PETROLEUM DEVELOPMENT CORP - 10-K Annual Report

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from to

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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as definition in Rule 12b-2 of the Exchange Act). Yes X No

As of March 21, 2005, 16,589,824 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 June 30, 2004, the last business day of the Registrant's most recently completed second quarter was $318,343,540 (based on the last traded price of $27.42).

Petroleum Development Corporation is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. Since it began oil and gas operations in 1969, the Company has grown primarily through drilling and development activities, the acquisition of producing natural gas and oil wells and the expansion of its natural gas marketing activities. As of December 31, 2004, the Company operates approximately 2,700 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 523 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 217 Bcfe. The Company's share of production for the fourth quarter of 2004 averaged 34,500 Mcfe per day.

The Company's operations are divided into four segments for management and reporting purposes. (See Consolidated Financial Statements, Note 19. Business Segments)

The Company drills wells not only for itself, but also for other investor partners. When the company drills wells for others it earns a profit above the cost of the wells. The Drilling and Development segment records the payments received from others as revenue and the related costs as expenses.

Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically purchases a 20% ownership interest in these drilling limited partnerships. In 2004, the Company, through four public drilling partnerships, raised $100 million making it the sponsor of the largest public oil and gas partnership program in the United States as it has been for the last several years. With the partnerships as a drilling partner the Company has been able to expand its drilling opportunities, reduce its drilling risk through greater diversification, and to share the costs of the infrastructure necessary to support such activities.

The Company's wholly-owned subsidiary, Riley Natural Gas (RNG), purchases, aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end‑user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to help manage the financial impact on the Company and its Partnerships of changes in the price of natural gas and oil. RNG also manages the marketing of oil and gas for the Company's wells outside the Appalachian Basin, but does not market gas or oil for non-affiliated producers in those areas.

Revenue from the sale of oil and natural gas from the Company's interest in oil and gas wells is reported in this segment. The Company has interests in approximately 2,700 wells ranging from a few percent to 100 percent. During 2004 approximately 14% of the Company's production was generated by Appalachian Basin wells, 14% by Michigan Basin wells and 72% by Rocky Mountain wells. As of the end of 2004, the Company's total proved reserves were located as follows: Appalachian Basin 19%, Michigan 12% and Rocky Mountain Region 69%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2005 will be focused in that area.

The Company operates almost all of the approximately 2,700 wells in which it owns an interest. When it owns less than 100 percent of the working interest in a well, it charges the other owners a competitive operating fee for operating the well. These revenues and the associated costs are reflected in the Well Operations segment.

The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan since 1997, and in the Rocky Mountain Region since 1999.

In all three regions the Company has historically targeted shallow (less than 10,000 feet), developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. Recently the Company has begun to drill to progressively deeper targets in the Rocky Mountain Region. In particular it has drilled several wells with depths of more than 12,000 feet. The Company's management believes these deeper wells offer the possibility of significantly greater reserves and production than shallow wells, although they are also more expensive to drill. In addition the probability of encountering problems when drilling a deep well is generally greater than when drilling a shallow well. With increasing costs for and declining availability of proved developed drilling locations, the Company's management believes the additional risk associated with exploratory drilling is justified by the potential to generate additional proved locations at a significantly lower cost than would be required to purchase proved undeveloped locations.

The Company's primary objective is to increase shareholder value by expanding its oil and natural gas reserves, production and revenues through a strategy that includes the following key elements:

Drilling new wells, particularly shallow, developmental natural gas wells, has been the mainstay of the Company's drilling program for a number of years. The Company drilled 158 wells in 2004, compared to 111 wells in 2003. In addition the Company seeks to maximize the value of its existing wells through a program of well recompletions and infill drilling in areas where attractive opportunities exist. The Company's management believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2004, the Company had leases or other development rights to 1,700 undeveloped acres in the Michigan Basin, 10,000 undeveloped acres in the northern Appalachian Basin and 152,830 undeveloped acres in the Rocky Mountain Region. The Company also has about 40 Wattenberg Field wells that it plans to recomplete in 2005, and the new wells it has drilled since 1999 in the field will be available for recompletions beginning in 2006.

To support future development activities the Company began an exploratory drilling program in 2004 that it plans to continue in 2005. The goal of the exploration program is to develop several significant new areas for the Company to include in its future development drilling programs.

The Company's acquisition efforts are focused on producing properties that fit well within existing operations or in areas where the Company is establishing new operations and that have most of their value in producing wells, behind pipe reserves or high quality proved undeveloped locations. Acquisitions have historically offered economies in management and administration, and the Company's management believes that it can acquire and manage more producing wells without incurring substantial increases in its administrative costs.

