "Election of Directors", in the Company's definitive
proxy statement for its 1997 annual meeting of stockholders filed or to be filed
with the Commission on or before April 30, 1997.
Item 13. Certain Relationships and Related Transactions
The response to this item is set forth herein in Note 8 in the Notes to
Consolidated Financial Statements.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements:
See Index to Financial Statements and Schedules on page F-1.
(2) Financial Statement Schedules:
See Index to Financial Statements and Schedules on page F-1.
Schedules and Financial Statements Omitted
All other financial statement schedules are omitted because
they are not required, inapplicable, or the information is
included in the Financial Statements or Notes thereto.
(3) Exhibits:
See Exhibits Index on page E-1.
(b) During the fourth quarter of 1996, the Company filed no report
on Form 8-K.
-16-
CONFORMED COPY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PETROLEUM DEVELOPMENT CORPORATION
By /s/ James N. Ryan
James N. Ryan, Chairman
March 20, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:
Signature Title Date
/s/ James N. Ryan Chairman, Chief Executive March 20, 1997
James N. Ryan Officer and Director
/s/ Steven R. Williams President and Director March 20, 1997
Steven R. Williams
/s/ Dale G. Rettinger Executive Vice President, March 20, 1997
Dale G. Rettinger Treasurer and Director
(principal financial and
accounting officer)
/s/ Roger J. Morgan Secretary and Director March 20, 1997
Roger J. Morgan
-17-
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Index to Financial Statements and Financial Statement Schedules
1. Financial Statements:
Independent Auditors' Report F-2
Consolidated Balance Sheets - December 31, 1996 and 1995 F-3 & 4
Consolidated Statements of Income - Years Ended
December 31, 1996, 1995, and 1994 F-5
Consolidated Statements of Stockholders' Equity -
Years Ended December 31, 1996, 1995, and 1994 F-6
Consolidated Statements of Cash Flows -
Years Ended December 31, 1996, 1995, and 1994 F-7
Notes to Consolidated Financial Statements F-8 - 20
2. Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
and Reserves F-21
F-1
Independent Auditors' Report
The Stockholders and Board of Directors
Petroleum Development Corporation:
We have audited the consolidated financial statements of Petroleum
Development Corporation and subsidiaries as listed in the accompanying
index. In connection with our audits of the consolidated financial
statements, we also have audited the financial statement schedule as listed
in the accompanying index. These consolidated financial statements and
financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
consolidated financial statements and financial statement schedule based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Petroleum Development Corporation and subsidiaries as of December 31, 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. Also in our opinion, the
related financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly,
in all material respects, the information set forth therein.
KPMG PEAT MARWICK LLP
Pittsburgh, Pennsylvania
March 13, 1997
F-2
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
1996 1995
Assets
Current assets:
Cash and cash equivalents (includes
restricted cash of $1,734,900 in 1996) $20,615,400 10,053,600
Notes and accounts receivable 6,696,000 2,016,600
Inventories 567,200 217,900
Prepaid expenses 740,900 868,800
Total current assets 28,619,500 13,156,900
Properties and equipment:
Oil and gas properties (successful
efforts accounting method) 46,525,700 37,992,000
Pipelines 7,186,900 6,851,900
Transportation and other equipment 2,151,200 2,546,900
Land and buildings 1,098,200 849,200
56,962,000 48,240,000
Less accumulated depreciation,
depletion and amortization 22,522,300 21,127,100
34,439,700 27,112,900
Other assets 545,000 350,300
$63,604,200 40,620,100
(Continued)
F-3
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
1996 1995
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 9,703,800 2,119,100
Accrued taxes 506,000 155,100
Other accrued expenses 1,505,900 1,628,800
Advances for future drilling contracts 18,397,000 10,069,600
Funds held for future distribution 864,000 704,000
Total current liabilities 30,976,700 14,676,600
Long-term debt, excluding
current maturities 5,320,000 2,500,000
Other liabilities 1,094,200 601,700
Deferred income taxes 3,140,800 2,920,900
Commitments and contingencies
Stockholders' equity:
Common stock, par value $.01 per share;
authorized 22,250,000 shares; issued and
outstanding 10,460,753 and 11,208,627 104,600 112,100
Common stock, Class A, par value $.01 per
share; authorized 2,750,000 shares; issued
and outstanding - none - -
Additional paid-in capital 6,617,300 7,019,800
Retained earnings 16,427,400 12,878,000
Unamortized stock award (76,800) (89,000)
Total stockholders' equity 23,072,500 19,920,900
$63,604,200 40,620,100
See accompanying notes to consolidated financial statements.
