UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission File Number: 001-33614

Ultra Petroleum Corp.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

281-876-0120

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  YES þ     NO o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YES o      NO þ

 

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirement for the past 90 days.  YES þ     NO o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not 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.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  YES o     NO þ

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $15,086,678,210 as of June 30, 2008 (based on the last reported sales price of $98.20 of such stock on the New York Stock Exchange on such date).

 

As of February 13, 2009, there were 151,232,545 common shares of the registrant outstanding.

 

Documents incorporated by reference: The definitive Proxy Statement for the 2009 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2008, is incorporated by reference in Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

 

 

 

Terms used to describe quantities of oil and natural gas and marketing

 

 

Terms used to describe the Company’s interests in wells and acreage

 

 

Terms used to assign a present value to the Company’s reserves

 

 

Terms used to classify the Company’s reserve quantities

 

The Securities and Exchange Commission (“SEC”) definition of proved oil and natural gas reserves, per Regulation S-X, is as follows:

 

Proved oil and natural gas reserves.  Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made as defined in Rule 4-10(a)(2). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 

(a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

 

(b) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

 

(c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

 

Proved developed reserves — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as defined in Rule 4-10(a)(3).

 

Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required as defined in Rule 4-10(a)(4).

 

Terms used to describe the legal ownership of the Company’s oil and natural gas properties

 

 

Terms used to describe seismic operations

 

 

 

 

Ultra Petroleum Corp. (“Ultra” or the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company was originally incorporated on November 14, 1979, under the laws of the Province of British Columbia, Canada. Ultra remains a Canadian company, but since March 2000, has operated under the laws of The Yukon Territory, Canada pursuant to Section 190 of the Business Corporations Act (Yukon Territory). The Company’s operations are primarily in the Green River Basin of southwest Wyoming. The Company continually evaluates other opportunities for the acquisition, exploration and development of oil and natural gas properties.

 

Ultra’s current operations are focused on developing and expanding its position in a tight gas sand trend located in the Green River Basin in southwest Wyoming. As of December 31, 2008, Ultra owns interests in approximately 121,432 gross (59,953 net) acres in Wyoming covering approximately 190 square miles. The Company owns an interest in approximately 984 gross producing wells in this area and is operator of approximately 50% of the 984 gross wells. The Company also has an exploration effort underway in Pennsylvania.

 

Following the acquisition of Pendaries Petroleum Ltd. on January 16, 2001, the Company became active in oil and natural gas exploration and development covering the 04/36 Block and the 05/36 Block in Bohai Bay, China. During the third quarter of 2007, the Company made the decision to dispose of Sino-American Energy Corporation, which owned our Bohai Bay assets in China, in order to focus on our legacy asset in the Pinedale Field in southwest Wyoming. The reserve volumes sold represented all of Ultra’s international assets and, previously, were the only results included in our foreign operating segment. See Note 11 for further discussion on the completion of the sale.

 

The Company also owns interests in 287,745 gross (152,227 net) acres in Pennsylvania. The Company has drilled three deep test wells in the Marshlands prospect area to date. During the year ended December 31, 2008, the Company participated in the drilling of 18 gross (9.63 net) wells on the Pennsylvania properties. At year end 2008, there was 1.0 gross (0.5 net) exploratory well that commenced during the year that was actively drilling and 17 gross (9.13 net) wells that were suspended. After flowback testing, these wells have been shut-in awaiting further development and pipeline connection.

 

The Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to such reports and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge to the public on the Company’s website at www.ultrapetroleum.com. To access the Company’s SEC filings, select “Financials” under the Investor Relations tab on the Company’s website. You may also request a copy of these filings at no cost by making written or telephone requests for copies to Ultra Petroleum Corp., Manager, Investor Relations, 363 N. Sam Houston Pkwy. E., Suite 1200, Houston, TX 77060, (281) 876-0120.

 

Any materials that the Company has filed with the SEC may be read and/or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding us. The SEC’s website address is www.sec.gov.

 

Business Strategy

 

Green River Basin, Wyoming

 

During 2009, the Company plans to continue its ongoing program to identify, develop and explore the acreage position now held in the tight gas sand trend in the Green River Basin in southwest Wyoming. The Company expects that wells drilled during 2009 will target the sands of the upper Cretaceous Lance Pool in the Pinedale and Jonah fields. The Lance Pool, as administered by the Wyoming Oil and Gas Conservation Commission (“WOGCC”), includes sands of both the Lance (found at subsurface depths of approximately 8,000 to 12,000 feet) and Mesaverde (found at subsurface depths of approximately 12,000 to 14,000 feet) in the Pinedale and Jonah fields area of Sublette County, Wyoming. The Company plans to drill delineation, step-out and exploration wells on its Green River Basin

acreage positions in an ongoing attempt to further define and expand the current known producing limits of these two field areas. Work is continuing in an effort to assess the need for further increased density drilling to more efficiently recover the vast resources present in the area. Currently, most of the Pinedale field is approved by the WOGCC for 16 wells per 160-acre government quarter section (10-acre equivalent). Pilot areas approved for testing of well density of 32 wells per government quarter section (5-acre equivalent) continue to be evaluated with additional, newly approved pilot areas added to the assessment and results expected during 2009. Current spacing in the Jonah field is eight wells per 80-acre drilling and spacing unit (10-acre spacing) with several pilots testing spacing at 16 wells per 80-acre drilling and spacing unit (5-acre spacing). All of the Company’s drilling activity is conducted utilizing its extensive integrated geological and geophysical data set. This data set is being utilized to map the potentially productive intervals, to identify areas for future extension of the Lance fairway and to identify deeper objectives which may warrant drilling.

 

Pennsylvania

 

During 2009, the Company plans to complete acquisition of a 3D seismic survey in the Marshlands area, continue evaluation of its acreage holding in the area, acquire additional acreage, and participate in the drilling of additional exploratory wells.

 

Marketing and Pricing

 

Ultra derives its revenues principally from the sale of its natural gas and associated condensate production from wells operated by the Company and others in the Green River Basin in southwest Wyoming. The Company’s revenues are determined, to a large degree, by prevailing natural gas prices for production situated in the Rocky Mountain region of the United States, specifically, southwest Wyoming. With the first segment of the Rockies Express Pipeline, LLC (“REX”) operational during 2008 (as discussed below), a substantial portion of the Company’s revenues are determined by market prices in the midwestern and eastern regions of the United States. Energy commodity prices in general, and the Company’s regional prices in particular, have been highly volatile in the past, and such high levels of volatility are expected to continue in the future. The Company experienced significant levels of volatility in the pricing for its natural gas and condensate production during 2008. The Company cannot predict the market prices for the sale of its natural gas, condensate, or oil production.

 

The Company, from time to time, in the regular course of its business, has hedged a portion of its natural gas production primarily through the use of fixed price, forward sales of physical gas, or through the use of financial swaps with financial counterparties the Company believes to be creditworthy. The Company may elect to hedge additional portions of its forecasted natural gas production in the future, in much the same manner as it has done previously. For a more detailed description of the Company’s hedging activities, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.

 

Natural Gas Marketing

 

Ultra currently sells all of its natural gas production to a diverse group of third-party, non-affiliated entities in a portfolio of transactions of various durations and prices (daily, monthly and longer term). Historically, the Company’s customers were predominately located in the western United States — primarily California and the Pacific Northwest, as well as the Front Range area of Colorado and in Utah. With the first segment of REX operational, the Company’s customer base expanded to include customers in the midwestern and eastern regions of the United States.

 

The sale of the Company’s natural gas is “as produced”. As such, the Company does not maintain any significant inventories or imbalances of natural gas. The Company maintains credit policies intended to mitigate the risk of uncollectible accounts receivable related to its sale of natural gas. The Company does not have any outstanding, uncollectible accounts for its natural gas sales at December 31, 2008.

 

The Company has entered into various gathering and processing agreements with several midstream service providers that gather, compress and process natural gas owned or controlled by the Company from its producing wells in the Pinedale Anticline and Jonah fields in southwest Wyoming. Under these agreements, the midstream

service providers have routinely expanded their facility’s capacities in southwest Wyoming to accommodate growing volumes from wells in which the Company owns an interest. The Company has, in recent years, been able to lower some of the gathering and processing fees for such midstream services with its midstream service providers, in exchange for committing to these longer term arrangements. As a result of such negotiations, two new, large cryogenic gas processing plants have been constructed in southwest Wyoming. These facilities remove natural gas liquids from the Company’s gas (and gas of others) making it sufficient quality to be accepted into the natural gas transmission pipelines serving the area. One of these facilities was placed into service in the first quarter of 2007, and another larger facility was completed and became fully operational during 2008. The new facilities have added incremental cryogenic processing capacity of approximately 1.1 Bcf per day to the southwest Wyoming area. The Company has contractually secured capacity at both of these facilities for the processing of its natural gas. The Company believes that the capacity of the midstream infrastructure related to its production will continue to be adequate to allow it to sell essentially all of its available natural gas production.

 

The market price for natural gas in the Rockies generally, and in southwest Wyoming specifically, is influenced by a number of regional and national factors, all of which are unpredictable and are beyond the Company’s ability to control or to predict. These factors include, among others, weather, natural gas supplies, natural gas demand, and natural gas pipeline capacity to export gas from the Rockies.

