UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

 

 

Commission File Number: 0-29370

Ultra Petroleum Corp.

(Exact Name of Registrant as Specified in Its Charter)

 

 

363 North Sam Houston Parkway East, Suite 1200

Houston, Texas 77060

(Address of Principal Executive Offices) (Zip Code)

 

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):

 

 

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 $8,390,514,190 as of June 29, 2007 (based on the last reported sales price of $55.24 of such stock on the American Stock Exchange on such date).

 

As of February 15, 2008, there were 152,437,606 common shares of the registrant outstanding.

 

Documents incorporated by reference: The definitive Proxy Statement for the 2008 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2007, 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

 

the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations.

 

 

 

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, 2007, Ultra owns interests in approximately 121,652 gross (62,756 net) acres in Wyoming covering approximately 230 square miles. The Company owns an interest in approximately 676 gross producing wells in this area and is operator of approximately 50% of the 676 gross wells. The Company also has an exploration effort underway in Pennsylvania.

 

Following the acquisition of Pendaries Petroleum Ltd. (“Pendaries”) 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 (jointly the “Blocks”) in Bohai Bay, China. During the third quarter of 2007, we made the decision to dispose of Sino-American Energy Corporation (“Sino-American”), 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 represent all of Ultra’s international assets and, previously, were the only results included in our foreign operating segment.

 

On September 26, 2007, Ultra Petroleum Corp.’s wholly-owned subsidiary, UP Energy Corporation, a Nevada corporation, entered into a definitive share purchase agreement with an effective date of June 30, 2007 and a closing date of October 22, 2007, to sell all of the outstanding shares of Sino-American, a Texas corporation, for a total purchase price of US$223.0 million, subject to adjustments. Sino-American held all of Ultra Petroleum Corp.’s interests in oil and gas production sharing contracts in Bohai Bay, China. The purchaser was SPC E&P (China) Pte. Ltd., a wholly-owned subsidiary of Singapore Petroleum Company. See Note 11 for further discussion on the completion of the sale.

 

The Company also owns interests in 252,629 gross (140,100 net) acres in Pennsylvania. The Company drilled one gross (1.0 net) test well on this acreage in 2005. During 2006, this well was brought on production and the Company commenced drilling operations on two gross (1.12 net) additional exploratory wells in the area. At year end 2006, one well remained drilling while the second well was suspended. During 2007, the Company drilled one gross (1.0 net) well on which completion operations were ongoing at December 31, 2007. Subsequent to year end 2007, this well was temporarily abandoned. Ultra continues to evaluate this area to determine plans for future activity.

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

 

In 2008, 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 the majority of the wells drilled during 2008 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, the Pinedale field is approved by the WOGCC for a mix of well densities ranging from one well per 40-acre government quarter section (40-acre equivalent) down to 16 wells per government quarter section (10-acre equivalent). Pilot areas have been approved for testing of well density of 32 wells per government quarter section (5-acre equivalent) with results expected during 2008. In the Jonah field, the current spacing 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). In addition to the ongoing efforts in the Lance Pool section, the Company is continuing to drill a deep test to further evaluate the potential for production from the Rock Springs, Blair and Hilliard Formations which underlie much of the Company’s acreage position in the Pinedale field. 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

 

The Company has drilled three test wells in the Marshlands prospect area to date. During 2008 the Company plans to drill or participate in approximately 12 wells in the Marshlands prospect to test the Devonian, Marcellus Shale formation. Ultra plans to continue to evaluate its acreage holding in the area, acquire additional acreage, seismic and geologic data in the area as needed, and develop an overall strategy to assess the potential of the area and bring that potential to production in a timely and cost effective manner.

 

Bohai Bay, China

 

On October 22, 2007, the Company closed on the sale of Sino-American, which owned our Bohai Bay assets in China, in order to focus on our legacy asset in the Pinedale Field in southwest Wyoming. See Note 11 for further details.

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. 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 cannot predict or control 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 creditworthy financial counterparties. The Company may elect to hedge additional portions of its forecast 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). The Company’s customers are 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. As the Rockies Express Pipeline, LLC (“REX”) becomes operational (as discussed below), the Company’s customer base is expected to expand to include customers in the mid-western and eastern 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. The Company does not have any outstanding, uncollectible accounts for its natural gas sales at December 31, 2007.

 

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 field in southwest Wyoming. Under these agreements, the midstream service providers will expand their facility’s capacities in southwest Wyoming to accommodate growing volumes from wells in which the Company owns an interest. These agreements generally contain multi-year commitments for midstream services. 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 (in both 2005 and 2006), 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 the other, larger, facility is nearing completion and is projected to be completed and fully operational during the first quarter of 2008. The new facilities are expected to add 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. Ultra believes that the capacity of the midstream infrastructure related to the Company’s production will continue to be adequate to allow it to sell essentially all of its available production.