F-4
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Income
Years Ended December 31, 1996, 1995 and 1994
1996 1995 1994
Revenues:
Oil and gas well drilling operations $18,698,200 13,941,000 15,190,200
Oil and gas sales 26,051,100 4,150,600 4,361,300
Well operations and pipeline income 3,928,800 3,750,900 3,730,300
Other income 935,600 504,000 524,400
49,613,700 22,346,500 23,806,200
Costs and expenses:
Cost of oil and gas well drilling
operations 15,779,800 11,943,000 14,288,700
Oil and gas purchases and production
cost 24,190,300 4,138,700 4,067,000
General and administrative expenses 2,304,000 1,960,600 2,203,800
Depreciation, depletion
and amortization 2,309,600 2,152,100 1,848,200
Interest 380,000 319,700 300,200
44,963,700 20,514,100 22,707,900
Income before income
taxes 4,650,000 1,832,400 1,098,300
Income taxes 1,100,600 350,900 176,700
Net income $ 3,549,400 1,481,500 921,600
Earnings per common
and common equivalent share $.31 .13 .08
See accompanying notes to consolidated financial statements.
F-5
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 1996, 1995 and 1994
Common stock
issued
Number Additional
of paid-in Retained Unamortized
shares Amount capital earnings Stock
Award Total
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
See accompanying notes to consolidated financial statements.
F-6
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 1996, 1995 and 1994
1996 1995 1994
Cash flows from operating activities:
Net income $ 3,549,400 1,481,500 921,600
Adjustment to net income to reconcile
to cash provided by operating activities:
Deferred income taxes 213,900 112,600 97,400
Depreciation, depletion and amortization 2,309,600 2,152,100 1,848,200
Disposition of leasehold acreage 151,700 201,300 173,600
Employee compensation paid in stock 17,900 12,300 108,200
(Increase) decrease in notes and accounts
receivable (1,480,600) (41,200) 39,400
(Increase) decrease in inventories (349,300) 172,300 (38,100)
Decrease (increase) in prepaid expenses 203,300 10,600 (211,000)
(Increase) decrease in other assets (226,400) 65,800 65,100
Increase in accounts payable
and accrued expenses 3,938,200 42,300 92,200
Increase in advances for future
drilling contracts 8,327,400 869,700 1,071,900
Increase (decrease) in funds held for
future distribution 160,000 337,300 (474,300)
Other 90,700 (95,800) 18,300
Total adjustments 13,356,400 3,839,300 2,790,900
Net cash provided by operating
activities 16,905,800 5,320,800 3,712,500
Cash flows from investing activities:
Capital expenditures (10,415,500) (3,910,400) (5,606,500)
Proceeds from sale of leases 655,400 289,400 282,100
Proceeds from sale of fixed assets 10,800 36,700 34,200
Net cash acquired from
purchase of subsidiary 1,450,000 - -
Net cash used in investing
activities (8,299,300) (3,584,300) (5,290,200)
Cash flows from financing activities:
Proceeds from debt 4,200,000 - 800,000
Proceeds from issuance of stock 135,300 46,600 5,000
Purchase of treasury stock (1,000,000) - -
Retirement of debt (1,380,000) (636,300) (899,300)
Net cash provided by (used in)
financing activities 1,955,300 (589,700) (94,300)
Net increase (decrease) in cash
and cash equivalents 10,561,800 1,146,800 (1,672,000)
Cash and cash equivalents,
beginning of year 10,053,600 8,906,800 10,578,800
Cash and cash equivalents, end of year $20,615,400 10,053,600 8,906,800
See accompanying notes to consolidated financial statements.
F-7
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Years Ended December 31, 1996, 1995 and 1994
(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.
(Continued)
F-8
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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.
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.
(Continued)
F-9
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Well operations income consists of operation charges for well upkeep,
maintenance and operating lease income on tangible well equipment.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income
in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date.
Derivatives
Gains and losses related to qualifying hedges of firm commitments or
anticipated transactions through the use of natural gas futures
contracts are deferred and recognized in income or as adjustments of
carrying amounts when the underlying hedged transaction occurs. In
order for futures contracts to qualify as a hedge, there must be
sufficient correlation to the underlying hedged transaction. The
change in the fair value of derivative instruments which do not
qualify for hedging are recognized into income currently.