 

The Rocky Mountain region is typically a net exporter of natural gas because local natural gas production typically exceeds local demand for natural gas during non-winter months. As a result, natural gas production in southwest Wyoming has historically sold at a discount relative to other U.S. natural gas production sources or market areas. These regional pricing differentials or discounts are typically referred to as “basis” or “basis differentials” and are reflective, to some extent, of the costs associated with transporting the Company’s gas to markets in other regions or states. The Company has seen significant basis differentials for its Wyoming production versus the Henry Hub (“Henry Hub”) NYMEX natural gas futures delivery or pricing reference point in south Louisiana in the past. This trend continued in 2008.

 

In years past, increases in pipeline capacity to transport production from Rocky Mountain production areas to markets in the West have served to improve (i.e. lower) basis differentials for Wyoming natural gas production. (Examples include: Kern River Pipeline — in service May 2003; the Cheyenne Plains Pipeline — in service February 2005; and Rockies Express Pipeline expansion to Cheyenne, Wyoming placed into service on February 14, 2007). These expansions of pipeline export capacity have historically reduced but not entirely eliminated the basis differential for natural gas prices in southwest Wyoming when compared to prices at the Henry Hub pricing reference point.

 

This trend of smaller basis differentials and improved wellhead prices in Wyoming following significant pipeline expansions has continued with the initiation of service on the REX West pipeline in early 2008. The prices for the Company’s Wyoming natural gas production were substantially improved on both a relative (locational basis adjusted) and real (net price) basis during the first half of 2008. However, unprecedented growth in natural gas production from the Rockies and other fields and basins in North Texas, Louisiana, Oklahoma, and Arkansas during 2008, coupled with a high utilization of existing natural gas pipeline export capacity, resulted in natural gas prices in the Rocky Mountain region at significantly lower levels during the second half of 2008 as compared to the first half of 2008. A contraction in industrial demand for natural gas during this time also contributed to a drop in prices.

 

Unplanned hydrostatic testing on a 26 mile segment of the REX Pipeline in Kansas during September 2008 reduced the export capacity of the natural gas pipeline grid in Wyoming by 200 MMCFD. The impact to the supply/demand balance of natural gas in Wyoming as a result of the reduction in pipeline export capacity (and as a result, spot natural gas prices) was both immediate and severe. In response to this change in the supply/demand balance, the Company made voluntary reductions of 100 MMCFD to its gas sales and physically shut-in some volumes during September and part of October 2008.

 

The Company has previously and continues to take action to assure that the pipeline infrastructure to move its natural gas supplies away from southwest Wyoming is expanded to provide sufficient capacity to transport its natural gas production and to provide for reasonable prices for its natural gas in the future. Previously, the Company agreed to become an anchor shipper on REX, sponsored by subsidiaries of Kinder Morgan, Conoco Phillips, and Sempra Energy. The Rockies Express Pipeline begins at the Opal Processing Plant in southwest Wyoming and

traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. This pipeline is ultimately projected to cover more than 1,800 miles and is designed as a large-diameter (42”), high-pressure natural gas pipeline. The Rockies Express Pipeline is an interstate pipeline and is subject to the jurisdiction of the United States Federal Energy Regulatory Commission (“FERC”). Commencing upon completion of the pipeline facilities, the Company’s commitment involves a capacity of 200 MMBtu per day of natural gas for a term of 10 years, and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper.

 

The pipeline is being built in two phases: REX — West (Wyoming to Missouri — in service) and REX — East (Missouri to Ohio — under construction). The REX partners have recently updated guidance on the timing for completion of various portions of REX — East. As of January 2009, REX has announced that it expects approximately 275 miles of 42” pipeline and five new pipeline interconnections in eastern Illinois and western Indiana to be placed into service on or about April 1, 2009. As part of that same announcement, Kinder Morgan has also indicated that approximately an additional 169 miles of pipeline and an additional nine pipeline interconnections in Indiana and western Ohio will be placed into service on or around June 15, 2009. Kinder Morgan further advised that the balance of the REX — East pipeline will be available to be placed into service by November 1, 2009, with an expanded capacity of 1.8 Bcf per day. The increase in capacity from 1.5 Bcf per day to 1.8 Bcf per day that coincides with this completion is due to the installation of additional compressor units at two compressor stations on REX — West, one of which is located in Wyoming and the other in Nebraska.

 

As the REX — East project is completed as contemplated above, the Company expects that the price that it receives for its gas which is sold off of the REX — East project will be sold at prices that will reflect an improvement relative to the prices that it currently receives for its gas sales at REX — West, Rockies and Wyoming sales points.

 

Oil Marketing

 

The Company markets its Wyoming condensate (which is an oil-like product that is produced coincident to its natural gas production from gas wells located in the Pinedale Anticline and Jonah Fields in Sublette County, Wyoming), to various purchasers. The pricing of the Company’s condensate production varied significantly during 2008 and is based on NYMEX crude futures daily settlement prices, less a negotiated location and transportation discount or differential. All of the Company’s condensate sales are denominated in U.S. dollars per barrel and are paid for on a monthly basis. The Company’s condensate production is gathered from its Wyoming well locations by tanker trucks and is then shipped to other locations for injection into crude oil pipelines or other facilities. The Company routinely maintains only operating inventories of condensate production and sells its product on an “as produced” basis.

 

Environmental Matters

 

The U.S. Bureau of Land Management (“BLM”) initiates preparation of an Environmental Impact Statement (“EIS”) relating to potential natural gas development on federal lands in the Pinedale Anticline area in the Green River Basin of Wyoming. An EIS is required under the National Environmental Policy Act (“NEPA”) for major federal actions significantly affecting the quality of the human environment and entails consideration of environmental consequences of a proposed action and its alternatives. Although the Company co-owns leases on state and privately owned lands in the vicinity of the Pinedale Anticline that do not fall under the federal jurisdiction of the BLM and are not subject to the EIS requirement, the area north of the Jonah field, including the Pinedale Anticline, which the EIS addresses, is where most of the Company’s exploration and development is taking place. The BLM issues a Record of Decision (“ROD”) with respect to a final EIS, which allows for surface disturbances for drilling and production activities within the area covered by the EIS, but does not authorize the drilling of particular wells. Ultra, therefore, must submit applications to the BLM’s Pinedale field manager for permits and other required authorizations, such as rights-of-way for each specific well or particular pipeline location. In making its determination on whether to approve specific drilling or development activities, the BLM applies the requirements of the ROD.

The ROD imposes limits on drilling and completion activity and proposes mitigation guidelines, standard practices for industry activities and best management practices for sensitive areas. The Company cannot predict if or how these adjustments may affect permitting, development and compliance under the ROD. The BLM’s field manager may also impose additional limitations and mitigation measures as are deemed reasonably necessary to mitigate the impact of drilling and production operations in the area.

 

To date, the Company has expended significant resources in order to satisfy applicable environmental laws and regulations in the Pinedale Anticline area and other areas of operation under the jurisdiction of the BLM. The Company’s future costs of complying with these regulations may continue to be significant. Further, any additional limitations and mitigation measures could further increase production costs, delay exploration, development and production activities or curtail exploration, development and production activities altogether.

 

In August 1999, the BLM required an Environmental Assessment (“EA”) for the potential increased density drilling in the Jonah Field area. An EA is a more limited environmental study than that conducted under an EIS. The EA was required to address the potential environmental impacts of developing the field on a well density of two wells per 80-acre drilling and spacing unit as opposed to the one well per 80-acre drilling and spacing unit as was approved in the initial Jonah field EIS approved in 1998. The new EA was completed in June 2000. With the approval of this EA and the earlier approval by the WOGCC for drilling of two wells per 80-acre drilling and spacing unit, the Company was permitted to drill infill wells at this well density on the 2,160 gross (1,322 net) acres then owned by the Company in the Jonah field. Subsequently, various other operators have received approval for the drilling of increased density wells in pilot areas at well densities ranging from four wells per 80-acre drilling and spacing unit to sixteen wells per drilling and spacing unit. Results of all of these pilot projects were utilized in acquiring approval from the WOGCC in November 2004 to increase the overall density of development for the Jonah Field to eight wells per 80-acre drilling and spacing unit.

 

The BLM prepared a new EIS covering the Jonah field to assess the impact of increased density development and define the parameters under which this increased density development will be allowed to proceed. The draft EIS was made available in February 2005 and the final ROD was issued on March 14, 2006. Key components of the ROD require an annual operations plan that includes all previous year activity including the number of wells drilled, total new surface disturbance by well pads, roads, and pipelines, and current status of all reclamation activity. Also required is a plan of development for the upcoming year reflecting the planned number of wells to be drilled and an estimate of new surface disturbance and reclamation activity. Other components include a drilling rig forecast, emission reduction report, annual water well monitoring reports, a three-year operational forecast and the use of flareless-completion technology to reduce noise, visual impacts and air emissions, including greenhouse gases as well as other monitoring and mitigation measures.