 

Because local natural gas production typically exceeds local demand for natural gas during non-winter months, the Rocky Mountain Region is usually a net-exporter of natural gas. 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”. The Company has seen significant basis differentials for its Wyoming production versus the Henry Hub (“Henry Hub”) pricing reference point in south Louisiana in the past. This trend continued and actually became

more pronounced in 2007. As a result, the Company realized prices that were significantly lower than those received by companies with natural gas production in other regions of the U.S.

 

During portions of the second and third quarters of 2007, the Company realized natural gas prices that were lower than those seen in previous years in the southwest Wyoming region. 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. Continued robust growth in natural gas production from natural gas fields in Wyoming, Colorado and Utah during 2007, coupled with a nearly 100% utilization of existing natural gas pipeline export capacity, caused natural gas prices in the Rocky Mountain Region to decrease dramatically during the second and third quarters of 2007. In addition, a fire and resulting damage at a compressor station on the Colorado Interstate Gas Company pipeline near Cheyenne, Wyoming during the third quarter of 2007 reduced the export capacity of the natural gas pipeline grid in Wyoming, and the impact to the supply/demand balance (and as a result, spot natural gas prices) was immediate and severe. In response to this dramatic change in the supply/demand balance, the Company made voluntary reductions to its gas sales and physically shut-in some volumes during the third quarter of 2007. With the onset of colder weather, and in response to voluntary producer shut-ins of natural gas production by the Company and others, the widening basis differentials for Rockies production became much less pronounced during the last two months of 2007. For example, the differential between prevailing Wyoming prices and the benchmark Henry Hub price ranged from more than $5 per MMBtu discount in October 2007 to a more narrow discount of approximately $1.20 per MMBtu in December 2007.

 

In the 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.

 

The Company continued to take action toward assuring that the pipeline infrastructure to move its natural gas supplies away from southwest Wyoming would be expanded to provide sufficient capacity to transport its natural gas production and to provide for reasonable basis differentials for its natural gas in the future. 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”).

 

On December 19, 2005, the Company entered into two Precedent Agreements (“Precedent Agreements”) with REX and Entrega Gas Pipeline, LLC. The Precedent Agreements govern the parties through the design, regulatory process and construction of the pipeline facilities and, subject to certain conditions precedent, the Company will take firm transportation service, when the pipeline facilities are constructed. Commencing upon completion of the pipeline facilities, the Company’s commitment involves a capacity of 200,000 MMBtu per day of natural gas for a term of 10 years, and the Company will be obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. Based on current assumptions, current projections regarding the cost of the expansion and the participation of other shippers in the expansion, the Company currently projects that annual demand charges due may be approximately $70.0 million per year for the term of the contract, exclusive of fuel and surcharges. The Company’s Board of Directors approved the Precedent Agreements on February 6, 2006 and Kinder Morgan, as the managing member of REX, advised the Company of their final approval of the Precedent Agreements, and their intent to proceed with the construction of the Rockies Express Pipeline on February 28, 2006.

 

The pipeline facilities are currently under construction and are anticipated to be completed in stages between 2008 and 2009. REX filed its application for a Certificate of Public Convenience and Necessity for the Rockies

Express West Project (“REX-West”) with the FERC on May 31, 2006. The REX-West portion of the project is 713 miles of pipeline commencing at Cheyenne Hub (Weld County, CO) and ending in Audrain County, Missouri. The FERC issued a Certificate of Public Convenience and Necessity for REX- West on April 19, 2007 and issued several Notices to Proceed for construction of REX-West in May and June of 2007. Construction on much of the REX-West segment has been completed and interim service commenced on portions of REX-West on January 12, 2008, (from Cheyenne and Opal, Wyoming, as far east as the REX interconnection with ANR pipeline in Brown County, KS.) Interim service provides for the delivery of gas from Opal, Wyoming and other sources to points of interconnection with three significant downstream pipelines on the REX-West segment — (NGPL, ANR, and Northern Natural Gas pipelines). This initiation of interim service for the REX-West segment is within two weeks of the projected “in-service” date estimate provided by Kinder Morgan to the Company when it entered into the aforementioned Precedent Agreements in December 2005, and is a strong indication of the success with which Kinder Morgan has executed its plans for the REX pipeline project to date. The Company has been advised by Kinder Morgan that it expects that the remainder of the REX-West pipeline segment will be completed in March 2008 and that deliveries of REX-West gas into the Panhandle Eastern Pipeline system at Audrain County, Missouri will commence at that time.