Stock Compensation
On January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation," which permits entities to recognize as
expense over the vesting period the fair value of all stock-based
awards on the date of grant. Alternatively, SFAS 123 allows entities
to continue to measure compensation cost for stock-based awards using
the intrinsic value based method of accounting prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and to
provide pro forma net income and pro forma earnings per share
disclosures as if the fair value based method defined in SFAS 123 had
been applied. The Company has elected to continue to apply the
provisions of APB 25 and provide the pro forma disclosure provisions
of SFAS 123. See note 5 to the financial statements.
Use of Estimates
Management of the Company has made a number of estimates and
assumptions relating to the reporting of assets and liabilities and
revenues and expenses and the disclosure of contingent assets and
liabilities to prepare these financial statements in conformity with
generally accepted accounting principles. Actual results could
differ from those estimates. Estimates which are particularly
significant to the consolidated financial statements include
estimates of oil and gas reserves and future cash flows from oil and
gas properties.
(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, 1996 and 1995, in the amounts of $5,930 and
$168,400, net of the allowance for doubtful accounts of $147,200 and
$368,800, respectively.
The allowance for doubtful current accounts receivable as of December
31, 1996 and 1995 was $140,600 and $20,200, respectively.
(Continued)
F-10
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(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 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, 1996 and 1995, the balance outstanding was
$5,320,000 and $2,500,000, respectively. No principal payments are
required under the credit agreement until maturity on December 31,
1999. Interest 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:
1996 1995 1994
Current:
Federal $ 545,600 128,400 66,600
State 341,100 109,900 12,700
Total current
income taxes 886,700 238,300 79,300
Deferred:
Federal 165,800 87,300 75,500
State 48,100 25,300 21,900
Total deferred
income taxes 213,900 112,600 97,400
Total taxes $1,100,600 350,900 176,700
Income tax expense attributable to income from continuing operations was
$1,100,600, $350,900 and $176,700 for the years ended December 31,
1996, 1995 and 1994, 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:
1996 1995 1994
Amount Amount Amount
Computed "expected" tax $1,581,000 623,000 373,400
State income tax 249,900 108,800 71,200
Percentage depletion (205,800) (155,900) (136,000)
Nonconventional source
fuel credit (510,500) (127,300) (18,000)
Adjustment to oil and
gas properties - - (132,700)
Adjustments to valuation
allowance - (100,700) -
Other (14,000) 3,000 18,800
$1,100,600 350,900 176,700
(Continued)
F-11
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at December
31, 1996 and 1995 are presented below:
1996 1995
Deferred tax assets:
Drilling notes, principally due to
allowance for doubtful accounts $ 465,800 671,300
Investment tax credit carryforwards 45,200 233,300
Alternative minimum tax credit
carryforwards (Section 29) 926,600 909,400
Other 550,800 440,600
Total gross deferred tax assets 1,988,400 2,254,600
Less valuation allowance (926,600) (941,300)
Deferred tax assets 1,061,800 1,313,300
Less current deferred tax assets
(included in prepaid expenses) (376,100) (386,200)
Net non-current deferred
tax assets 685,700 927,100
Deferred tax liabilities:
Plant and equipment, principally
due to differences in
depreciation and amortization (3,826,500) (3,848,000)
Total gross deferred
tax liabilities (3,826,500) (3,848,000)
Net deferred tax liability $(3,140,800) (2,920,900)
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 year ended
December 31, 1996 a decrease of $14,700 and for the years ended December 31,
1995 and 1994 increases of $98,600 and $45,000, respectively.
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 $.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.
(Continued)
F-12
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Number
of Shares Average Range
Outstanding December 31, 1993 2,182,250 $0.71 .38 - 1.63
Granted - $ - -
Exercised (226,250) $0.50 .44 - .69
Expired - $ - -
Outstanding December 31, 1994 1,956,000 $0.77 .38 - 1.63
Granted 210,000 $1.13 1.13 - 1.13
Exercised (78,000) $0.60 .56 - .72
Expired (235,350) $0.68 .38 - 1.63
Outstanding December 31, 1995 1,852,650 $0.91 .50 - 1.63
Granted -
Exercised (230,000) $0.72 .50 - 1.125
Expired (40,000) $0.80 .50 - 1.625
Outstanding December 31, 1996 1,582,650 $0.94 .50 - 1.625
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:
1996 1995
As Reported Pro Forma As Reported Pro Forma
Net income $3,549,400 $3,473,250 $1,481,500 $1,474,400
Earnings per
share $ .31 $ .30 $ .13 $ .13
Stock Redemption Agreement
The Company has stock redemption agreements with three officers of the
Company. The agreements require the Company to maintain life insurance
on each executive in the amount of $1,000,000. The agreements provide
that the Company shall utilize the proceeds from such insurance to
purchase from such executives' estates or heirs, at their option,
shares of the Company's stock. The purchase price for the outstanding
common stock is to be based upon the average closing asked price for
the Company's stock as quoted by NASDAQ during a specified period. The
Company is not required to purchase any shares in excess of the amount
provided for by such insurance.