 

During the period from 2003 through year end 2008, Ultra and other operators in the Pinedale field received approval from the WOGCC to drill increased density and pilot project wells in several areas in the Lance Pool across the Pinedale field. At the end of 2007, there were over a dozen different infill density and pilot project orders granted by the WOGCC and currently in place on the Pinedale field. While a very minor portion of the Pinedale field still provides for one well per 40 acres, a succession of WOGGC approvals through yearend 2007 now provide for and range from two wells per 40 acres (20-acre density) up to a 32 well per 160-acre pilot project (5-acre density). The northern portion of the Pinedale field is operated by Questar Exploration and Production Company (“Questar”) in which the Company is a working interest partner and owns a working interest in the majority of Questar’s acreage. Questar’s most recent infill density application, approved in July 2007, provided for the drilling of 16 wells per quarter section (10-acre density). With respect to the central portion of the Pinedale field, approval was granted for development on a two wells per 40-acre density in November 2005. Ultra operates the majority of the acreage covered by this approval. Within this two wells per 40-acre density area and in an additional area in the southern portion of the Pinedale field, in July 2007, Ultra and other operators received approval from the WOGCC to provide for the drilling of 16 wells per quarter section (10-acre density). Finally, in December 2007, approximately 2% (640 gross acres) of the productive area of the Pinedale field in which Company owns a working interest has now been approved by the WOGCC for drilling at the equivalent of 5-acre density; an additional 73% (26,888 gross acres) has been approved for drilling at equivalent 10-acre density; an additional 18% (6,687 gross acres) has been approved for drilling at equivalent 20-acre density, with 7% (2,400 gross acres) still under the state wide 40-acre well density rules. Further drilling and testing within the areas approved for increased density

continues, the results of which are being evaluated to determine the overall development strategy for the Pinedale field and the ultimate need for future increases in development density.

 

Ultra, Shell and Questar (“Proponents”) submitted a development proposal for the Pinedale field which includes broad application of operations principles being evaluated in the demonstration project area. The Proponents entered into a memorandum of understanding with the BLM to commence the preparation of a Supplemental Environmental Impact Statement (“SEIS”) for year-round access in the Pinedale field. The SEIS process included assessment of alternative considerations and mitigation requirements that were considered as alternatives, or in addition, to those included in the proposal. The proposal included commitments to reduce surface disturbance by utilizing fewer overall pads and drilling more directional wells than called for in the 2000 Pinedale Anticline Project Area (“PAPA”) ROD.

 

The final ROD was granted on September 9, 2008. The 2008 SEIS ROD allows, among other things, for full field development from no more than 600 well pads field-wide, as well as year-round development and delineation activity within big game (pronghorn and mule deer) and greater sage-grouse seasonal use areas. Further, the Proponents agreed to implement numerous individual mitigation components. These commitments include i) the use of a full-field liquids gathering system, ii) the use of advanced rig engine emission reduction technology by at least 80% of the Company’s 2005 rig emission levels, iii) a mitigation and monitoring fund to address mitigation efforts to minimize impacts from energy development, and iv) additional funding for ground water monitoring on the PAPA. Additionally, ten-year planning and annual meetings with BLM and appropriate state agencies will allow for proper community planning.

 

Also as part of the 2008 SEIS ROD, Ultra has offered to suspend additional activity for at least five years from the signing of the SEIS ROD on certain leases. After the five-year period, leases under federal suspension and/or term no surface occupancy will be considered for conversion to “available for development” when a comparable acreage in the core area of the PAPA has been returned to a functioning habitat.

 

In 2007 and 2008 Ultra entered five groundwater supply wells into the Wyoming Department of Environmental Quality Voluntary Remediation Program (“VRP”). These wells exceeded the Department of Environmental Quality’s (“DEQ”) minimum clean-up levels (“MCL”). Four of the five wells are now non-detect or below the MCL. The remaining well has a very low levels of contaminates and a remediation plan has been submitted to the DEQ for this well. Ultra encountered another water well that exceeded the MCL. This well was remediated and the contaminate levels were non-detect before it was entered into the VRP.

 

Regulation

 

Oil and Gas Regulation

 

The availability of a ready market for oil and natural gas production depends upon numerous factors beyond the Company’s control. These factors may include, among other things, state and federal regulation of oil and natural gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be shut-in because of a lack of an available natural gas pipeline in the areas in which the Company may conduct operations. State and federal regulations are generally intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to the Company are also subject to the jurisdiction of various federal, state and local agencies.

 

The Company’s sales of natural gas are affected by the availability, terms and costs of transportation both in the gathering systems that transport the natural gas from the wellhead to the interstate pipelines and in the interstate pipelines themselves. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the FERC under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has implemented regulations intended to increase competition within the natural

gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. On February 25, 2000, the FERC issued a statement of policy and a final rule concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for services. The final rule revises the FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets. The FERC has also issued several other generally pro-competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, the FERC generally reaffirmed its policy allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, the FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline-by-pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, the FERC established criteria to allow providers to charge market-based (i.e. negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short-term releases by shippers of interstate pipeline transportation capacity.

 

The Company’s sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates.

 

If the Company conducts operations on federal, tribal or state lands, such operations must comply with numerous regulatory restrictions, including various operational requirements and restrictions, nondiscrimination statutes and royalty and related valuation requirements. In addition, some operations must be conducted pursuant to certain on-site security regulations, bonding requirements and applicable permits issued by the BLM or Minerals Management Service, Bureau of Indian Affairs, tribal or other applicable federal, state and/or Indian Tribal agencies.

 

The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a non-reciprocal country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that holders of the Company’s equity interests may be citizens of foreign countries, which could be determined to be citizens of a non-reciprocal country under the Mineral Act.

 

Environmental Regulations

 

General.  The Company’s exploration, drilling and production activities from wells and natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products are subject to stringent federal, state and local laws and regulations governing environmental quality, including those relating to oil spills and pollution control. Although such laws and regulations can increase the cost of planning, designing, installing and operating such facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials in the environment or otherwise relating to the protection of the environment, will not have a material effect upon the Company’s operations, capital expenditures, earnings or competitive position.

 

Solid and Hazardous Waste.  The Company has previously owned or leased and currently owns or leases, numerous properties that have been used for the exploration and production of oil and natural gas for many years. Although the Company utilized standard operating and disposal practices, hydrocarbons or other solid wastes may have been disposed of or released on or under such properties on or under locations where such wastes have been taken for disposal. In addition, many of these properties are or have been operated by third parties over whom the Company has no control, nor has ever had control as to such entities’ treatment of hydrocarbons or other wastes or

the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and natural gas wastes and properties have gradually become stricter over time. Under current and evolving law, it is possible the Company could be required to remediate property, including ground water, containing or impacted by previously disposed wastes including performing remedial plugging operations to prevent future, or mitigate existing contamination.

 

Although oil and gas wastes generally are exempt from regulation as hazardous wastes (“Hazardous Wastes”), the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, it is possible some wastes the Company generates presently or in the future may be subject to regulation under RCRA and state analogs. The Environmental Protection Agency (“EPA”) and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and is considering adopting stricter disposal standards for non-hazardous wastes. Furthermore, certain wastes generated by the Company’s oil and natural gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under the RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.

 

Superfund.  The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, liability, generally is joint and several, for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRP”), include current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated and will generate wastes that fall within CERCLA’s definition of Hazardous Substances. The Company may also be an owner or operator of facilities on which Hazardous Substances have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages, as a past or present owner or operator or as an arranger. To its knowledge, the Company has not been named a PRP under CERCLA nor have any prior owners or operators of its properties been named as PRP’s related to their ownership or operation of such property.

 

National Environmental Policy Act.  As noted, the federal National Environmental Policy Act provides that, for major federal actions significantly affecting the quality of the human environment, the federal agency taking such action must prepare an EIS. In the EIS, the agency is required to evaluate alternatives to the proposed action and the environmental impacts of the proposed action and of such alternatives. Actions of the Company, such as drilling on federal lands, to the extent the drilling requires federal approval, may trigger the requirements of the National Environmental Policy Act, including the requirement that an EIS be prepared. The requirements of the National Environmental Policy Act may result in increased costs, significant delays and the imposition of restrictions or obligations, including but not limited to the restricting or prohibiting of drilling on a company’s activities.

 

Oil Pollution Act.  The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act (“CWA”), imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, a company could be liable for costs and damages.

Air Emissions.  The Company’s operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws generally require new and modified sources of air pollutants to obtain permits prior to commencing construction, which may require, among other things, stringent, technical controls. Other federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement agencies can bring actions for failure to strictly comply with air pollution regulations or permits and generally enforce compliance through administrative, civil or criminal enforcement actions, resulting in fines, injunctive relief and imprisonment.

 

Clean Water Act.  The CWA restricts the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. Under the Clean Water Act, permits must be obtained for the routine discharge pollutants into waters of the United States. The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities.

 

Endangered Species Act.  The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The Company conducts operations on federal oil and natural gas leases that have species, such as raptors that are listed as threatened or endangered and also sage grouse or other sensitive species, that potentially could be listed as threatened or endangered under the ESA. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. If a company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

 

OSHA and other Regulations.  The Company is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require a company to organize and/or disclose information about hazardous materials used or produced in its operations.

 

Climate Change Legislation.  More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause the Company to incur material expenses in complying with them. The U.S. Congress last session considered climate change-related legislation to regulate GHG emissions that could affect our operations and our regulatory costs, as well as the value of oil and natural gas generally. Although that legislation did not pass, expectations are that Congress will continue to consider some type of climate change legislation and that the EPA may consider climate change-related regulatory initiatives. As a result, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential federal and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce.