With operations in the Rocky Mountains, Michigan and the Appalachian Basin, the Company has proven its ability to grow through operations in geographically diverse areas. While these areas provide geographic diversification, within each area the Company has concentrated positions that lend themselves to effective development and operation. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2005, but will continue to seek additional opportunities for expansion in areas where the Company's experience and expertise can be applied successfully.

The Company seeks opportunities to reduce the risks inherent in the oil and gas industry in a variety of ways. For a number of years an integral part of the Company's strategy has been to concentrate on development drilling and geographical diversification to reduce risk levels associated with natural gas and oil drilling, production and markets. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. Development drilling will remain the foundation of our drilling activities in 2005. However Company's management believes the increasing cost of high quality development locations has made exploratory drilling more attractive. Exploratory wells have the potential of identifying new development opportunities at a significantly lower cost than the current cost of proven locations. While successful exploratory efforts could add to the Company's future drilling opportunities at favorable costs, under the successful efforts method of accounting, exploratory dry holes are expensed at the time it is recognized that they are unproductive. This could result in greater short term expenses and a reduction in the near-term profitability of the Company.

To help offset the relatively high business risk inherent in the oil and gas industry the company maintains a conservative financial structure. The Company's management believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company's utilizes its marketing subsidiary, Riley Natural Gas, to manage the marketing of the Company's oil and natural gas and its commodity hedges. This allows the Company to maintain better control over third party risk in sales and hedging activities. The Company uses natural gas and oil hedges to reduce the effects of volatility of energy prices.

The Company's Internet address is www.petd.com. Electronic copies of the Company's annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports are available free of charge by visiting the "Financial Information" section of www.petd.com. These reports are posted as soon as reasonably practicable after they are electronically filed with the Securities and Exchange Commission. Additionally, information including the Company's press releases, current drilling program sales, Bylaws, Committee Charters, Code of Business Conduct and Ethics, Shareholder Communication Policy, Board Nomination Procedures and the Whistleblower and Qualified Legal Compliance Committee Hotline is also available at the site.

Natural gas is the second largest energy source in the United States, after liquid petroleum. The estimated 21.9 Tcf of natural gas consumed in 2004 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 35% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 24% and 15% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; and 25% by utilities for the generation of electricity; and 1% for other users. (Source U.S. Energy Information Administration)

The Company's management believes that the market for natural gas will continue to grow in the future. Natural gas is the cleanest and most environmentally safe of the fossil fuels. Relative to other energy sources, natural gas usage and losses during transportation from source to destination are slight, averaging only about 3% of the natural gas energy. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground.

The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. Increasing international demand for petroleum combined with supply constraints drove oil prices to record high levels in 2004. Continuing increases in world energy demand appear likely in 2005 and beyond. This makes natural gas more competitive in domestic markets as a replacement for oil and increases the value of domestic oil and natural gas reserves.

The Company's management believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas even at prices that are high by historical standards.

Because local supplies of natural gas are inadequate to meet demand in sections of the country, areas including the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. Natural gas producers in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States.

In contrast, much of the production in the Rocky Mountains is transported significant distances to end use markets. As a result the price received for gas in the Rocky Mountains is generally less than the price received in areas closer to the primary consuming areas. The Rocky Mountain region is believed to hold substantial undeveloped natural gas resources. Recent and planned additions to pipeline capacity in the region have made the area more attractive for development. Although gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, development costs may be less.

The Company's development activities focus on the identification and drilling of new productive wells, the acquisition of existing producing wells from other producers, and maximizing the value of the Company's current properties through infill drilling, recompletions, and other production enhancements.

The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience evaluating prospects and drilling natural gas and oil wells. They utilize results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and formations that are used to predict areas with prospects for economic development.

On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds, farmouts and other development rights in these prospective areas. These rights are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2004, the Company had leasehold rights to approximately 164,530 acres available for development. See--"Properties--Oil and Natural Gas Leases."

When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2004, the Company drilled a total of 157 development wells of which 153 were successfully completed as producing wells. Typically, the Company will act as driller‑operator for these prospects, frequently selling interests in the wells to partnerships, primarily Company‑sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company retains an interest in each well it drills.

The Company also drilled one exploratory well in 2004 and plans additional exploratory wells in 2005. As of the date of this report the exploratory well had been completed and testing was underway but the well had not been classified as successful or dry. Testing of the well was suspended in January due to lease restrictions on the Federal lease. We expect to resume testing in the second quarter. If the well is determined to be a dry hole, its cost will be expensed in the period when the determination is made as required by the successful efforts method of accounting. The cost of the well as of January 31, 2005 is $4,362,000. Currently the Company plans to retain most if not all of the working interest in the exploratory wells, since the Company partnerships focus on developmental activities and are allowed only limited participation in exploratory drilling. See "Financing of Company Drilling and Development Activities" And "Drilling and Development Activities Conducted for Company Sponsored Partnerships."

Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction is performed under the Company's direction by subcontractors specializing in those operations, as is common in the industry. When judged advantageous, material and services used by the Company in the development process are acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its drilling partnerships for the Company's services are frequently fixed before the wells are drilled or are determined based primarily on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling when possible.

The following table summarizes the Company's development drilling activity for the last 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 Company's exploratory wells drilled in the past five years (not included in the table data) consist of one well (1.0 net) drilled in 2004 and one dry hole (1.0 net) drilled in 2003. The exploratory well drilled in 2004 was completed late in the year. Testing was commenced in December and suspended in January due to lease restrictions on the federal lease that restrict access for heavy equipment including service units during certain periods of the year to protect wildlife and the environment. The lease restrictions would not prevent the operation of producing wells during this period. Testing is scheduled to resume late in the second quarter. The well cannot be classified as dry or productive until testing is complete. If it is classified as dry the cost will be expensed in the period when the determination is made as required by the successful efforts method of accounting.

	Development Wells Drilled
	Total		Productive		Dry
	Drilled	Net	Drilled	Net	Drilled	Net
2000	97	27.39	97	27.39	-	-
2001	141	40.00	135	37.94	6	2.06
2002	70	13.71	70	13.71	-	-
2003	110	28.51	110	28.51	-	-
2004	157	43.00	153	42.40	4	.60

Total	575	152.61	565	149.95	10	2.66

The Company conducts development drilling activities for its own account and acts as operator for other investors. When conducting activities for its own account the Company uses cash flow from operations and capital provided from its long term credit facility to fund its share of operations. The Company currently has activated $60 million of a $100 million credit facility with J.P. Morgan Chase Bank, NA and BNP Paribas, however it has more than adequate reserves to allow the full line to be activated if necessary. As of the end of 2004 the Company had $21 million outstanding of the facility.

Drilling and Development Activities Conducted for Company Sponsored Partnerships

In addition to wells and interests in wells that it drills for itself, the company also acts as operator for other oil and gas investors. Historically these other investors have included individuals, corporations, partnerships formed by non-affiliated parties and other investors. Currently the Company's drilling partners consist primarily of public partnerships sponsored by the Company. A part of the Company's drilling investment is used to purchase an interest in each partnership.

In 1984, the Company began sponsoring private drilling limited partnerships, and, in 1989, the Company began to offer partnership interests in public drilling programs registered with the SEC. The Company's public partnerships had $100 million in subscriptions in 2004, $78.3 million in subscriptions in 2003, and $56.9 million in subscriptions in 2002. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 22% of the aggregate subscriptions received for that particular drilling partnership and receives a 20% working interest in each partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership, during 2004 this amounted to $22.0 million.. The funds received from these programs are restricted to use in future drilling operations. While funds were received by the Company pursuant to drilling contracts in the years indicated, the Company recognizes revenues from drilling operations on the percentage of completion method as the wells are drilled, rather than when funds are received. Substantially all of the Company's drilling and development funds are now received from partnerships in which the Company serves as managing general partner. However, because wells produce for a number of years, the Company continues to serve as operator for a number of unaffiliated parties.

The process begins when the Company enters into a development agreement with an investor partner, pursuant to which the Company agrees to assign some or all of its rights in the property to be drilled to the partnership or other entity. The partnership or other entity thereby becomes owner of a working interest in the property.

The Company's drilling contracts with its investor partners have historically taken many different forms. Currently the agreements can be classified as on a "footage-based" rate, whereby the Company receives drilling and completion payments based on the depth of the well. Basic drilling and completion operations are performed on a footage‑based rate, with leases being contributed at the Company's cost. The Company may also purchase a working interest in the subject properties. In its financial reporting the Company reports only its share of reserves, production, revenue and costs associated with wells in which other investors participate. The level of the Company's third party drilling and development activity is dependent upon the amount of subscriptions in its public drilling partnerships and investments from other partnerships or other joint venture partners. Accepting investments from third party investors and Company sponsored partnerships enables the Company to diversify its holdings, thereby reducing the risk of the Company's investments. Additionally, the Company benefits through such arrangements by its receipt of fees for its management services and/or through an increased share in the revenues produced by the developed properties. The Company's management believes that investments in drilling activities, whether through Company‑sponsored partnerships or other sources, are influenced in part by the favorable treatment that such investments enjoy under the federal income tax laws. No assurance can be given that the Company will continue to have access to funds generated through these financing vehicles.