 

The Rockies Express East project (“REX-East”) segment is planned to commence at the East terminus of the REX-West segment (at the above mentioned interconnection with Panhandle Eastern Pipeline in Audrain County, Missouri), and traverse eastward across Missouri, Illinois, Indiana, and Ohio to its eastern terminus near Clarington, Ohio. The REX partners have filed an application for a Certificate of Public Convenience and Necessity for the REX-East segment (Missouri to Ohio) and have, in response, received a Draft Environmental Impact Statement (“EIS”) from the FERC, which was issued in November 2007. Following a public comment period on this draft EIS, the FERC has indicated that it expects to issue a Final Certificate of Public Convenience and Necessity during the spring of 2008. Kinder Morgan and the REX partners have indicated that they expect that, assuming the above mentioned FERC REX-East EIS is approved and the Final Certificate is issued as indicated, REX-East construction would commence in late spring 2008. Construction is estimated to be completed on or about January 1, 2009, with the entire REX pipeline being placed into service at that time.

 

There have been and continue to be, numerous other proposed pipeline projects that have been announced to transport growing Rockies and Wyoming natural gas production to a variety of geographically diverse markets in different parts of North America. There are numerous such proposals that have been presented to the Company in recent months, which, if constructed, would provide the Company with additional outlets and market access for its natural gas production from southwest Wyoming. The Company continuously evaluates such proposals and may make additional commitments to one or more such pipeline projects in the future in an effort to cause additional pipeline infrastructure and capacity to be added to the pipeline network.

 

Oil Marketing

 

During a portion of 2007, the Company, through its wholly-owned subsidiary, Sino-American, marketed its share of oil production from the 04/36 and 05/36 Blocks in Bohai Bay, China. On October 22, 2007, the Company completed the sale of Sino-American, which owned our Bohai Bay assets in China, in order to focus on our legacy asset in the Pinedale Field in southwest Wyoming. See Note 11 for further details.

 

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 is based on NYMEX crude futures daily settlement prices, less a negotiated location and transportation discount and is denominated in U.S. dollars per barrel. 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.

 

Environmental Matters

 

In 1998, the U.S. Bureau of Land Management (“BLM”) initiated preparation of an 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. On July 27, 2000, the BLM issued its Record of Decision (“ROD”) with respect to the final EIS, which allows for 700 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 winter drilling and completion activity and, proposes mitigation guidelines, standard practices for industry activities and best management practices for sensitive areas. The ROD also provides for annual reviews to compare actual environmental impacts to the environmental impacts estimated in the EIS and provides for adjustments to mitigate such impacts, if necessary. The review team comprises operators, local residents and other affected persons. 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 2007, Ultra and other operators in the Pinedale field have 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 year-end 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, Ultra received approval within the aforementioned 16 wells per quarter section area to conduct a pilot program on 640 acres to provide for the drilling of 32 wells per quarter section (5-acre density). With these approvals, 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.

 

In April 2004, Questar asked the BLM to modify winter access restrictions to allow operations on three active pads with two drilling rigs per pad during the winter restriction period. This request required an EA to consider the negative impacts of winter activity relative to the extensive mitigation measures proposed by Questar. On November 9, 2004, the BLM issued a “Finding of No Significant Impact” (“FONSI”) which enabled Questar to phase in over the next year the proposed year-round drilling program which allowed two drilling rigs on one pad during the winter of 2004-2005. Questar’s proposed mitigation measures included construction of a water and condensate gathering system during the summer of 2005. Questar’s proposal allows six rigs to operate from three active pads beginning in the winter of 2005-2006 through the winter of 2013-2014 once implementation of the proposed mitigation measures is complete.

 

In early 2005, Ultra, along with Anschutz and Shell (“Proponents”), proposed to the BLM a winter access demonstration project for the Mesa area of the Pinedale field. This area is normally subject to the winter big game stipulation, which prohibits drilling and completion activities in the area from November 15th until April 30th. Under the terms of the proposal, the Proponents were able to operate a total of six rigs, two each on three different winter pads. During this winter demonstration project, the Proponents employed innovative technologies and practices for operations to provide a more beneficial alternative to the current wildlife restrictions. Upon successful completion of the winter demonstration project, the Proponents intend to apply the operations principles demonstrated to implement a long-term development plan that will result in substantially less impact to wildlife, habitat, and local communities than what is allowed under the current Pinedale Anticline Project Area (“PAPA”) ROD while providing assurance of year-round access from the BLM to permit the implementation of a comprehensive development scenario for the Pinedale field. An EA was conducted by the BLM to evaluate the winter demonstration project proposal and associated impacts and the Proponents received approval from the BLM in September 2005, with issuance of a FONSI. The Proponents began activities in the winter demonstration project in November 2005. The FONSI includes several conditions of approval requiring monitoring and mitigation of impacts on wildlife and monitoring and mitigation of rig engine emissions and noise levels associated with project drilling activities.