 

The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company.

Employees

 

As of December 31, 2008, the Company had 86 full-time employees, including officers.

 

 

There are inherent limitations in all control systems and failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

 

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design will succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions or the degree of compliance with its policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.

 

Our reserve estimates may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production data acquired subsequent to the date of an estimate may justify revising such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely.

 

Competitive industry conditions may negatively affect our ability to conduct operations.

 

We compete with numerous other companies in virtually all facets of our business. The competitors in development, exploration, acquisitions and production include major integrated oil and natural gas companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources that our Company can permit. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.

 

Factors that affect our ability to compete in the marketplace include:

 

 

Factors beyond our control affect our ability to effectively market production and may ultimately affect our financial results.

 

The ability to market oil and natural gas depends on numerous factors beyond our control. These factors include:

 

 

Because of these factors, we may be unable to market all of our oil and natural gas that we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce.

 

We may experience a temporary decline in revenues if we lose one of our significant customers.

 

A significant customer as used herein is one that individually accounts for 10% or more of our total revenues. In 2008, we had two significant customers for our natural gas production. Sales to Nicor Enerchange were $115.7 million and sales to Tenaska were $117.9 million, which accounted for 10.7% and 10.9% of the Company’s total 2008 revenues, respectively. To the extent these or any other significant customer reduces the volume of its natural gas purchases from us, we could, theoretically, experience a temporary interruption in sales of, or a lower price for, our natural gas. The Company has numerous other customers that would likely compensate for the loss of one or more of our significant customers by increasing their purchases of our natural gas production.

 

A decrease in oil and natural gas prices may adversely affect our results of operations and financial condition.

 

Our revenues are determined, to a large degree, by prevailing natural gas prices for production situated in the Rocky Mountain region of the United States, specifically, southwest Wyoming. Energy commodity prices in general, and our regional prices in particular, have been historically highly volatile, and such high levels of volatility are expected to continue in the future. We cannot accurately predict the market prices that we will receive for the sale of our natural gas, condensate, or oil production.

 

Oil and natural gas prices are subject to a variety of additional factors beyond our control, such as large fluctuations in oil and natural gas prices in response to relatively minor changes in the supply of and demand for oil and natural gas and market uncertainty. These factors include but are not limited to weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and natural gas, the price of foreign oil and natural gas imports and the availability of alternate fuel sources and transportation interruption. Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on the carrying value of our proved reserves, borrowing capacity, our ability to obtain additional capital, and the Company’s revenues, profitability and cash flows from operations.

 

The Company’s average price realization for natural gas, excluding gains and losses on commodity derivatives, was $4.81 per Mcf during the quarter ended December 31, 2008 as compared to $8.80 per Mcf for the quarter ended June 30, 2008. If prices received during the second quarter of 2008 were realized during the fourth quarter of 2008, natural gas revenues would have increased by approximately $150 million.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

 

A price decrease may more adversely affect the price received for our Wyoming production than production in other U.S. regions.

 

Natural gas prices in the southwest Wyoming region are critical to our business. The market price for this natural gas differs from the market indices for natural gas in the Gulf Coast region of the United States due potentially to insufficient pipeline capacity and/or low demand during certain months of the year for natural gas in the Rocky Mountain region of the United States. Therefore, a price decrease may more adversely affect the price received for our Wyoming production than production in the other U.S. regions. There have been, and continue to be, from time to time, numerous proposed pipeline projects, including the Rockies Express Pipeline, that have been announced to transport Rockies’ and Wyoming natural gas production to markets. Although the Company continuously evaluates its options and opportunities to support these project, there can be no assurance that such infrastructures will be built or that if built, they would prevent large basis differentials from occurring in the future. The Company has mitigated its exposure to this risk by securing capacity rights to transport a portion of its natural gas production on the Rockies Express pipeline and delivering it to markets beyond the Rocky Mountain region.

 

If the United States experiences a sustained economic downturn or recession, natural gas prices may fall, which may adversely affect our results of operations.

 

The unprecedented disruption in the U.S. and international credit markets has resulted in a rapid deterioration in the worldwide economy and tightening of the financial markets in the second half of 2008, and the outlook for the economy in 2009 is uncertain. The current global credit and economic environment has reduced worldwide demand for energy and resulted in significantly lower natural gas prices. A sustained reduction in the prices we receive for our natural gas production could have a material adverse effect on our results of operations. For example, for the quarter ending December 31, 2008, a 10% reduction in the price we received for natural gas would have reduced our revenues by approximately $20 million. In addition, current conditions in the credit and equity markets, if they persist, could also increase our financing costs and limit our financial flexibility. The continuation, or worsening, of domestic and global economic conditions could continue to adversely affect our business and results of operations.

 

Compliance with environmental and other government regulations could be costly and could negatively impact our production.

 

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

 

 

Under these laws and regulations or under the common law, the Company could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. The Company could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change and greenhouse gases. We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages. Accordingly, we may be subject to liability or may be required to cease production from properties in the event of environmental damages.

A significant percentage of our United States operations are conducted on federal lands. These operations are subject to a variety of on-site security regulations as well as other permits and authorizations issued by the BLM, the Wyoming Department of Environmental Quality and other federal agencies. A portion of our acreage is affected by winter lease stipulations that prohibit exploration, drilling and completing activities generally from November 15th to April 30th, but allow production activities all year round. To drill wells in Wyoming, we are required to file an Application for Permit to Drill with the WOGCC. Drilling on acreage controlled by the federal government requires the filing of a similar application with the BLM. These permitting requirements may adversely affect our ability to complete our drilling program at the cost and in the time period anticipated. On large-scale projects, lessees may be required to perform an EIS to assess the environmental impact of potential development, which can delay project implementation and/or result in the imposition of environmental restrictions that could have a material impact on cost or scope.

 

We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

 

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. Although we have been able to successfully raise money in the current economic climate, we may not be successful in the future. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

 

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capital expenditures to develop our existing reserves and to discover new oil and gas reserves.

 

Our ability to continue exploration and development of our properties and to replace reserves may be dependent upon our ability to continue to raise significant additional financing, including debt financing or obtain other potential arrangements with industry partners in lieu of raising financing. Any arrangements that may be entered into could be expensive to us. There can be no assurance that we will be able to raise additional capital in light of factors such as the market demand for our securities, the state of financial markets for independent oil and gas companies (including the markets for debt), oil and natural gas prices and general market conditions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of our capital budget.

 

We expect to continue using our bank credit facility to borrow funds to supplement our available cash flow. The loan commitment and aggregate amount of money we can borrow under the credit facility and from other sources is revised from time to time based on certain restrictive covenants. A change in our ability to meet the restrictive covenants might limit our ability to borrow. If this occurred, we may have to sell assets or seek substitute financing. We can make no assurances that we would be successful in selling assets or arranging substitute financing. For a description of the bank credit facility and its principal terms and conditions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Our operations may be interrupted by severe weather or drilling restrictions, particularly in the Rocky Mountain region.

 

Our operations are conducted primarily in the Rocky Mountain region of the United States. The weather in this area can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Likewise, our Rocky Mountain operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.

 

Our focus on exploration projects increases the risks inherent in our oil and gas activities.

 

We have historically invested a significant portion of our capital budget in drilling exploratory wells in search of unproved oil and gas reserves. We cannot be certain that these exploratory wells will be productive or that we will recover all or any portion of our investments. To increase the chances for exploratory success, we often invest in seismic or other geophysical data to assist us in identifying potential drilling objectives. Additionally, the cost of drilling, completing and testing exploratory wells is often uncertain at the time of our initial investment. Depending on complications encountered while drilling, the final cost of the well may significantly exceed our original estimate. We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment and are then depleted using the unit of production method based on our proved reserves.

 

Unless we are able to replace reserves which we have produced, our cash flows and production will decrease over time.

 

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, our reserves and production will decline. We can give no assurance that we will be able to find, develop or acquire additional reserves at acceptable costs.

 

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

 

The oil and natural gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, natural gas leaks, and discharges of toxic gases. The occurrence of any of these events with respect to any property we own or operate (in whole or in part) could have a material adverse impact on us. We and the operators of our properties maintain insurance in accordance with customary industry practices and in amounts that management believes to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial condition.

 

There are risks associated with our drilling activity that could impact our results of operations.

 

Our oil and natural gas operations are subject to all of the risks and hazards typically associated with drilling for, and production and transportation of, oil and natural gas. These risks include the necessity of spending large amounts of money for identification and acquisition of properties and for drilling and completion of wells. In the drilling of exploratory or development wells, failures and losses may occur before any deposits of oil or natural gas are found. The presence of unanticipated pressure or irregularities in formations, blow-outs or accidents may cause such activity to be unsuccessful, resulting in a loss of our investment in such activity. If oil or natural gas is encountered, there can be no assurance that it can be produced in quantities sufficient to justify the cost of continuing such operations or that it can be marketed satisfactorily.

Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all.

 

This report includes certain descriptions of our future drilling plans with respect to our prospects. A prospect is an area which our geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill a prospect depends on the following factors:

 

 

We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all.