In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers as well as greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and the right to operate the wells. Although the Company made several offers to purchase properties during 2004, other potential purchasers outbid the Company, therefore none of its offers were successful. Several purchases made during 2003 as described below did contribute to the Company's increased production in 2004.

During the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg-Basin in northeastern Colorado from Williams Production RMT Company for $28 million. The Company estimates the acquisition included approximately 22.6 billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed non-producing reserves (PDNP) at the time of acquisition, all of which is natural gas.

During the fourth quarter of 2003, the Company purchased from one of its unaffiliated joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of proved developed non-producing reserves from interests in 17 net wells (183 gross). The purchase price was $5.2 million.

During the fourth quarter of 2003, the Company purchased from an unaffiliated party 97 gross wells (73 net) in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase included approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed producing and proved developed non-producing reserves along with 100,000 acres of oil and gas leases.

The Company also purchased a number of small interests in its partnerships from investor partners wishing to sell their interests in 2004, 2003 and 2002.

The following table shows the Company's net production in barrels (Bbl) of crude oil and in thousand cubic feet (Mcf) of natural gas and the costs and weighted average selling prices thereof, for the last five years.

	Year Ended December 31,
	2004	2003	2002	2001	2000
Production(1):
Oil(MBbl)	381	289	227	195	109
Natural Gas (MMcf)	10,372	8,712	6,462	6,085	5,737
Equivalent Mmcf(2)	12,658	10,449	7,824	7,255	6,391
Average sales price:
Oil (per Bbl)(3)	$35.13	$29.39	$24.41	$22.53	$29.99
Natural gas (per Mcf)(3)	$5.26	$4.42	$2.68	$3.53	$2.74
Average production cost (lifting cost) Per equivalent Mcf(4)	$1.18	$0.98	$0.82	$0.83	$0.66

(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company.

(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas and oil sales. The effect of hedges on the average sales price of natural gas per Mcf for the years ended December 31, 2004, 2003, 2002, 2001, and 2000 was $(0.09), $(0.09), $0.02, $(0.56),and $(0.91) respectively. The effect of hedges on the average sales price of oil per barrel for the year ended December 31, 2004 was $(2.71). There was no oil hedged in earlier years.

(4) Production costs represent oil and gas operating expenses which include severance and ad valorem taxes as reflected in the financial statements of the Company. See Oil and Gas Production Costs in Management's Discussion and Analysis.

Natural gas produced by the Company's well interests is sold under contracts with terms ranging from one month to three years. Virtually all of the Company's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company's management believes that the pricing provisions of its natural gas contracts are customary in the industry.

The Company sells its natural gas to industrial end-users, utilities, other gas marketers, and other wholesale gas purchasers. Two customers accounted for 13.8% and 11.1% respectively of the Company's revenues from oil and gas sales (7.8% and 6.3% of total revenues) in 2004. Three customers accounted for 16.6%, 17.4% and 14.3%, respectively of the Company's revenues from oil and gas sales (9.8%, 10.3% and 8.5% of total revenues) in 2003. Two customers accounted for 21.1% and 11.0%, respectively of the Company's revenues from oil and gas sales (10.8% and 5.6% of total revenues) in 2002. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2004, 2003, and 2002.

At December 31, 2004, natural gas produced by the Company sold at prices per Mcf ranging from $0.90 to $12.22, depending upon well location, the date of the sales contract and other factors. The weighted net average price of natural gas sold by the Company during 2004 was $5.26 per Mcf.

In general, the Company, together with its marketing subsidiary, RNG, has been and expects to continue to be able to produce and sell natural gas from its wells without significant curtailment by providing natural gas to purchasers at competitive prices. Open access transportation through the country's interstate pipeline system makes a broad range of markets accessible to the Company. Whenever feasible the Company obtains access to multiple pipelines and markets from each of its gathering systems seeking the best available market for its natural gas at any point in time.

Some of the Company's wells in the Appalachian Basin and Michigan, and most of the Company's wells in Wattenberg field in Colorado, produce oil in addition to natural gas. At the end of 2004 oil was about 9% of the Company's total equivalent reserves.

The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is sold to purchasers at or near the Company's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry. One purchaser accounted for 7.6%, 11.0% and 11.9% of the Company's revenues from oil and gas sales (4.3%, 6.5% and 5.6% of total revenues) in 2004, 2003, and 2002. At December 31, 2004, oil produced by the Company sold at prices ranging from $37.25 to $49.00 per barrel, depending upon the location and quality of oil. In 2004, the weighted net average price per barrel of oil sold by the Company was $35.13.

Oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to procure and implement Spill Prevention, Control and Counter-measures ("SPCC") plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Operations of the Company are also subject to the Federal Clean Water Act and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground.

The Company's natural gas marketing activities involve the purchase of natural gas from other producers and the sale of that natural gas along with natural gas produced by the Company. The Company's management believes that in a deregulated market, successful natural gas marketing is an essential component of profitable operations. A variety of factors affect the market for natural gas, including the availability of other domestic production, natural gas imports, the availability and price of alternative fuels, the proximity and capacity of natural gas pipelines, general fluctuations in the supply and demand for natural gas and the effects of state and federal regulations on natural gas production and sales. The natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers.

RNG, a wholly owned subsidiary, is a natural gas marketing company that specializes in the purchase, aggregation and sale of natural gas production in the Company's operating areas. RNG markets natural gas produced by the Company and also purchases natural gas from other producers and resells to utilities, end users or other marketers. The employees of RNG have extensive knowledge of natural gas markets in the Company's areas of operations. Such knowledge assists the Company in maximizing its prices as it markets natural gas from Company-operated wells. The gas is marketed to natural gas utilities, pipelines and industrial and commercial customers, either directly through the Company's gathering system, or utilizing transportation services provided by regulated interstate pipeline companies.

The Company utilizes commodity-based derivative instruments as hedges to manage a portion of the exposure to price volatility stemming from its oil and natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures and option contracts for Appalachian, Michigan and eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oil production. The contracts hedge committed and anticipated natural gas purchases and sales and anticipated oil sales, generally forecasted to occur within the next two year period. Company policy prohibits the use of natural gas or oil futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position.

The Company through RNG has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used by RNG to coordinate fixed and variable priced purchases and sales, and by the Company to "lock in" fixed prices from time to time for the Company's share of production, and to establish "floors" and "ceilings" or "collars" on the possible range of the price realized for the sale of natural gas and oil. In order for contracts to serve as effective hedges, the derivatives must be highly effective in offsetting changes in cash flows of hedged items. There must be sufficient correlation to the underlying hedged transaction. While hedging can help provide price protection if spot prices drop, hedges can also limit upside potential.

For unhedged natural gas sales not subject to fixed price contracts, the Company is subject to price fluctuations for natural gas sold in the spot market and under market index contracts. The Company continues to evaluate the potential for reducing these risks by entering into hedge transactions. In addition, the Company may also close out any portion of hedges that may exist from time to time which may result in a gain or loss on that hedge transaction. Generally the Company hedges only a portion of its anticipated production, so some or all of the production is subject to the full fluctuation of market pricing.

The Company currently operates approximately 1,476 wells in the Appalachian Basin, 204 wells in the Michigan Basin and 991 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 51% ownership interest in the wells it operates.

The Company is paid a monthly operating fee for each well it operates for outside owners including the limited partnerships sponsored by the Company. The fee is competitive with rates charged by other operators in the area. The fee covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions.

Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed gathering systems in some of its areas of operations. The Company also continues to construct new trunk lines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems.

The Company is paid a transportation fee for natural gas that is moved by other shippers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners.

The Company's business and the natural gas industry in general are heavily regulated. The availability of a ready market for natural gas production depends on several factors beyond the Company's control. These factors include regulation of natural gas production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment, control and reduce the risk to the public and workers from the drilling completion, production and transportation of oil and natural gas, prevent waste of natural gas, protect rights to produce natural gas between owners in a common reservoir and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the United States the federal and state governments own a large percentage of the land and the rights to develop oil and natural gas. Recently the Company has increased its positions in these types of leases. Generally government leases are subject to additional regulations and controls not commonly seen on private leases. The Company takes the steps necessary to comply with applicable regulations both on its own behalf and as part of the services it provides to its investor partnerships. The Company's management believes that it is in substantial compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following discussion of the regulation of the United States natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Company's operations may be subject.

The Company's oil and natural gas operations are subject to various types of regulation at the federal, state and local levels. Prior to commencing drilling activities for a well, the Company must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. Such permits and approvals include those for the drilling of wells, and such regulation includes maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. Where wells are to be drilled on state or federal leases additional regulations and conditions may apply. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and natural gas industry increases the Company's costs of doing business and, consequently, affects its profitability. In as much as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.

Historically, the transportation and sale for resale of natural gas in interstate commerce were regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (FERC). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future.

The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In the past, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No.636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non‑pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No.636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No.636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is the greater transportation access available on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long‑term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates.