 

Subsequent to the BLM ruling allowing implementation of the winter demonstration project, the 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 will include assessment of alternative considerations and mitigation requirements that should be considered as alternatives, or in addition, to those included in the proposal. The proposed action includes

commitments to reduce surface disturbance by utilizing fewer overall pads and drilling more directional wells than called for in the PAPA ROD. The operators have agreed also to implement numerous individual mitigation components. These commitments include use of a full-field liquids gathering system and use advanced rig engine emission reduction technology to protect air quality. A mitigation and monitoring fund would be established to address mitigations to minimize impacts from energy development. Ten-year planning and annual meetings with BLM and appropriate state agencies will allow for proper community planning. The draft SEIS was sent out for public comment on December 15, 2006. The closing date for public comment was April 6, 2007. Due to the comments received on the Alternatives in the original draft SEIS, the BLM determined to issue a revised draft SEIS. The revised draft SEIS (“RDSEIS”) was sent out for public comment on December 27, 2007. The closing date for public comment was February 11, 2008, and the final ROD is anticipated in the summer of 2008.

 

In September 2002, the Company received the “Oil and Gas Wildlife Stewardship” award from the Wyoming Game and Fish Department in recognition of its contribution to wildlife management in the Pinedale area. During 2001, the Company received the “Agency/Corporation of the Year” award from the Wyoming Wildlife Federation and the “Regional Administrator’s Award for Environmental Achievement” from the U.S. Environmental Protection Agency.

 

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 is also considering a number of regulatory initiatives that could affect the terms and costs of interstate transportation of natural gas by interstate pipelines on behalf of natural gas shippers, including policy inquiries about natural gas quality and interchangeability, selective discounting of transportation services by pipelines to shippers, and proposed rules governing pipeline creditworthiness and collateral standards. Because these regulatory initiatives have not been made final, the approach the FERC will take and the potential impact on natural gas suppliers remain unclear.

 

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.

 

See “Risk Factors” for a discussion of the risks involved in our international operations.

 

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, and may trigger 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 imputed 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.

 

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, 2007, the Company had 72 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 natural gas or oil sales. In 2007, we had three significant customers for our natural gas production. 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.

 

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.

 

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. 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 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 amount we may borrow under the credit facility may not exceed a borrowing base determined by the lenders based on their projections of our future production, future production costs and taxes, commodity prices and other factors. We cannot control the assumptions the lenders use to calculate the borrowing base. The lenders may, without our consent, adjust the borrowing base at any time. If our borrowings under the credit facility exceed the borrowing base, the lenders may require that we repay the excess borrowing. If this occurred, we may have to sell assets or seek financing from other sources. 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. A portion of our acreage is affected by winter

lease stipulations that prohibit drilling and completing activities from November 15th to April 30th, but allow production activities all year round.

 

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 geo-science 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 640 gross (640 net) acres currently held by production or operations in Pennsylvania.

 

Green River Basin, Wyoming

 

As of December 31, 2007, the Company owned developed oil and natural gas leases totaling 17,399 gross (7,638 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 104,253 gross

(55,118 net) acres in the Green River Basin of Sublette County, Wyoming which represents 28% 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, 2007. The primary target on the Company’s Wyoming acreage is the tight gas sands of the upper Cretaceous Lance Pool formation.

 

Exploratory Wells.  During 2007, the Company participated in the drilling of a total of 79 gross (43.76 net) productive exploratory wells on the Green River Basin properties. At December 31, 2007, there were 36 gross (17.58 net) additional exploratory wells that commenced during the year that were either still drilling or had drilling 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 2007, the Company participated in the drilling of 72 gross (32.35 net) productive development wells on the Green River Basin properties. At year end 2007, there were 25 gross (11.32 net) additional development wells that commenced during 2007 and were either still drilling or had drilling 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, 2007, the Company owned developed oil and gas leases totaling 640 gross (640 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 251,989 gross (139,460 net) acres in this area which represents 72% of the Company’s total undeveloped net acreage. Holding costs of leases in Pennsylvania not held by production were approximately $0.4 million for the year ended December 31, 2007.

 

Exploratory Wells.  During the year ended December 31, 2007, the Company participated in the drilling and completion of a total of two gross (1.12 net) wells in the Marshlands prospect area on the Pennsylvania properties. One of these has been completed and placed on production from the Ordovician shale section. The second well has been plugged back after testing the Silurian Tuscarora formation. This well was being completed in the Devonian Marcellus shale formation at year end 2007. During 2006, the Company acquired a 3D seismic survey covering a large prospect area. Processing of this data set has now been completed and locations are being finalized for potential inclusion in the 2008 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, 2007, 2006, and 2005 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, 2007, 2006 and 2005. 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, 2011. As of December 31, 2007, proved undeveloped reserves represent 61.8% 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, 2007, 2006 and 2005 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, 2007, 2006 and 2005.