 

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying value of our oil and gas properties.

 

We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under such method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices in effect at the time of the calculation are held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings.

 

Forward-Looking Statements

 

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this document, including without limitation, statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct.

 

Forward-looking statements include statements regarding:

 

 

Some of the risks which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include:

 

 

The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could affect our operating results and performance. We urge you to carefully consider these factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made, and we have no obligation to update these forward-looking statements.

 

 

None.

 

 

Location and Characteristics

 

The Company owns oil and natural gas leases in Wyoming and Pennsylvania. The leases in Wyoming are primarily federal leases with 10-year lease terms until establishment of production. Production on a lease extends the lease terms until cessation of that production. The Company owns 39 leases totaling approximately 65,345 gross (36,618 net) acres currently held by production (“HBP”) in Wyoming. The HBP acreage includes all of the Company’s leases held within the productive area of the Pinedale and Jonah fields. The leases in Pennsylvania include both those from private individuals, typically with lease terms of five years until establishment of production and leases from the Commonwealth of Pennsylvania, which have lease term of five years until establishment of production. Production on the Pennsylvania leases extends the lease terms until cessation of that production. The Company owns approximately 839 gross (739 net) acres currently held by production or operations in Pennsylvania.

 

Green River Basin, Wyoming

 

As of December 31, 2008, the Company owned developed oil and natural gas leases totaling 18,916 gross (8,528 net) acres in the Green River Basin of Sublette County, Wyoming which represents 92% of the Company’s total developed net acreage. The Company owns undeveloped oil and natural gas leases totaling 102,516 gross (51,425 net) acres in the Green River Basin of Sublette County, Wyoming which represents 25% of the Company’s total undeveloped net acreage. The Company’s acreage in the Green River Basin primarily covers the Pinedale field

with several other undeveloped acreage blocks north and west of the Pinedale field as well as acreage in the Jonah field. Holding costs of leases in Wyoming not held by production were approximately $0.1 million for the year ended December 31, 2008. The primary target on the Company’s Wyoming acreage is the tight gas sands of the upper Cretaceous Lance Pool formation.

 

Exploratory Wells.  During 2008, the Company participated in the drilling of a total of 108 gross (59.50 net) productive exploratory wells on the Green River Basin properties. At December 31, 2008, there were 50 gross (18.69 net) additional exploratory wells that commenced during the year that were either still drilling or had operations suspended at a depth short of total depth and thus a determination of productive capability could not be made at year end.

 

Development Wells.  During 2008, the Company participated in the drilling of 120 gross (61.98 net) productive development wells on the Green River Basin properties. At year end 2008, there were 29 gross (17.99 net) additional development wells that commenced during 2008 and were either still drilling or had operations suspended at a depth short of total depth. For purposes of this report, development wells are wells identified as proven undeveloped locations by the Company’s independent petroleum engineering firm, Netherland, Sewell & Associates, Inc., at the previous year end reserve evaluation. When drilled, these locations will be counted as development wells.

 

Pennsylvania

 

As of December 31, 2008, the Company owned developed oil and gas leases totaling 839 gross (739 net) acres in the Pennsylvania portion of the Appalachian Basin which represents 8% of the Company’s total developed net acreage. The Company owns undeveloped oil and gas leases totaling 286,906 gross (151,488 net) acres in this area which represents 75% of the Company’s total undeveloped net acreage. Holding costs of leases in Pennsylvania not held by production were approximately $0.2 million for the year ended December 31, 2008.

 

Exploratory Wells.  During the year ended December 31, 2008, the Company participated in the drilling of a total of 18 gross (9.63 net) wells on the Pennsylvania properties. During 2008, the Company began acquisition of a 3D seismic survey covering the Marshlands prospect area. At year end 2008, acquisition was still underway. Processing of this data set is expected in early 2009 with potential inclusion of exploratory well locations in the 2009 drilling program.

Oil and Gas Reserves

 

The following table sets forth the Company’s quantities of domestic proved reserves, for the years ended December 31, 2008, 2007, and 2006 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. The table summarizes the Company’s domestic proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2008, 2007 and 2006. In accordance with Ultra’s three-year planning and budgeting cycle, proved undeveloped reserves included in this table include only economic locations that are forecast to be on production before January 1, 2012. As of December 31, 2008, proved undeveloped reserves represent 57.9% of the Company’s total proved reserves.

 

 

 

 

The following table sets forth the Company’s quantities of proved reserves in China, for the years ended December 31, 2008, 2007 and 2006 as estimated by independent petroleum engineers Ryder Scott Company. In accordance with the Company’s “new field” reserve booking policy, proved reserves were booked after production has commenced. The table summarizes the Company’s proved reserves in China, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2008, 2007 and 2006.

 

 

 

 

The following table sets forth the Company’s quantities of total proved reserves both domestically and in China, for the years-ended December 31, 2008, 2007 and 2006 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. and Ryder Scott Company. The table summarizes the Company’s total proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2008, 2007 and 2006. In accordance with Ultra’s three-year planning and budgeting cycle, proved undeveloped reserves included in this table include only economic locations that are forecast to be on production before January 1, 2012. At December 31, 2008, proved undeveloped reserves represent 57.9% of the Company’s total proved reserves.

 

 

 

 

Since January 1, 2008, no crude oil or natural gas reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

Production Volumes, Average Sales Prices and Average Production Costs

 

The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with the Company’s sale of oil and natural gas for the periods indicated.

 

 

 

 

Productive Wells

 

As of December 31, 2008, the Company’s total gross and net wells were as follows:

 

 

 

 

Oil and Gas Acreage

 

As of December 31, 2008, the Company had total gross and net developed and undeveloped oil and natural gas leasehold acres in the United States as set forth below. The Company’s material undeveloped properties are not subject to a material acreage expiry. The developed acreage is stated on the basis of spacing units designated by state regulatory authorities. The acreage and other additional information concerning the Company’s oil and natural gas operations are presented in the following tables.

 

 

Drilling Activities

 

For each of the three fiscal years ended December 31, 2008, 2007 and 2006, the number of gross and net wells drilled by the Company was as follows:

 

Wyoming — Green River Basin

 

 

At year end, there were 29 gross (17.99 net) additional development wells that were either drilling or had operations suspended. This includes wells in both the Pinedale and Jonah fields.

 

 

At year end there were 50 gross (18.69 net) additional exploratory wells that were either drilling or had operations suspended.

Pennsylvania

 

 

At year end there were 18 gross (9.63 net) exploratory wells that were either drilling or had operations suspended.

 

China — Bohai Bay

 

 

 

 

 

The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

 

 

No matters were submitted to a vote of the Company’s security holders during the fourth quarter of the fiscal year ended December 31, 2008.

 

 

Since August 3, 2007, the Company’s common stock has traded on the New York Stock Exchange (“NYSE”) under the symbol “UPL”. Prior to such time, the Company’s common stock traded on the American Stock Exchange (“AMEX”) under the symbol “UPL”. The following table sets forth the high and low intra-day sales prices of the common stock for the periods indicated.

 

 

 

On February 13, 2009, the last reported sales price of the common stock on the NYSE was $40.17 per share. As of February 13, 2009 there were approximately 413 holders of record of the common stock.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Ultra Petroleum Corp.

 

 

 

 

Copyright ^© 2009 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

 

Copyright ^© 2009 Dow Jones & Co. All rights reserved.

 

The Company has not declared or paid and does not anticipate declaring or paying any dividends on its common stock in the near future. The Company intends to retain its cash flow from operations for the future operation and development of its business.

 

On May 17, 2006, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate $1 billion of the Company’s outstanding common stock which has been and will be funded by cash on hand and the Company’s senior credit facility. Pursuant to this authorization, the Company has commenced a program to purchase up to $750.0 million of the Company’s outstanding shares through open market transactions or privately negotiated transactions.

 

 

The selected consolidated financial information presented below for the years ended December 31, 2008, 2007, 2006, 2005, and 2004 is derived from the Consolidated Financial Statements of the Company. The earnings per share information (basic income per common share and diluted income per common share) have been updated to reflect the 2 for 1 stock split on May 10, 2005.

 

 

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the consolidated financial statements and related notes of the Company. Except as otherwise indicated, all amounts are expressed in U.S. dollars. We have one operating segment, natural gas and oil exploration and development with one geographical segment, the United States.

 

The Company currently generates the majority of its revenue, earnings and cash flow from the production and sales of natural gas and oil from its property in southwest Wyoming. The price of natural gas in the southwest Wyoming region is a critical factor to the Company’s business. The price of natural gas in southwest Wyoming historically has been volatile. The average annual realizations for the period 2003-2008 have ranged from $2.33 to $8.81 per Mcf. This volatility could be detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into forward sales and derivative contracts for natural gas. The average realization for the Company’s natural gas during 2008 was $7.26 per Mcf, including realized gains on commodity derivatives. For the quarter ended December 31, 2008, the average realization for the Company’s natural gas was $5.39 per Mcf, including realized gains on commodity derivatives. The Company’s average price realization for natural gas, excluding realized gains on commodity derivatives, was $7.11 per Mcf and $4.81 per Mcf for the year and quarter ended December 31, 2008, respectively.