Stock Purchase
On January 31, 1996, the Company purchased 1,200,000 shares of its common
stock pursuant to an option agreement. The option was obtained in
connection with a debt restructuring in 1990. The company utilized
its' revolving credit line to acquire the shares for $1,000,000 or
$0.83 a share. The shares representing approximately 11% of the
currently outstanding stock were retired by the Company.
(6) Employee Benefit Plans
The Company made 401-K Plan contributions of $139,800, $71,800 and
$68,700 for 1996, 1995 and 1994, respectively.
The Company has a profit sharing plan (the Plan) covering full-time
employees. The Company contributed $50,000 and $28,500 to the plan in
(Continued)
F-13
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
cash during 1996 and 1995, respectively. The Company did not make a
contribution to the Plan during 1994.
During 1996 and 1995, 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 1996 and 1995.
At December 31, 1996 and 1995, the Company has recorded as other assets
$111,800 and $60,000, 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 11,573,429 for 1996, 11,606,690
for 1995 and 11,990,497 for 1994. 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 $18,234,200
in 1996, $11,397,000 in 1995 and $12,834,300 in 1994 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 $6,435,700 in 1996, $4,003,500 in
1995 and $4,041,600 in 1994 for those services. During 1996, 1995 and
1994, the Company paid $35,400, $38,500 and $127,900, 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.
(10) Supplemental Disclosure of Cash Flows
The Company paid $380,000, $319,700 and $300,200 for interest in 1996,
1995 and 1994, respectively. The Company paid income taxes in 1996 and
1994 in the amounts of $664,300 and $312,500, respectively.
(Continued)
F-14
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(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 substanially
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
begining of 1995:
Proforma Results (unaudited)
1996 1995
Revenues $53,091,400 $35,361,800
Net income $3,592,800 $1,546,900
Earnings per share $ .31 $ .13
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. 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.
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.
(Continued)
F-15
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(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:
Years Ended December 31,
1996 1995 1994
Property acquisition cost:
Proved undeveloped properties $ 543,600 167,800 426,200
Producing properties 3,211,800 218,500 1,332,100
Development costs 5,344,900 2,977,700 2,260,800
$9,100,300 3,364,000 4,019,100
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:
December 31,
1996 1995
Proved properties:
Intangible drilling costs $19,572,400 16,582,000
Tangible well equipment 21,999,600 16,831,800
Well equipment leased to others 4,063,600 4,063,600
Undeveloped properties 890,100 514,600
46,525,700 37,992,000
Less accumulated depreciation,
depletion and amortization 15,837,800 14,529,900
$30,687,800 23,462,100
(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:
Years Ended December 31,
1996 1995 1994
Revenue:
Oil and gas sales $4,674,900 2,534,000 2,610,100
Expenses:
Production costs 963,600 596,000 734,700
Depreciation, depletion
and amortization 1,248,200 1,000,700 922,300
2,211,800 1,596,700 1,657,000
Results of operations for
oil and gas producing
activities before provision
for income taxes 2,463,100 937,300 953,100
Provision for income taxes 519,600 137,800 146,600
Results of operations for oil
and gas producing activities
(excluding corporate over-
head and interest costs) $1,943,500 799,500 806,500
(Continued)
F-16
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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.
(17) Net Proved Oil and Gas Reserves (Unaudited)
The proved reserves of oil and gas of the Company as estimated by an
independent petroleum engineer, Wright & Company, Inc. at December
31, 1996 and by the Company's petroleum engineers at December 31,
1995 and 1994. 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:
Oil (BBLS)
1996 1995 1994
Proved developed and
undeveloped reserves:
Beginning of year 140,000 79,000 91,000
Revisions of previous estimates (30,000) 72,000 (1,000)
Beginning of year as revised 110,000 151,000 90,000
Dispositions (49,000) - -
Acquisitions 27,000 - -
Production (7,000) (11,000) (11,000)
End of year 81,000 140,000 79,000
Proved developed reserves:
Beginning of year 140,000 79,000 91,000
End of year 81,000 140,000 79,000
Gas (MCF)
1996 1995 1994
Proved developed and
undeveloped reserves:
Beginning of year 33,829,000 32,225,000 24,660,000
Revisions of previous estimates (1,037,000) 686,000 4,472,000
Beginning of year as revised 32,792,000 32,911,000 29,132,000
New discoveries and extensions 2,613,000 2,119,000 2,345,000
Disposition (127,000) - -
Acquisitions 9,529,000 135,000 1,943,000
Production (1,495,000) (1,336,000) (1,195,000)
End of year 43,312,000 33,829,000 32,225,000
Proved developed reserves:
Beginning of year 29,326,000 27,746,000 20,181,000
End of year 35,516,000 29,326,000 27,746,000
(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
(Continued)
F-17
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
flows relating to proved oil and gas reserves. Future cash inflows
are derived by applying current oil and gas prices to estimated
future production. Future production, development, site restoration
and abandonment costs are derived based on current costs assuming
continuation of existing economic conditions. Future income tax
expenses are computed by applying the statutory rate in effect at the
end of each year to the future pretax net cash flows, less the tax
basis of the properties and gives effect to permanent differences,
tax credits and allowances related to the properties.
Years Ended December 31,
1996 1995 1994
Future estimated cash flows $193,800,000 99,478,000 73,316,000
Future estimated production
and development costs (59,806,000) (29,288,000) (24,370,000)
Future estimated income
tax expense (33,499,000) (20,004,000) (13,950,000)
Future net cash flows 100,495,000 50,186,000 34,996,000
10% annual discount for
estimated timing of cash
flows (66,233,000) (29,126,000) (20,551,000)
Standardized measure of
discounted future
estimated net cash flows $ 34,262,000 21,060,000 14,445,000
The following table summarizes the principal sources of change in the
standardized measure of discounted future estimated net cash flows:
Years Ended December 31,
1996 1995 1994
Sales of oil and gas
production, net of
production costs $(3,711,000) (1,938,000) (1,875,000)
Net changes in prices
and production costs 42,384,000 17,024,000 (9,560,000)
Extensions, discoveries
and improved recovery,
less related cost 9,659,000 4,609,000 3,875,000
Acquisitions 17,775,000 294,000 2,745,000
Development costs incurred
during the period 5,345,000 2,978,000 2,261,000
Revisions of previous
quantity estimates (2,902,000) 1,700,000 8,222,000
Changes in estimated
income taxes (13,495,000) (6,054,000) (882,000)
Accretion of discount (37,107,000) (8,575,000) (1,785,000)
Other (4,746,000) (3,423,000) (2,574,000)
$ 13,202,000 6,615,000 427,000
It is necessary to emphasize that the data presented should not be
viewed as representing the expected cash flow from, or current value
of, existing proved reserves since the computations are based on a
large number of estimates and arbitrary assumptions. Reserve
quantities cannot be measured with precision and their estimation
requires many judgmental determinations and frequent revisions. The
required projection of production and related expenditures over time
requires further estimates with respect to pipeline availability,
rates of demand and governmental control. Actual future prices and
costs are likely to be substantially different from the current
prices and costs utilized in the computation of reported amounts.
Any analysis or evaluation of the reported amounts should give
specific recognition to the computational methods utilized and the
limitations inherent therein.