 

 

 

 

The following table sets forth the Company’s quantities of total proved reserves both domestically and in China, for the years-ended December 31, 2007, 2006 and 2005 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, 2007, 2006 and 2005. 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, 2011. At December 31, 2007, proved undeveloped reserves represent 61.8% of the Company’s total proved reserves.

 

 

 

 

The Company did not file any reports during the year ended December 31, 2007, with any federal authority or agency with respect to oil and natural gas reserves.

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, 2007, the Company’s total gross and net wells were as follows:

 

 

 

 

Oil and Gas Acreage

 

As of December 31, 2007, 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, 2007, 2006 and 2005, the number of gross and net wells drilled by the Company was as follows:

 

Wyoming — Green River Basin

 

At year end, there were 25 gross (11.32 net) additional development wells that were either drilling or had drilling operations suspended. This includes wells in both the Pinedale and Jonah fields.

 

 

At year end there were 36 gross (17.58 net) additional exploratory wells that were either drilling or had drilling operations suspended.

 

Pennsylvania

 

 

At year end there was 1 gross (1.0 net) exploratory well on which completion operations were ongoing.

 

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, 2007.

 

 

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 15, 2008, the last reported sales price of the common stock on the NYSE was $75.67 per share. As of February 15, 2008 there were approximately 435 holders of record of the common stock.

 

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

 

 

 

Copyright^© 2008, Standard &Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved.
www.researchdatagroup.com/S&P.htm

 

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 $500.0 million of the Company’s outstanding shares through open market transactions or privately negotiated transactions.

 

 

During the year ended December 31, 2007, the Company repurchased 1,431,170 shares of its common stock in open market transactions for an aggregate $78.9 million at a weighted average price of $55.12 per share. Since the program’s inception in May 2006, the Company has purchased a total of 5.4 million shares in open market transactions for an aggregate $276.4 million at a weighted average price of $51.19 per share.

 

In addition to the shares repurchased in open market transactions during the year ended December 31, 2007, the Company also acquired 265,322 shares delivered by employees for $17.4 million to satisfy the exercise price of the employees’ stock options and tax withholding obligations in connection with the exercise of employee stock options issued pursuant to the Company’s employee incentive plans.

 

In total, during the year ended December 31, 2007, the Company repurchased 1,696,492 shares of its common stock for an aggregate $96.3 million dollars at a weighted average price of $56.76 per share. Since the program’s inception in May 2006, the Company has repurchased 5.7 million shares of its common stock for an aggregate $294.5 million at a weighted average price of $51.73 per share.

 

The selected consolidated financial information presented below for the years ended December 31, 2007, 2006, 2005, 2004, and 2003 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 2003-2007 have ranged from $2.33 to $8.64 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 in southwest Wyoming. The average realization for the Company’s natural gas during calendar 2007 was $4.66 per Mcf, basis Opal, Wyoming, including the effect of hedges. For the quarter ended December 31, 2007, the average realization for the Company’s natural gas was $4.42 per Mcf, including the effect of hedges.

 

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 18% production growth on an Mcfe basis during the quarter ended December 31, 2007 as compared to the same quarter in 2006 and 32% production growth for the year-ended December 31, 2007 compared to the same period in 2006. Management expects to deliver additional production growth during 2008 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.

 

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 2007, 2006, or 2005. As of December 31, 2007, the ceiling limitation exceeded the carrying value of the Company’s oil and natural gas properties. Estimates of standardized measure at December 31, 2007 were based on realized natural gas prices which averaged $6.13 per Mcf and on realized liquids prices which averaged $86.91 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, 2007, the Company had net deferred tax assets totaling $24.6 million which management considers is more likely than not to be realized.

 

Commodity Derivative Instruments and Hedging Activities.  The Company may, from time to time, enter into commodity derivative contracts and/or fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company has, in the past, primarily utilized fixed price forward sales of physical gas when it hedges some portion of its Wyoming natural gas production. These transactions are generally placed with major financial institutions or with counterparties of high credit quality that present minimal credit risks to the Company. The Company may also secure payments under these types of transactions by requiring the counterparty to provide letter(s) of credit. The Company may also enter into commodity derivative contracts to manage price volatility. To the extent that it does enter into such derivative transactions, the Company expects that the oil and natural gas reference prices of these commodity derivatives contracts will be based upon crude oil and/or natural gas futures contracts which, when adjusted for location basis differentials, will have a high degree of historical correlation with actual prices the Company receives. Under Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“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 gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (Loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by the related results of the hedged item in the income statement. Gains and losses on hedging instruments included in Accumulated Other Comprehensive Income (Loss) on the balance sheet 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 sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. The Company currently does have several derivative contracts related to the marketing of its natural gas or oil production that are currently in effect.

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.  On January 1, 2006, the Company adopted 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.