 

The Company has grown its natural gas and oil production significantly over the past five years and management believes it has the ability to continue growing production by drilling already identified locations on its leases in Wyoming. The Company delivered 21% production growth on an Mcfe basis during the quarter ended December 31, 2008 as compared to the same quarter in 2007 and 20% production growth (27% from continuing operations) for the year-ended December 31, 2008 compared to the same period in 2007. Management expects to deliver additional production growth during 2009 by drilling and bringing into production additional wells in Wyoming.

 

 

The Company currently conducts operations exclusively in the United States. Substantially all of the oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. Inflation has not had a material impact on the Company’s results of operations and is not expected to have a material impact on the Company’s results of operations in the future.

 

In 2008, we saw significant changes in the business environment in which we operate, including severe economic uncertainty, increasing market volatility and continued tightening of credit markets. The market conditions in 2008 contributed to record high commodity prices during most of the year and nearly unprecedented drops in these commodity prices in the second half of the year.

 

Against this backdrop, we believe that our results of operations show just how successful we have been in improving our business. The highlights in 2008 include record operational and financial results. In 2008, the Company established new production records along with new records in earnings and cash flow while maintaining a low cost structure which contributes to the consistency of the Company’s growth and returns.

 

Outlook

 

In 2008, we experienced challenges associated with changing market conditions, which caused significant volatility in commodity prices and the tightening of the economy. However, we believe we are well positioned to weather the current economic downturn because of our status as a low cost operator in the industry and our financial flexibility.

 

Although we expect that our net cash provided by operating activities may be negatively affected by general economic conditions, we believe that we will continue to generate strong cash flow from operations, which, along with our available cash, will provide sufficient liquidity to allow us to return value to our shareholders. While it is possible that we may not have access to the credit markets on acceptable terms, we expect to rely on our available

cash, our existing credit facility and the cash we generate from our operations to meet our obligations and fund our capital expenditures and operations over the next twelve months. A continued, long-term disruption in the credit markets could make financing more expensive or unavailable, which could have a material adverse effect on our operations.

 

Critical Accounting Policies

 

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates, judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve the most complex or subjective decisions or assessments. These policies relate to estimates of volumes of oil and natural gas reserves used in calculating depletion, the amount of standardized measure used in computing the ceiling test limitations and the amount of abandonment obligations used in such calculations. Assumptions, judgments and estimates are also required in determining impairments of undeveloped properties and the valuation of deferred tax assets.

 

Oil and Gas Reserves.  The term proved reserves is defined by the SEC in Rule 4-10(a) of Regulation S-X under the Securities Act of 1933. In general, proved reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs at the date of the estimate. Prices include consideration of changes in existing prices provided by contractual arrangements, but not escalated based on future economic conditions.

 

Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the Company’s DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also make it uneconomical to drill wells or produce from fields with high operating costs.

 

Our proved reserves are a function of many assumptions, all of which could deviate materially from actual results. As a result, our estimates of proved reserves could vary over time, and could vary from actual results.

 

Full Cost Method of Accounting.  The accounting for and disclosure of oil and gas producing activities requires that we choose between GAAP alternatives. The Company uses the full cost method of accounting for its oil and natural gas operations. Under this method, separate cost centers are maintained for each country in which the Company incurs costs. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties for each full cost center are depleted using the units-of-production method. Changes in estimates of proved reserves, future development costs or asset retirement obligations are accounted for prospectively in our depletion calculation.

 

Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter on a country-by-country basis utilizing prices in effect on the last day of the quarter. SEC regulation S-X Rule 4-10 states that if prices in effect at the end of a quarter are the result of a temporary decline and prices improve prior to the issuance of the financial statements, the increased price may be applied in the computation of the ceiling test. The ceiling limits such pooled costs to the aggregate of the after-tax, present value, discounted at 10%, of future net revenues attributable to proved reserves, known as the standardized measure, plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower DD&A expense in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.

 

The Company did not have any write-downs related to the full cost ceiling limitation in 2008, 2007, or 2006. As of December 31, 2008, the ceiling limitation exceeded the carrying value of the Company’s oil and natural gas properties. Estimates of standardized measure at December 31, 2008 were based on realized natural gas prices which averaged $4.71 per Mcf and on realized liquids prices which averaged $30.10 per barrel in the U.S. A reduction in oil and natural gas prices and/or estimated quantities of oil and natural gas reserves would reduce the ceiling limitation and could result in a ceiling test write-down.

 

Asset Retirement Obligation.  The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties. Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements; the credit-adjusted, risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A.

 

Entitlements Method of Accounting for Oil and Natural Gas Sales.  The Company generally sells natural gas, condensate and crude oil under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.

 

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

 

Valuation of Deferred Tax Assets.  The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis (temporary differences).

To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. As of December 31, 2008, the Company had net deferred tax assets totaling $27.4 million which management considers is more likely than not to be realized.

 

Forward natural gas sales transactions:  The Company primarily relies on fixed price physical delivery contracts, which are considered sales in the normal course of business, to manage its commodity price exposure. The Company, from time to time, also uses derivative instruments as a way to manage its exposure to commodity prices. (See Note 7).

 

Fair Value Measurements.  The Company adopted SFAS No. 157 as of January 1, 2008. The implementation of SFAS No. 157 was applied prospectively for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact on consolidated results of operations, financial position or liquidity. See Note 13 for additional information.

 

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the fair value of the Company’s commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

 

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

 

The fair values summarized below were determined in accordance with the requirements of SFAS No. 157. In addition, we aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by SFAS No. 157. The balance of net unrealized gains and losses recognized for our energy-related derivative instruments at December 31, 2008 is summarized in the following table based on the inputs used to determine fair value:

 

 

 

 

Legal, Environmental and Other Contingencies.  A provision for legal, environmental and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingencies and periodically determines when the Company should record losses for these items based on information available to the Company.

 

Share-Based Payment Arrangements.  The Company follows Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) which requires the measurement and

recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized under SFAS No. 123R for the years ended December 31, 2008, 2007 and 2006 was $5.8 million, $5.7 million and $2.6 million, respectively. See Note 6 for additional information.

 

Financial Statement Restatement.  On October 31, 2008, in connection with the preparation of our quarterly report for the third quarter 2008, management determined that the contemporaneous formal documentation we had prepared in the first quarter of 2008 to support our initial natural gas hedge designations for production sold on REX did not meet the technical requirements to qualify for hedge accounting treatment in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). In order to cause the hedge contracts to qualify for hedge accounting treatment under SFAS No. 133, the Company was required to predict and document the future relationship between prices at REX sales points and the sales prices at the Northwest Pipeline Rockies (the basis of the contracts) at the time the derivative contracts were entered into. The actual relationship between the sales prices at the two locations was different than that predicted by the Company, which affected our ability to effectively demonstrate ongoing effectiveness between the derivative instrument and the forecasted transaction as outlined in our contemporaneous documentation as set forth under the requirements of SFAS No. 133.

 

The Company restated the Consolidated Financial Statements for the periods ended March 31, 2008 and June 30, 2008 to reflect the inability to qualify for hedge accounting treatment on the REX designated derivative contracts. The effect of the restatement was to recognize a non-cash, after tax, mark to market unrealized loss on commodity derivatives of $18.0 million in the first quarter of 2008 and a non-cash, after tax, mark to market unrealized gain on commodity derivatives of $1.6 million in the second quarter of 2008. There is no effect in any period on overall cash flows, total assets, total liabilities or total stockholders’ equity. Because these contracts were entered into and expire in fiscal year 2008, there is no change in full-year 2008 net income or operating cash flows as a result of the accounting treatment of the derivative contracts, as restated. The restatement did not have any impact on any of the financial covenants under the Company’s Senior Credit Facility or Senior Notes due 2015 and 2018.

 

Recently issued accounting pronouncements.  On December 31, 2008, the SEC published a final rule to revise its oil and gas reserves estimation and disclosure requirements. The primary objectives of the revisions are to increase the transparency and information value of reserve disclosures and improve comparability among oil and gas companies. The rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company anticipates that the implementation of the new rule will provide a more meaningful and comprehensive understanding of oil and gas reserves. The Company does not anticipate that the implementation of the new reporting requirements will have a material impact on the consolidated results of operations, financial position or liquidity.

 

In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to increase transparency about the location and amounts of derivative instruments in an entity’s financial statements; how derivative instruments and related hedged items are accounted for under SFAS No. 133; and how derivative instruments and related hedged items affect financial position, financial performance, and cash flows. SFAS No. 161 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2008. The Company does not anticipate that the implementation of SFAS No. 161 will have a material impact on the consolidated results of operations, financial position or liquidity.

 

In February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP SFAS 157-2”). FSP SFAS 157-2 delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all non-financial assets and non-financial liabilities, such as the asset retirement obligation, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). FSP SFAS 157-2 is effective for the Company’s fiscal year beginning January 1, 2009. The adoption of FSP FAS 157-2 is not expected to have a material impact on the Company’s consolidated financial statements.