Additional proposals and proceedings that might affect the natural gas industry occur frequently in the Congress, FERC, state commissions, state legislatures, and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The Company cannot determine to what extent future operations and earnings of the Company will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the natural gas industry in general, the business and prospects of the Company could be adversely affected.

The Company generates wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.

The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although the Company's management believes that it has utilized good operating and waste disposal practices, prior owners and operators of these properties may not have utilized similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.

The Company's expenses relating to preserving the environment during 2004 were not significant in relation to operating costs and the Company expects no material change in 2005. Environmental regulations have had no materially adverse effect on the Company's operations to date, but no assurance can be given that environmental regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the Company's business, financial condition or results of operations.

The Company's exploration and production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean‑up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's pipeline, gathering and distribution operations are subject to the many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, and surrounding properties caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any significant problems related to its facilities could adversely affect the Company's ability to conduct its operations. In accordance with customary industry practice, the Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the Company's operations and financial condition. The Company cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all.

The Company's management believes that its exploration, drilling and production capabilities and the experience of its management and professional staff generally enable it to compete effectively. The Company encounters competition from numerous other oil and natural gas companies, drilling and income programs and partnerships in all areas of its operations, including drilling and marketing natural gas and obtaining desirable natural gas leases. Many of these competitors possess larger staffs and greater financial resources than the Company, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future depends upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company competes with a number of other companies that offer interests in drilling partnerships with a wide range of investment objectives and program structures. Competition for investment capital for both public and private drilling programs is intense. The Company also faces intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. During 2004 the industry experienced increased demand for drilling services and supplies. This is resulting in increasing costs, and in some cases the demand for supplies and services exceeds the available supplies. This can result in higher well costs and delays in the execution of planned drilling operations. Factors affecting competition in the oil and natural gas industry include price, location, availability, quality and volumes produced. The Company's management believes that it can compete effectively in the oil and natural gas industry on each of the foregoing factors. Nevertheless, the Company's business, financial condition or results of operations could be materially adversely affected by competition.

As of December 31, 2004, the Company had 120 employees, including 17 in finance and data processing, 8 in administration, 12 in exploration and development, 78 in production and 5 in natural gas marketing. The Company's engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and pipeline systems. In addition, the Company retains subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at drilling sites. The Company's employees act as supervisors of the subcontractors.

The Company's employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent.

Oil and natural gas prices fluctuate unpredictably and a decline in oil and natural gas prices can significantly affect the Company's financial results and impede its growth.

The Company's revenue, profitability and cash flow depend in large part upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect the Company's financial results and impede its growth. Changes in oil and natural gas prices have a significant impact on the value of the Company's reserves and on its cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the Company's control, including national and international economic and political factors and federal and state legislation.

Lower oil and natural gas prices may not only decrease the Company's revenues , but also may reduce the amount of oil and natural gas that the Company can produce economically. This may result in the Company having to make substantial downward adjustments to its estimated proved reserves. If this occurs or if the Company's estimates of development costs increase, production data factors change or the Company's exploration results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. The Company may incur impairment charges in the future, which could have a material adverse effect on its results of operations.

The Company's estimated oil and gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of the Company's reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. The Company's estimates of oil and gas reserves are prepared by Wright & Company (Wright), independent petroleum engineers, using pricing, production, cost, tax and other information provided by the Company. Over time, Wright may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Also, Wright makes certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect the estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Some of our reserve estimates are made without the benefit of a lengthy production history, which renders these reserve estimates less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which the reserve estimates are based, as described above, often result in the actual quantities of oil and gas recovered being different from earlier reserve estimates.

The present value of future net cash flows from the proved reserves is not necessarily the same as the current market value of the estimated oil and natural gas reserves (the Securities and Exchange Commission requires the use of year end prices). The estimated discounted future net cash flows from proved reserves are based on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as actual prices we receive for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Unless oil and natural gas reserves are replaced as they are produced, the Company's reserves and production will decline, which would adversely affect the Company's business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we have estimated and can change due to other circumstances.Thus, the Company's future oil and natural gas reserves and production and, therefore, its cash flow and income are highly dependent on efficiently developing and exploiting the Company's current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs.

Prospects drilled by the Company may not yield natural gas or oil in commercially viable quantities.

A prospect is a property on which the Company's geologists have identified what they believe, based on available information, to be indications of natural gas or oil bearing rocks. However, the use of available data and other technologies and the study of producing fields in the same area will not enable the geologists to know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to repay drilling or completion costs and generate a profit. If a well is determined to be dry or uneconomic, which can occur even though it contains some oil or gas reserves, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient oil and gas to be profitable. If the Company drills a dry hole or non-profitable well on current and future prospects, the profitability of its operations will decline and the value of the Company will be reduced. In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive.