 

The Company adopted SFAS No. 123R using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006, the first day of the Company’s fiscal year 2006. Share-based compensation expense recognized under SFAS No. 123R for the years ended December 31, 2007 and 2006 was $2.1 million and $1.2 million, respectively, which consisted of stock-based compensation expense related to employee stock options. See Note 6 for additional information.

 

Recently issued accounting pronouncements.  In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurements. The changes to current practice resulting from the application of this statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements. SFAS No. 157 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company does not anticipate that the implementation of SFAS No. 157 will have a material impact on consolidated results of operations, financial position or liquidity.

 

In June 2006, the FASB issued FIN 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109, Accounting for Income Taxes. FIN 48 requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority.

 

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.

 

Net 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.

 

Results of Operations — Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

 

Oil and natural gas revenues from continuing operations increased 13% to $508.7 million for the year ended December 31, 2006 from $448.7 million for the same period in 2005. This increase was attributable to an increase in the Company’s production volumes partially offset by lower prices received. During 2006, the Company’s production increased to 78.4 Bcf of natural gas and 594.1 thousand barrels of condensate in Wyoming, up from 2005 levels of 61.7 Bcf of natural gas and 464.3 thousand barrels of condensate. This 27% increase on an Mcfe basis was attributable to the Company’s successful drilling activities during 2006 and 2005 in Wyoming. During the year ended December 31, 2006, the average product prices received were $6.00 per Mcf including the effects of hedging and $64.52 per barrel of condensate in Wyoming, compared to $6.84 per Mcf and $57.37 per barrel of condensate in Wyoming for the same period in 2005.

 

LOE increased to $15.1 million in 2006 from $9.0 million in 2005 due to higher production volumes along with increased water disposal costs. On a unit of production basis, LOE costs increased to $0.18 per Mcfe for the year-ended December 31, 2006 as compared to $0.14 per Mcfe during the same period in 2005. Production taxes during the year ended December 31, 2006 were $57.9 million compared to $52.7 million in 2005, or $0.71 per Mcfe in 2006, compared to $0.82 per Mcfe in 2005. Production taxes in Wyoming are calculated based on a percentage of revenue from production. Therefore, lower prices received decreased production taxes on a per unit basis. Gathering fees for the year ended December 31, 2006 increased to $19.7 million in 2006 from $17.1 million in 2005 largely as

a result of increased production volumes partially offset by revised gathering and processing agreements. The per unit gathering fees decreased to $0.24 per Mcfe in 2006 as compared to $0.27 per Mcfe in 2005 as a result of increased production volumes during 2006 as well as reduced fees as a result of revised gathering and processing agreements during 2006.

 

DD&A expenses increased to $79.7 million during the year ended December 31, 2006 from $48.5 million for the same period in 2005. This increase was attributable to increased production volumes and a higher depletion rate due to forecasted increased future development costs. On a unit basis, DD&A expense increased to $0.97 per Mcfe in 2006 from $0.75 per Mcfe in 2005.

 

General and administrative expenses increased slightly to $14.9 million during the twelve months ended December 31, 2006 as compared to $14.3 million during the same period in 2005. On a per unit basis, general and administrative expenses decreased to $0.18 per Mcfe during the year ended December 31, 2006 as compared to $0.22 per Mcfe for the same period in 2005.

 

Interest expense increased to $3.9 million in 2006 from $3.3 million in 2005. This increase was largely attributable to the increase in borrowings under the Company’s senior bank facility during 2006.

 

The income tax provision increased to $122.7 million in 2006 from $107.9 million in 2005. This increase was primarily attributable to increased earnings as well as the withholding tax paid in association with our share repurchase program (see Note 8). The Company recognized $27.6 million in current tax expense during 2006. The Company incurred a liability for current payment of income taxes of $3.6 million for the period ending December 31, 2005. During the year-ended December 31, 2006, the Company incurred $10.4 million in withholding tax attributable to the Company’s share repurchase program. In conjunction with the share repurchase program, a stock distribution to Ultra Petroleum from Ultra Resources is treated as a dividend for U.S. tax purposes to the extent of earnings and profits of UP Energy and Ultra Resources. U.S. tax rules, including rules under the U.S.-Canada Income Tax Treaty, require a 5% withholding tax when a U.S. corporation distributes a dividend to its sole corporate Canadian shareholder.

 

Discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese operations) increased to $34.5 million for the year ended December 31, 2006 from $31.7 million for the same period in 2005. The increase is primarily related increased realized oil prices partially offset by decreased oil production and increased severance taxes, DD&A and income taxes. (See Note 11).