Results of Operations — Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

 

Oil and natural gas revenues from continuing operations increased 91% to $1.1 billion for the year ended December 31, 2008 from $566.6 million for the same period in 2007. This increase was attributable to an increase in the Company’s production volumes and higher prices received in 2008. During 2008, the Company’s production from continuing operations increased to 138.6 Bcf of natural gas and 1.1 million barrels of condensate up from 2007 levels of 109.2 Bcf of natural gas and 870.1 thousand barrels of condensate. This 27% increase on an Mcfe basis was attributable to the Company’s successful drilling activities in Wyoming during 2008 and 2007. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 56% to $7.26 per Mcf during 2008 as compared to $4.66 for the same period in 2007. During the year ended December 31, 2008, the Company’s average price realization for natural gas was $7.11 per Mcf, excluding gains and losses on commodity derivatives as compared to $4.65 for the same period in 2007. During the year ended December 31, 2008, the average product prices received for condensate were $87.40 per barrel compared to $66.08 per barrel for the same period in 2007.

 

Lease operating expense (“LOE”) increased to $37.0 million for the year ended December 31, 2008 compared to $24.0 million during the same period in 2007 due primarily to increased production volumes as well as increased water disposal costs on non-operated properties in Wyoming. On a unit of production basis, LOE costs increased to $0.25 per Mcfe during the year ended December 31, 2008 as compared to $0.21 per Mcfe during the same period in 2007 mainly due to costs related to non-operated properties for water disposal costs.

 

During the year ended December 31, 2008 production taxes were $119.5 million compared to $63.5 million during the same period in 2007, or $0.82 per Mcfe during the year ended December 31, 2008 as compared to $0.55 per Mcfe during the same period in 2007. The increase in per unit taxes is largely attributable to increased sales revenues as a result of increased production and higher realized gas prices received during the year ended December 31, 2008 as compared to the same period in 2007. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased production taxes on a per unit basis.

 

Gathering fees increased to $37.7 million during 2008 compared to $27.9 million during 2007 largely due to increased production volumes. On a per unit basis, gathering fees increased slightly to $0.26 per Mcfe for the year ended December 31, 2008 compared to $0.24 per Mcfe for the year ended December 31, 2007.

 

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to mitigate volatility and provide for reasonable basis differentials for its natural gas, the Company incurred transportation demand charges totaling $46.3 million, or $0.32 per Mcfe, for the year ended December 31, 2008 in association with the REX Pipeline. The REX Pipeline became operational beginning in the first quarter of 2008.

 

DD&A expenses increased to $184.8 million during the year ended December 31, 2008 from $135.5 million for the same period in 2007, attributable to increased production volumes and a higher depletion rate, due to higher development costs. On a unit basis, DD&A increased to $1.27 per Mcfe for the year ended December 31, 2008 from $1.18 per Mcfe for the same period in 2007.

 

General and administrative expenses increased by 28% to $17.0 million during the year ended December 31, 2008 compared to $13.3 million for the same period in 2007. The increase in general and administrative expenses during 2008 is primarily attributable to increased Medicare taxes as a result of increased employee stock option exercises as well as higher compensation costs related to increased personnel during 2008 as compared to 2007. On a per unit basis, general and administrative expenses remained flat at $0.12 per Mcfe during the years ended December 31, 2008 and 2007.

 

Interest expense increased to $21.3 million during the year ended December 31, 2008 from $17.8 million during the same period in 2007. The increase is related to higher average outstanding debt balances during the year ended December 31, 2008 as compared to the same period in 2007. The increase in debt balances during 2008 is primarily related to the issuance of the Senior Notes on March 6, 2008 (See Note 5) as well as increased share repurchase activity in 2008 as compared to 2007 (See Note 8).

 

During the year ended December 31, 2008, the Company recognized $19.0 million and $14.2 million related to realized gain on commodity derivatives and unrealized gain on commodity derivatives, respectively. These amounts

relate to derivative contracts that the Company entered into during the first quarter of 2008 in order to mitigate commodity price exposure on a portion of the forecasted production which was expected to be sold on REX. Due to limited historical data correlating REX sales points and NWPL — Rockies (the basis of the contracts), the Company was unable to effectively demonstrate correlation between the derivative instrument and the forecasted transaction according to the contemporaneous documentation as set forth under the requirements of SFAS No. 133 causing the derivative contracts to no longer qualify for hedge accounting treatment. The realized gain on commodity derivatives relates to actual amounts received under these derivative contracts while the unrealized gain on commodity derivatives represents the change in the fair value of these derivative instruments.

 

Income before income taxes increased by 129% to $654.4 million for the year ended December 31, 2008 from $285.9 million for the same period in 2007 largely as a result of increased realized natural gas prices and increased production volumes during the year ended December 31, 2008 as compared to 2007.

 

The income tax provision increased 128% to $240.5 million for the year ended December 31, 2008 as compared to $105.6 million for the year ended December 31, 2007 attributable to increased pre-tax income and withholding taxes related to share repurchases (See Note 8).

 

Discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese operations) decreased to $0.4 million for the year ended December 31, 2008 from $82.8 million for the same period in 2007. The decrease is primarily related to the closing of the sale of Sino-American Energy Corporation for net proceeds of $208.0 million, which resulted in a pre-tax gain on sale of properties of $98.1 million during the quarter ended December 31, 2007. (See Note 11).

 

For the year ended December 31, 2008, net income increased by 57% to $414.3 million or $2.65 per diluted share as compared with $263.0 million or $1.66 per diluted share for the same period in 2007 primarily attributable to increased gas prices realized in 2008 as well as increased natural gas production during 2008.

 

Results of Operations — Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

 

Oil and natural gas revenues from continuing operations increased 11% to $566.6 million for the year ended December 31, 2007 from $508.7 million for the same period in 2006. This increase was attributable to an increase in the Company’s production volumes offset in part by lower prices received. During 2007, the Company’s production from continuing operations increased to 109.2 Bcf of natural gas and 870.1 thousand barrels of condensate up from 2006 levels of 78.4 Bcf of natural gas and 594.1 thousand barrels of condensate. This 40% increase on an Mcfe basis was attributable to the Company’s successful drilling activities during 2007 and 2006 in Wyoming. During the year ended December 31, 2007, the average product prices received were $4.66 per Mcf including the effects of hedging and $66.08 per barrel of condensate compared to $6.00 per Mcf including the effects of hedging and $64.52 per barrel of condensate for the same period in 2006.

 

Lease operating expense (“LOE”) increased to $24.0 million for the year ended December 31, 2007 compared to $15.1 million during the same period in 2006 due to increased production volumes as well as increased water disposal costs in Wyoming. On a unit of production basis, LOE costs increased to $0.21 per Mcfe during the year ended December 31, 2007 as compared to $0.18 per Mcfe during the same period in 2006 due to increased water disposal costs in Wyoming. During the year ended December 31, 2007 production taxes were $63.5 million compared to $57.9 million during the same period in 2006, or $0.55 per Mcfe during the year ended December 31, 2007 as compared to $0.71 per Mcfe during the same period in 2006. Production taxes are calculated based on a percentage of revenue from production. Therefore, lower prices received decreased production taxes on a per unit basis. Gathering fees increased to $27.9 million during 2007 compared to $19.7 million during 2006 largely due to increased production volumes. On a per unit basis, gathering fees remained flat at $0.24 per Mcfe for the years ended December 31, 2007 and 2006.

 

DD&A expenses increased to $135.5 million during the year ended December 31, 2007 from $79.7 million for the same period in 2006, attributable to increased production volumes and a higher depletion rate, due to higher development costs. On a unit basis, DD&A increased to $1.18 per Mcfe for the year ended December 31, 2007 from $0.97 per Mcfe for the same period in 2006.

General and administrative expenses decreased by 11% to $13.3 million during the year ended December 31, 2007 compared to $14.9 million for the same period in 2006. On a per unit basis, general and administrative expenses decreased to $0.12 per Mcfe during the year ended December 31, 2007 compared with $0.18 per Mcfe for the same period in 2006. This decrease was primarily attributable to a reduction in year over year compensation expense in combination with higher production volumes.

 

Interest expense increased to $17.8 million during the year ended December 31, 2007 from $3.9 million during the same period in 2006. The increase is related to increased borrowings under the Company’s senior bank facility during 2007.

 

Income before income taxes decreased by 11% to $285.9 million for the year ended December 31, 2007 from $319.4 million for the same period in 2006 largely as a result of reduced realized natural gas prices offset in part by increased production volumes.

 

The income tax provision decreased 14% to $105.6 million for the year ended December 31, 2007 as compared to $122.7 million for the year ended December 31, 2006 attributable to decreased pre-tax income and lower withholding taxes related to share repurchases (See Note 8).

 

Discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese operations) increased to $82.8 million for the year ended December 31, 2007 from $34.5 million for the same period in 2006. The increase is primarily related to the closing of the sale of Sino-American Energy Corporation for net proceeds of $208.0 million, which resulted in a pre-tax gain on sale of properties of $98.1 million during the quarter ended December 31, 2007. (See Note 11).

 

For the year ended December 31, 2007, net income increased by 14% to $263.0 million or $1.66 per diluted share as compared with $231.2 million or $1.43 per diluted share for the same period in 2006.