The Company may not be able to identify enough attractive prospects on a timely basis to meet its own development needs and those of the partnerships it forms for investors, which could limit the Company's development opportunities and/or force it to reduce the partnership activity.

Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for the Company to continue to grow its reserves and production, and for it to be able to continue its partnership drilling activities. The Company's ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, oil and natural gas prices, competition, costs, drilling results, and the ability of the Company's geologists to successfully identify potentially successful new areas to develop. Because of these uncertainties, The Company's profitability and growth opportunities may be limited by the timely availability of new drilling locations, and it could be forced to terminate or curtail its partnership activities because of a lack of suitable prospects for the partnerships.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect the Company's business, financial condition and results of operations.

Drilling activities are subject to many risks, including the risk that wells will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including unusual or unexpected geological formations, pressures, fires, blowouts, loss of drilling fluid circulation, title problems, facility or equipment malfunctions, unexpected operational events, shortages or delivery delays of equipment and services, compliance with environmental and other governmental requirements, and adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. The Company maintains insurance against various losses and liabilities arising from operations; however, insurance against all operational risks is not available. Additionally, the Company management may elect not to obtain insurance if the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Company's business activities, financial condition and results of operations.

Increased drilling activity, particularly in the Rocky Mountain Region, may create a shortage of drilling rigs, service providers, or materials forcing the Company to curtail its drilling operations for itself and its partnerships thereby reducing revenue and profits from new oil and gas wells and from the Company's drilling and completion activities.

With high levels of oil and gas prices many oil and gas companies have increased their levels of drilling and completing new wells and reworking old wells. At the same time there is a limited supply of drilling rigs, completion equipment and qualified personnel to provide the services necessary to drill, complete and rework new wells. In particular, the Rocky Mountain Region has seen a great increase in activity over the past few years. If the demand for these goods and services continues to increase shortages may develop, which could result in increased prices for these goods and services or the Company's inability to complete all of the drilling it has planned. This could result in decreased profitability for the Company and the temporary or permanent loss of part or all of its partnership drilling activity.

The Company's drilling and development segment receives virtually all of its revenue from the publicly registered partnerships it sponsors, and a reduction or loss of that business could reduce or eliminate the revenue and profits associated with those activities.

The Company's drilling activities are dependent upon the capital raised by the Company as sponsor of SEC registered limited partnerships. The Company sells oil and natural gas partnerships through a network of non-affiliated NASD broker dealers. The largest of those broker dealers sold about 11% of the partnership units in 2004. Investors in the partnerships are interested in the tax deductions generated by the intangible drilling costs and the cash flow generated by the partnerships. If the tax laws were changed to reduce or eliminate the tax advantages, if the cash flow from the partnerships were to decline due to weak wells or lower energy prices, or if the brokers decide to stop offering our partnerships for some other reason, the sales of the partnership units would decline, reducing or eliminating the revenue and profits associated with the drilling and completion business segment.

Under the Successful Efforts accounting method used by the Company unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive which results in a reduction of net income and could have a negative impact on the Company's stock price.

The Company plans to increase its exploratory drilling in 2005 in order to identify additional opportunities for future development. However the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful under the successful efforts method of accounting used by the Company. In addition lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells the Company anticipates that some or all of its exploratory wells may not be productive. The costs of such unsuccessful wells could result in a significant reduction in the Company's profitability in periods when they are required to be expensed, which could have an adverse effect on the Company's stock price. In addition unsuccessful wells will not add to the Company's reserves or production.

In order to continue to grow and maintain its profitability, the Company must annually add new reserves exceeding its yearly production at a finding and development cost that yields an acceptable operating margin and depreciation, depletion and amortization rate. Without cost effective exploration, development or acquisition activities, production, reserves and profitability will decline over time. Given the relative maturity of most gas basins in North America the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2004 on a per unit basis, particularly in the Rocky Mountain region, and the Company believes these values may continue to increase in 2005. This increase in finding and development costs is resulting in higher depreciation, depletion and amortization rates. If the upward trend in finding and development costs continues, the Company will be exposed to an increased likelihood of a writedown in carrying value of its natural gas and oil properties in response to falling prices, which would impair its profitability.

The Company's development and exploration operations require substantial capital and it may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves and production.