 

Liquidity and Capital Resources

 

During the year-ended December 31, 2007, the Company relied on cash provided by operations, borrowings under its senior credit facility and proceeds from the sale of its Chinese operations to finance its capital expenditures. The Company participated in the drilling of 212 wells in Wyoming. For the year ended December 31, 2007 net capital expenditures were $712.3 million ($697.8 million from continuing operations and $14.5 million from discontinued operations). At December 31, 2007, the Company reported a cash position of $10.6 million compared to $14.6 million at December 31, 2006. Working capital at December 31, 2007 was ($71.5) million as compared to $55.0 million at December 31, 2006. As of December 31, 2007, the Company had $290.0 million in outstanding bank indebtedness and other long-term obligations of $26.7 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 2008, which are currently projected to be $755.0 million. Of the $755.0 million budget, the Company plans to allocate approximately 95% to Wyoming and 5% to Pennsylvania. With the budget allocated for Wyoming, the Company plans to drill or participate in an estimated 240 gross wells in 2008. The Company currently has no budget for acquisitions in 2008.

 

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. At December 31, 2007, the Company had $290.0 million outstanding and $210.0 million unused and available under the current committed amount.

 

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, 2007).

 

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 until such time as we have obtained an investment grade public debt rating, 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, 2007, we were in compliance with all of our debt covenants. The Company’s total commitment fees were $0.4 million, $0.4 million and $0.4 million for the years ended December 31, 2007, 2006 and 2005, respectively.

 

During the year ended December 31, 2007, net cash provided by operating activities was $428.7 million, a 2% decrease from the $436.2 million for the same period in 2006. The decrease in net cash provided by operating activities was largely attributable 22% lower realized natural gas prices during the year ended December 31, 2007 as compared to the same period in 2006 partially offset by the 32% increase in production during the year ended December 31, 2007.

 

During the year ended December 31, 2007, net cash used in investing activities was $508.7 million as compared to $454.8 million for the same period in 2006. The increase in net cash used in investing activities is largely due to increased capital expenditures associated with the Company’s drilling activities in 2007.

 

During the year ended December 31, 2007, net cash provided by financing activities was $76.1 million as compared to net cash used in financing activities of $10.7 million for the same period in 2006. The increase in net cash provided by financing activities is primarily attributable to a reduction in the amount of funds used in the Company’s share repurchase program during 2007 (See Note 8).

 

Off-Balance Sheet Arrangements

 

The Company did not have any off-balance sheet arrangements as of December 31, 2007.

 

Contractual Obligations

 

The following table summarizes our contractual obligations as of December 31, 2007:

 

 

As of December 31, 2007, the Company had committed to drilling obligations with certain rig contractors that will continue into 2012. The drilling rigs were contracted to fulfill the 2007-2012 drilling program initiatives in Wyoming.

 

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 $2.8 million

at December 31, 2007 ($0.6 million in 2008, $0.7 million in 2009, 2010 and 2011, and less than $0.1 million in 2012).

 

On December 19, 2005, the Company signed two Precedent Agreements (“Precedent Agreements”) with Rockies Express Pipeline, LLC (“REX”) and Entrega Gas Pipeline, LLC governing how the parties will proceed through the design, regulatory process and construction of the pipeline facilities and, subject to certain conditions precedent, the Company will take firm transportation service if and when the pipeline facilities are constructed. Commencing upon completion of the pipeline facilities, the Company’s commitment involves capacity of 200,000 MMBtu per day of natural gas for a term of 10 years, and the Company will be obligated to pay to REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. Based on current assumptions, current projections regarding the cost of the expansion and the participation of other shippers in the expansion (noting specifically that these assumptions are likely to change materially), the Company currently projects that annual demand charges due may be approximately $70.0 million per year for the term of the contract, exclusive of fuel and surcharges. The Company’s Board of Directors approved the Precedent Agreements on February 6, 2006 and Kinder Morgan, as the managing member of REX advised the Company of their final approval of the Precedent Agreements, and their intent to proceed with the construction of the Rockies Express Pipeline on February 28, 2006.

 

The pipeline facilities are currently under construction and are anticipated to be completed in stages between 2008 and 2009. REX filed its application for a Certificate of Public Convenience and Necessity for the Rockies Express West Project (“REX-West”) with the FERC on May 31, 2006. The REX-West portion of the project is 713 miles of pipeline commencing at Cheyenne Hub (Weld County, CO) and ending in Audrain County, Missouri. The FERC issued a Certificate of Public Convenience and Necessity for REX- West on April 19, 2007 and issued several Notices to Proceed for construction of REX-West in May and June of 2007. Construction on much of the REX-West segment has been completed and Interim Service commenced on portions of REX-West on January 12, 2008, (from Cheyenne and Opal, Wyoming, as far east as the REX interconnection with ANR pipeline in Brown County, KS.) Interim service provides for the delivery of gas from Opal, Wyoming and other sources to points of interconnection with three significant downstream pipelines on the REX-West segment — (NGPL, ANR, and Northern Natural Gas pipelines). This initiation of interim service for the REX-West segment is within two weeks of the projected “in-service” date estimate provided by Kinder Morgan to the Company when it entered into the aforementioned Precedent Agreements in December 2005, and is a strong indication of the success with which Kinder Morgan has executed its plans for the REX pipeline project to date. The Company has been advised by Kinder Morgan that it expects that the remainder of the REX-West pipeline segment will be completed in March 2008 and that deliveries of REX-West gas into the Panhandle Eastern Pipeline system at Audrain County, Missouri will commence at that time.