 

Liquidity and Capital Resources

 

During the year-ended December 31, 2008, the Company relied on cash provided by operations, borrowings under its senior credit facility and proceeds from issuance of the Notes to finance its capital expenditures. The Company participated in the drilling of 307 wells in Wyoming. For the year ended December 31, 2008, net capital expenditures were $949.7 million. At December 31, 2008, the Company reported a cash position of $14.2 million compared to $10.6 million at December 31, 2007. The working capital deficit at December 31, 2008 was $149.4 million as compared to a working capital deficit of $67.5 million at December 31, 2007. As of December 31, 2008, the Company had $570.0 million in outstanding bank indebtedness and other long-term obligations of $46.2 million comprised of items payable in more than one year, primarily related to production taxes.

 

The Company’s positive cash provided by operating activities, along with availability under its senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital expenditures for 2009, which are currently projected to be $720.0 million. Of the $720.0 million budget, the Company plans to allocate approximately 90% to Wyoming and 10% to Pennsylvania. The Company plans to drill or participate in an estimated 200 gross wells in 2009. The Company currently has no budget for acquisitions in 2009.

 

Bank indebtedness:  The Company (through its subsidiary) is a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which matures in April 2012. This agreement provides an initial loan commitment of $500.0 million and may be increased to a maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right, but not the obligation, to increase the amount of its commitment as requested by the Company. In the event the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to add new financial institutions to the credit facility.

 

Loans under the credit facility are unsecured and bear interest, at our option, based on (A) a rate per annum equal to the higher of the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 50 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of our consolidated leverage ratio (87.5 basis points per annum as of December 31, 2008).

 

At December 31, 2008, we had $270.0 million in outstanding borrowings and $230.0 million of available borrowing capacity under our credit facility.

The facility has restrictive covenants that include the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to exceed 31/2 times; and as long as our debt rating is below investment grade, the maintenance of an annual ratio of the net present value of our oil and gas properties to total funded debt of at least 1.75 to 1.00. At December 31, 2008, we were in compliance with all of our debt covenants under our credit facility. The Company’s commitment fees were $0.7 million, $0.4 million and $0.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.

 

Senior Notes, due 2015 and 2018:  On March 6, 2008, our wholly-owned subsidiary, Ultra Resources, Inc. issued $300.0 million Senior Notes (“the Notes”) pursuant to a Master Note Purchase Agreement between the Company and the purchasers of the Notes. The Notes rank pari passu with the Company’s bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million are 5.45% Senior Notes due 2015.

 

Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the borrowings available to us under the revolving credit facility.

 

The Notes are pre-payable in whole or in part at any time. The Notes are subject to representations, warranties, covenants and events of default customary for a senior note financing. If payment default occurs, any Note holder may accelerate its Notes; if a non-payment default occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the Notes. At December 31, 2008, we were in compliance with all of our debt covenants under the Notes.

 

Operating Activities.  During the year ended December 31, 2008, net cash provided by operating activities was $840.8 million, a 96% increase from the $427.9 million for the same period in 2007. The increase in net cash provided by operating activities was largely attributable 56% higher realized natural gas prices during the year ended December 31, 2008 as compared to the same period in 2007 as well as the 27% increase in production from continuing operations during the year ended December 31, 2008.

 

Investing Activities.  During the year ended December 31, 2008, net cash used in investing activities was $915.3 million as compared to $507.1 million for the same period in 2007. The increase in net cash used in investing activities is largely due to increased capital expenditures associated with the Company’s drilling activities in 2008. The year ended December 31, 2007 includes $208.0 million associated with proceeds from the sale of our Bohai Bay assets (See Note 11).

 

Financing Activities During the year ended December 31, 2008, net cash provided by financing activities was $78.0 million as compared to $75.2 million for the same period in 2007. The slight increase in net cash provided by financing activities is primarily attributable to increased borrowings related to the issuance of the Senior Notes offset by increased share repurchase activity during the year ended December 31, 2008 (See Note 8).

 

Off-Balance Sheet Arrangements

 

The Company did not have any off-balance sheet arrangements as of December 31, 2008.

 

Contractual Obligations

 

The following table summarizes our contractual obligations as of December 31, 2008:

 

Transportation contract.  In December 2005, the Company agreed to become an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. The Company’s commitment involves capacity of 200 MMBtu per day of natural gas for a term of 10 years (beginning in the first quarter of 2008), and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. The pipeline is being built in two phases: REX — West (Wyoming to Missouri — in service) and REX — East (Missouri to Ohio — under construction).

 

Drilling contracts.  As of December 31, 2008, the Company had committed to drilling obligations with certain rig contractors that will continue into 2012. The drilling rigs were contracted to fulfill the 2009-2012 drilling program initiatives in Wyoming.

 

Office space lease.  In May 2007, the Company amended its office leases in Englewood, Colorado and Houston, Texas, both of which it has committed through 2012. The Company’s total remaining commitment for office leases is $2.3 million at December 31, 2008 ($0.8 million in 2009, $0.7 million in 2010 and 2011, and $0.1 million in 2012).

 

 

The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable, ranging from $4.24 per Mcf to a monthly high of $8.81 per Mcf during 2008. Pricing volatility is expected to continue. Realized natural gas prices are derived from the financial statements which include the effects of realized hedging gains and losses and natural gas balancing.

 

The Company primarily relies on fixed price forward natural gas sales to manage its commodity price exposure. These fixed price forward natural gas sales are considered normal sales. The Company, from time to time, also uses derivative instruments to manage its exposure to commodity prices. The Company has periodically entered into fixed price to index price swap agreements in order to hedge a portion of its natural gas production. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as reported by such publications as Inside FERC Gas Market Report. Based on management’s current estimates, future production is expected to be sufficient to meet delivery requirements associated with the Company’s derivative contracts and fixed price forward physical delivery contracts.

 

Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the Consolidated Balance Sheets, and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations.

 

On October 31, 2008, in connection with the preparation of our quarterly report for the third quarter 2008, management of Company and the Audit Committee of the Board of Directors determined that the contemporaneous formal documentation we had prepared in the first quarter of 2008 to support our initial natural gas hedge designations for production sold on REX did not meet the technical requirements to qualify for hedge accounting treatment in accordance with SFAS No. 133. In order to cause the hedge contracts to qualify for hedge accounting treatment under SFAS No. 133, the Company was required to predict and document the future relationship between prices at REX sales points and the sales prices at the Northwest Pipeline Rockies (the basis of the contracts) at the time the hedge contracts were entered into. The actual relationship between the sales prices at the two locations was different than that predicted by the Company, which affected our ability to effectively demonstrate ongoing effectiveness between the derivative instrument and the forecasted transaction as outlined in our contemporaneous documentation as set forth under the requirements of SFAS No. 133. While such derivatives no longer qualify for

hedge accounting treatment, the Company believes that these contracts remain a valuable component of our commodity price risk management program.

 

Effective November 3, 2008, the Company changed its method of accounting for natural gas commodity derivatives to reflect unrealized gains and losses on commodity derivative contracts in the income statement rather than on the balance sheet. The Company has historically followed hedge accounting for its natural gas hedges. Under this accounting method, the unrealized gain or loss on qualifying cash flow hedges (calculated on a mark to market basis, net of tax) was recorded on the balance sheet in stockholders’ equity as accumulated other comprehensive income. When an unrealized hedging gain or loss was realized upon contract expiration, it was reclassified into earnings through inclusion in natural gas sales revenues. The Company continues to record the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, but records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Income as gains or losses on commodity derivatives. There is no resulting effect on overall cash flow, total assets, total liabilities or total stockholders’ equity, and there is no impact on any of the financial covenants under the Company’s senior credit facility or senior notes due 2015 and 2018.

 

The Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming delivery points to mitigate its commodity price exposure. The Company had the following fixed price physical delivery contracts in place on behalf of its interest and those of other parties at December 31, 2008. (In November 2007, the Minerals Management Service commenced a Royalty-in-Kind program which had the effect of increasing the Company’s average net interest in physical gas sales from 80% to approximately 91%.)

 

 

At December 31, 2008, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price.

 

 

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Income for the years ended December 31, 2008 and 2007 (refer to Note 1(n) for details of unrealized gains or losses included in accumulated other comprehensive income in the Consolidated Balance Sheets):

 

 

 

 

Subsequent to December 31, 2008 and through February 13, 2009, the Company has entered into the following fixed price physical delivery contracts on behalf of its interest and those of other parties:

 

 

Subsequent to December 31, 2008 and through February 13, 2009, the Company has entered into the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price:

 

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

The management of the Company is responsible for the preparation and integrity of all information contained in this Annual Report. The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. The financial statements include amounts that are management’s best estimates and judgments.

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.

 

The effectiveness of our internal control over financial reporting has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Shareholders of
Ultra Petroleum Corp.

 

We have audited Ultra Petroleum Corp.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Ultra Petroleum Corp.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, Ultra Petroleum Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Ultra Petroleum Corp. as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008 of Ultra Petroleum Corp. and our report dated February 19, 2009 expressed an unqualified opinion thereon.

 

 

Houston, Texas

February 19, 2009

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Shareholders of
Ultra Petroleum Corp.

 

We have audited the accompanying consolidated balance sheets of Ultra Petroleum Corp. as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Ultra Petroleum Corp. at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Ultra Petroleum Corp.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2009 expressed an unqualified opinion thereon.

 

 

Houston, Texas

February 19, 2009

ULTRA PETROLEUM CORP.

 

CONSOLIDATED STATEMENTS OF OPERATIONS