The oil and natural gas industry is capital intensive. The Company makes and expects to continue to make substantial capital expenditures in its business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, the Company has financed capital expenditures primarily with cash generated by operations and proceeds from bank borrowings. Currently the Company intends to finance its capital expenditures with cash flows from operations and its existing financing arrangements. Cash flows from operations and access to capital are subject to a number of variables, including the Company's proved reserves, the level of oil and natural gas the Company is able to produce from existing wells, the prices at which oil and natural gas are sold, and the Company's ability to acquire, locate and produce new reserves.

If the Company's revenues or the borrowing base under its revolving credit facility decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, it may have limited ability to obtain the capital necessary to sustain its operations at planned levels.

If additional capital is needed, the Company may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves.

The Company's credit facility and other debt financing have substantial restrictions and financial covenants and the Company may have difficulty obtaining additional credit, which could adversely affect our operations.

The Company will depend on its revolving credit facility for future capital needs. The revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

A substantial part of the Company's producing properties are located in the Rocky Mountains, making it vulnerable to risks associated with operating in one major geographic area.

The Company's operations are becoming increasingly focused on the Rocky Mountain region, which means its producing properties and new drilling opportunities are geographically concentrated in that area. As a result, the Company, the success of its operations, and its profitability may be disproportionately exposed to the impact of delays or interruptions of production from existing or planned new wells by significant governmental regulation, transportation capacity constraints, curtailment of production, interruption of transportation, or fluctuations in prices of oil and natural gas produced from the wells in the region.

Seasonal weather conditions and lease stipulations adversely affect the Company's ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas, including parts of the Sand Wash and Piceance Basins, drilling and other oil and natural gas activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to 6 months out of the year. This limits operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay operations and materially increase operating and capital costs and therefore adversely affect profitability.

Properties that the Company buys may not produce as projected and the Company may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

One of the Company's growth strategies is to acquire producing oil and natural gas reserves in its areas of operations and in new areas to help establish a base of operations for further development. However, reviews of potential acquisitions are inherently incomplete because it generally is not feasible to review in depth every individual property. Ordinarily, the Company focuses review efforts on the higher value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable or detectable even when an inspection is undertaken. Even when problems are identified, the Company may choose to assume certain environmental and other risks and liabilities in connection with acquired properties.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

The Company operates most of the wells in which it owns an interest. However it also participates in some cases through joint operating agreements under which it owns partial interests in oil and natural gas properties. If the Company does not operate the properties in which it owns an interest, it does not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator to adequately perform operations, or an operator's breach of the applicable agreements, could reduce production and revenues. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of the Company's control, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology.

Market conditions or operational impediments hinder access to oil and natural gas markets or delay production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. The Company's ability to market its production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm the Company's business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, the Company would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

Our hedging activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of oil and natural gas and to allow our gas marketing company to offer pricing options to gas sellers and purchasers, the Company uses hedging arrangements for a portion of its oil and natural gas production from its own wells, and for gas purchases and sales by its marketing subsidiary. Hedging arrangements expose the Company to the risk of financial loss in some circumstances, including when production, purchases or sales are different than expected, the counter-party to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. In addition, hedging arrangements may limit the benefit from changes in the prices for oil and natural gas and may require the use of Company resources to meet cash margin requirements.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, the Company's oil and natural gas hedging arrangements as well as the hedging arrangements of its marketing subsidiary expose the Company to credit risk in the event of nonperformance by counterparties.

The Company depends on a limited number of key personnel who would be difficult to replace.

The Company depends on the performance of our executive officers and other key employees. The loss of any member of senior management or other key employees could negatively impact the Company's ability to execute its strategy. The Company does not maintain key person life insurance policies on any of its employees.

Competition in the oil and natural gas industry is intense, which may adversely affect the Company's ability to succeed.

The oil and natural gas industry is intensely competitive, and the Company competes with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than the Company can, which would adversely affect the Company's competitive position. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because of the many companies in our industry have greater financial and human resources, the Company may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. These factors could adversely affect the success of the Company's operations and its profitability.

The Company is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

The Company's exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, the Company could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, the Company's activities are subject to the regulation by oil and natural gas-producing states of conservation practices and protection of correlative rights. These regulations affect operations and limit the quantity of oil and natural gas that can be produced and sold. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the Company's ability to explore on or develop its properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect profitability. Furthermore, the Company may be put at a competitive disadvantage to larger companies in the industry who can spread these additional costs over a greater number of wells and larger operating staff. See "Business - Governmental Regulation - Regulation of Oil and Natural Gas Exploration and Production" and "Business - Governmental Regulation - Environmental Regulations" for a description of the laws and regulations that affect us.

The table below shows the number of the Company's productive gross and net wells at December 31, 2004.


Nevada	95-2636730
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)