(Continued)
F-18
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(19) Business Segments
Information on the Company's operations by business segement are as follows
for the years ended December 31,:
1996 1995 1994
Revenues:
Drilling and production $27,940,200 20,360,100 21,250,800
Marketing and pipeline 20,737,900 1,482,400 2,031,000
$48,678,100 21,842,500 23,281,800
Operating Profit:
Drilling and production $ 6,207,000 3,714,300 3,302,800
Marketing and pipeline 191,400 (105,600) (224,900)
6,398,400 3,608,700 3,077,900
General and administrative expense $(2,304,000) (1,960,600) (2,203,800)
Interest expense (380,000) (319,700) (300,200)
Interest income and other 935,600 504,000 524,400
Income before income taxes $ 4,650,000 1,832,400 1,098,300
Depreciation, Depletion
and Amortization:
Drilling and production $ 2,153,900 2,008,000 1,696,800
Marketing and pipeline 155,700 144,100 151,400
$ 2,309,600 2,152,100 1,848,200
Identifiable Assets:
Drilling and production $54,847,000 39,016,000 36,381,000
Marketing and pipeline 8,005,100 1,067,700 1,383,600
Corporate 752,100 536,400 560,700
$63,604,200 40,620,100 38,325,300
Capital Expenditures:
Drilling and production $10,059,900 3,817,700 5,478,000
Marketing and pipeline 124,200 86,900 112,200
Corporate 231,400 5,800 16,300
$10,415,500 3,910,400 5,606,500
(Continued)
F-19
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(20) Quarterly Financial Data (Unaudited)
Summarized quarterly financial data for the years ended December 31, 1996
and 1995, are as follows:
1996
Quarter Year
First Second(1) Third(1) Fourth(1)
Revenues $11,441,300 $10,333,700 $11,317,000 $16,521,700 $49,613,700
Cost of operations 9,203,000 8,858,900 9,996,500 14,221,300 42,279,700
Gross profit 2,238,300 1,474,800 1,320,500 2,300,400 7,334,000
General and
administrative
expenses 541,800 570,100 651,000 541,100 2,304,000
Interest expense 72,100 67,300 106,400 134,200 380,000
613,900 637,400 757,400 675,300 2,684,000
Income before
income taxes 1,624,400 837,400 563,100 1,625,100 4,650,000
Income taxes 344,400 177,500 152,600 426,100 1,100,600
Net income $1,280,000 $ 659,900 $ 410,500 $1,199,000 $ 3,549,400
Primary earnings
per share $ .11 $ .06 $ .04 $ .10 $ .31
1995
Quarter Year
First Second Third Fourth
Revenues $9,537,000 $4,432,800 $3,582,500 $4,794,200 $22,346,500
Cost of operations 8,034,500 3,621,700 2,764,500 3,813,100 18,233,800
Gross profit 1,502,500 811,100 818,000 981,100 4,112,700
General and
administrative
expenses 450,300 520,900 600,700 388,700 1,960,600
Interest expense 83,400 76,300 71,000 89,000 319,700
533,700 597,200 671,700 477,700 2,280,300
Income before
income taxes 968,800 213,900 146,300 503,400 1,832,400
Income taxes 240,300 53,000 36,300 21,300 350,900
Net income $ 728,500 $ 160,900 $ 110,000 $ 482,100 $ 1,481,500
Primary earnings
per share $ .06 $ .02 $ .01 $ .04 $ .13
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
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
AND RESERVES
Years Ended December 31, 1996, 1995 and 1994
Column A Column B Column C Column D Column E
Additions,
Balance at Charged to Balance
Beginning Costs and at End
Description of Period Expenses Deductions of Period
Allowance for doubtful
accounts deducted from
accounts and notes receivable
in the balance sheet
1996 $389,000 $108,100 $209,300 $287,800
1995 $429,400 $210,000 $250,400 $389,000
1994 $362,300 $ 75,100 $ 8,000 $429,400
F-21
Petroleum Development Corporation
Index to Exhibits
11 Schedule of Computation of Net Income Per Share E-2
E-1
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
EXHIBIT 11
SCHEDULE OF COMPUTATION OF NET INCOME PER SHARE
Years Ended December 31,
PRIMARY
1996 1995 1994
Net income for primary income
per common share before extraordinary item $ 3,549,400 $1,481,500 $ 921,600
Net income for primary income
per common share 3,549,400 $1,481,500 $ 921,600
Weighted average number of common shares
outstanding during the year 10,449,137 11,056,441 10,878,601
Add - common equivalent shares (determined
using the "treasury stock" method) represent-
ing shares issuable upon exercise of employee
stock options 1,124,292 550,249 1,111,896
Weighted average number of shares
used in calculation of primary
income per share 11,573,429 11,606,690 11,990,497
Primary income per share $ .31 $ .13 $ .08
FULLY DILUTED
Net income for primary income per
common share $ 3,549,400 $ 1,481,500 $ 921,600
Net income for fully diluted
net income per share $ 3,549,400 $ 1,481,500 $ 921,600
Weighted average number of shares
used in calculating primary income
per common share 11,573,429 11,606,690 11,990,497
Shares issuable upon exercise of stock
options used in primary calculation above (1,124,292) (550,249) (1,111,896)
Shares issuable for fully diluted calculation 1,327,038 880,689 1,111,896
Weighted average number of shares
used in calculation of fully
diluted income per share 11,776,175 11,937,130 11,990,497
Fully diluted earnings per share $ .30 $ .12 $ .08
E-11