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 -2- 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 -3- 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, -4- 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. -5- 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. -7- 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.
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.
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
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 (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.
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 -9-
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 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.
"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 -10-
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 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.
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-
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 Item 6. Selected Financial Data (1)
(1) See Consolidated Financial Statements elsewhere herein. -12-
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 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:
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-
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 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 PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES Consolidated Balance Sheets December 31, 1996 and 1995
See accompanying notes to consolidated financial statements. F-4
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 PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES Consolidated Statements of Income Years Ended December 31, 1996, 1995 and 1994
See accompanying notes to consolidated financial statements. F-5
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 PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES Consolidated Statements of Stockholders' Equity Years Ended December 31, 1996, 1995 and 1994
See accompanying notes to consolidated financial statements. F-6
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 PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows Years Ended December 31, 1996, 1995 and 1994
See accompanying notes to consolidated financial statements. F-7
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 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:
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 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
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 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:
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
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) PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements
The Company accounts for its stock-based compensation plans under APB 25. For stock options granted, the option price was not less than the market value of shares on the grant date, therefore, no compensation cost has been recognized. Had compensation cost been determined under the provisions of SFAS 123, the Company's net income and earnings per share would have been the following on a pro forma basis:
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
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
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 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)
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
1996 1995 Revenues $53,091,400 $35,361,800 Net income $3,592,800 $1,546,900 Earnings per share $ .31 $ .13 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:
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:
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
(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:
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
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 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:
(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
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 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.
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
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 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 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:
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
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 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 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