 

The Rockies Express East project (“REX-East”) segment is planned to commence at the East terminus of the REX-West segment (at the above mentioned interconnection with Panhandle Eastern Pipeline in Audrain County, Missouri), and traverse eastward across Missouri, Illinois, Indiana, and Ohio to its eastern terminus near Clarington, Ohio. The REX partners have filed an application for a Certificate of Public Convenience and Necessity for the REX-East segment (Missouri to Ohio) and have, in response, received a Draft Environmental Impact Statement from the FERC, which was issued in November 2007. Following a public comment period on this draft EIS, the FERC has indicated that it expects to issue a Final Certificate of Public Convenience and Necessity during the spring of 2008. Kinder Morgan and the REX partners have indicated that they expect that, assuming the above mentioned FERC REX-East EIS is approved and the Final Certificate is issued as indicated, REX-East construction would commence in late spring 2008. Construction is estimated to be completed on or about January 1, 2009, with the entire REX pipeline being placed into service at that time.

 

Additionally, in maintaining its acreage base that is not held by production, the Company incurs certain expenses, including delay rental costs. From year to year, the Company’s acreage base varies, sometimes dramatically, rendering it impossible to forecast with any accuracy what the amount of these delay rental costs will be. In 2007, delay rental costs for all of the Company’s leases not held by production were approximately $0.4 million.

 

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. Pricing volatility is expected to continue. Natural gas price realizations ranged from a monthly low of $3.18 per Mcf to a monthly high of $6.85 per Mcf during 2007. Realized natural gas prices are derived from the financial statements which include the effects of hedging and natural gas balancing.

 

The Company primarily relies on fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales. The Company may, from time to time and to a lesser extent, use derivative instruments as one way 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 production. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures as listed on the NYMEX, which have a high degree of historical correlation with actual prices the Company receives. 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 gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. At December 31, 2007, all hedges were considered effective as the hedging instruments offset the change in the hedged transaction’s cash flows for the risk being hedged. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. 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 sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. The Company currently does not have any derivative contracts in place that do not qualify as cash flow hedges.

 

During 2007, the Company recognized income, which is included in natural gas sales on the income statement, associated with financially settled swaps to counterparties totaling $1.1 million as its net realization from the hedging activities.

 

The Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming delivery points to hedge 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, 2007. (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, 2007, 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 (all prices NWPL Rockies basis).

 

 

 

 

Subsequent to December 31, 2007 and through February 20, 2008, 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, 2007 and through February 20, 2008, 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 (all prices NWPL Rockies basis):

 

 

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, 2007.

 

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.

 

Michael D. Watford

Chief Executive Officer

 

February 22, 2008

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, 2007, 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, 2007, 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, 2007 and 2006, and the related consolidated statements of operations and retained earnings, shareholders’ equity, and cash flow for each of the two years in the period ended December 31, 2007 of Ultra Petroleum Corp. and our report dated February 22, 2008 expressed an unqualified opinion thereon.

 

 

Houston, Texas

February 22, 2008

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Shareholders

Ultra Petroleum Corp.:

 

We have audited the accompanying consolidated statements of operations and retained earnings, shareholders’ equity, and cash flow of Ultra Petroleum Corp. and subsidiaries for the year ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our 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 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and the cash flows of Ultra Petroleum Corp. and subsidiaries for the year ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

 

 

Denver, Colorado

March 30, 2006

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Shareholder of

Ultra Petroleum Corp.

 

We have audited the accompanying consolidated balance sheets of Ultra Petroleum Corp. as of December 31, 2007 and 2006, and the related consolidated statement of operations and retained earnings, shareholders’ equity, and cash flow for each of the two years in the period ended December 31, 2007. 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, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

 

As discussed in Notes 1 and 6 to the consolidated financial statements, Ultra Petroleum Corp. changed its method of accounting for Share-Based Payments in accordance with Statement of Financial Accounting Standards No. 123 (revised 2004) on January 1, 2006. In addition, as discussed in Note 9 to the consolidated financial statements, in 2007 the Company changed its method of accounting for income taxes.

 

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, 2007, 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 22, 2008 expressed an unqualified opinion thereon.

 

 

Houston, Texas

February 22, 2008

ULTRA PETROLEUM CORP.

 

CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS

 

 

See accompanying notes to consolidated financial statements.

 

Approved on behalf of the Board: