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

 

 

Form 10-K

 

 

 

Commission file number 001-33614

 

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

 

 

(Registrant’s telephone number, including area code)
(281) 876-0120
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 requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  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 $5,906,164,446 as of June 30, 2009 (based on the last reported sales price of $39.00 of such stock on the New York Stock Exchange on such date).

 

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of February 17, 2010 was 152,068,210.

 

Documents incorporated by reference: The definitive Proxy Statement for the 2010 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2009, 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:

 

Economically producible — A resource that generates revenue that exceeds (or is reasonably expected to exceed) costs of the operation.

 

Estimated ultimate recovery (“EUR”) — The sum of reserves remaining as of a given date and cumulative production as of that date.

 

Proved oil and gas reserves —  Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs and under existing economic conditions, operating methods, and government regulation — before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

 

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

The area of the reservoir considered as proved includes all of the following:

 

a. The area identified by drilling and limited fluid contacts, if any,

 

b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

 

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

 

a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.

 

b. The project has been approved for development by all necessary parties and entities, including governmental entities.

 

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved developed oil and gas reserves — Proved oil and gas reserves that can be expected to be recovered:

 

a. Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.

 

b. Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Proved undeveloped oil and gas reserves — Proved oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

 

Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

Reasonable certainty — If deterministic methods are used, a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

Reliable technology — A grouping of one or more technologies (including computational methods) that has been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

 

Resources — Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

 

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

 

 

Terms used to describe seismic operations

 

 

 

 

General

 

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 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 located in the Green River Basin of southwest Wyoming and in the north-central Pennsylvania area of the Appalachian Basin.

 

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 the Company. The SEC’s website address is www.sec.gov.

 

Oil and Gas Properties Overview

 

Ultra’s current operations in southwest Wyoming are focused on developing the Company’s position in a tight gas sand trend located in the Green River Basin with targets in 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. As of December 31, 2009, Ultra owned interests in approximately 112,000 gross (56,000 net) acres in Wyoming covering approximately 190 square miles.

 

Ultra’s current operations in north-central Pennsylvania are focused on exploring, developing and expanding its position in the Marcellus Shale and deeper horizons. At December 31, 2009, the Company owned interests in approximately 326,000 gross (169,000 net) acres in Pennsylvania.

 

Business Strategy

 

Ultra’s mission is to profitably grow an upstream oil and gas company for the long-term benefit of its shareholders. Ultra’s strategy includes building a robust portfolio of high return investment opportunities, maintaining a disciplined approach to capital investment, maximizing earnings and cash flows by controlling costs and maintaining financial flexibility.

 

High Return Portfolio.  Ultra maintains a portfolio of properties that provide long-term growth through development in areas that support sustainable, lower-risk, repeatable, high return drilling projects. The Company continually evaluates opportunities for the acquisition, exploration and development of additional oil and natural gas properties that afford risk-adjusted returns in excess of or equal to its current set of investment alternatives.

 

Disciplined Capital Investment.  The Company’s business strategy involves the regular review of its investment opportunities in order to optimize return to its shareholders. Over the past ten years, Ultra has consistently delivered meaningful reserve and production growth while providing significant returns to its shareholders. In 2009, oil and natural gas production increased 24% over 2008 levels and estimated proved reserves increased 11% to 3.9 Tcfe from 3.5 Tcfe with return on capital employed of 18% and return on equity of 32%.

Low Cost Producer.  Ultra strives to maintain one of the lowest cost structures in the industry in terms of both adding and producing oil and natural gas reserves. The Company continues to focus on improving its drilling and production results through the use of advanced technologies and detailed technical analysis of its properties.

 

Financial Flexibility.  Preserving financial flexibility and a strong balance sheet are also strategic to Ultra’s business philosophy. At December 31, 2009, the Company had cash on hand of $14.3 million and outstanding debt was $795.0 million. Consistent with this strategy and subsequent to year-end 2009, the Company issued $500.0 million of senior notes at an average interest rate of 5.46% and a weighted average term of 10.6 years. As a result of the issuance, the availability under the Company’s revolving credit facility increased to approximately $335.0 million and the debt maturity profile lengthened to over eight years due to adding tranches of 12 and 15 year debt while the Company’s weighted average cost of debt remains at approximately 5.5%.

 

Green River Basin, Wyoming

 

During 2009, the Company participated in the drilling of 222 wells in Wyoming and continued to improve its drilling and completion efficiency on its operated wells as measured by spud to total depth. During 2009, the average drilling days decreased 17% from 2008 levels to 20 days from spud to total depth. In addition, the Company’s average well cost decreased from $5.5 million per well during 2008 to $5.0 million during 2009, increasing both the present value and rate of return on these wells. This 9% reduction in costs is a direct result of fewer drilling days, fewer rig moves associated with pad drilling and lower cost of services. These cost reductions were accomplished while simultaneously drilling deeper wells and completing more frac stages per well.

 

During 2010, the Company plans to continue its ongoing development program of its acreage position in the tight gas sand trend in the Green River Basin in southwest Wyoming. The Company expects that wells drilled during 2010 will target the sands of the upper Cretaceous Lance Pool in the Pinedale and Jonah fields.

 

Additionally, the Company plans to continue its assessment of increased density drilling to more efficiently recover the vast resources present in the area. Currently, essentially all of the Pinedale field is approved by the WOGCC for 16 wells per 160-acre government quarter section (10-acre equivalent). Pilot activities are planned to continue in 2010 in areas approved for testing of well density of 32 wells per 160-acre government quarter section (5-acre equivalent). Current spacing in the Jonah field is eight wells per 80-acre drilling and spacing unit (10-acre spacing) with several pilots testing spacing at 16 wells per 80-acre drilling and spacing unit (5-acre spacing).

 

All of the Company’s drilling activity is conducted utilizing its extensive integrated geological and geophysical data set. This data set is being utilized to map the potentially productive intervals, to identify areas for future extension of the Lance fairway and to identify deeper objectives which may warrant drilling.

 

Pennsylvania

 

During 2009, the Company participated in the drilling of 35 horizontal Marcellus wells and two vertical Oriskany wells. The Company also completed a 3-D seismic survey in the Marshlands area. The Company is actively leveraging its Pinedale experience by translating its Wyoming directional drilling, completion and production knowledge to the Marcellus.

 

During 2010, the Company plans to expand its exploration and development activities in the Middle Devonian Marcellus Shale play on its acreage position in Pennsylvania. Ultra’s current activities are located in Potter, Tioga, Bradford and Lycoming counties. Activities include lease acquisition, 3-D seismic, drilling, completion, infrastructure construction and production operations. The Company’s activities are focused in the north-central counties of Pennsylvania where the Company believes favorable Marcellus Shale properties exist for economic development.

 

In December 2009, the Company signed a purchase and sale agreement to acquire additional acreage in the Pennsylvania Marcellus Shale (the deep rights), strategically increasing the scale of its Marcellus position. The transaction closed on February 22, 2010 with an effective date of October 1, 2009. At the closing, the Company acquired 78,221 net acres in the deep rights, for a purchase price of $333.0 million, subject to post closing adjustments. The Company may acquire additional interests in these net acres at subsequent closings if the Sellers

cure title defects as provided in the purchase agreement. (See Note 14 to the Company’s Consolidated Financial Statements included in this report).

 

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. A small, but increasing portion of the Company’s revenues is associated with gas sales from wells located in the Appalachian Basin in Pennsylvania. Historically, the Company’s revenues have been determined, to a large degree, by prevailing natural gas prices for production situated in the Rocky Mountain region of the United States, specifically, southwest Wyoming. With the completion of the Rockies Express Pipeline, LLC (“REX”) during 2009, a substantial portion of the Company’s revenues are now determined by natural gas market prices in the Midwestern and Eastern regions of the United States. Energy commodity prices in general, and the Company’s regional prices in particular, have been highly volatile, and such high levels of volatility are expected to continue in the future.

 

Supplies of natural gas in the U.S. grew rapidly during 2008 in response to higher natural gas prices and higher levels of drilling activity. Natural gas prices peaked in mid-2008 and then declined dramatically, while simultaneously, the world economy fell into recession. These coincident events materially reduced gas demand and resulted in an imbalance between natural gas supply and demand. This supply/demand imbalance persisted throughout 2009, resulting in reductions in drilling activity directed toward natural gas and in materially lower gas prices. Furthermore, this imbalance caused record high levels of natural gas in storage in the U.S. and Canada at the beginning of the traditional storage withdrawal season (November 1st). Mild weather in November 2009 lead to a delay in the commencement of storage withdrawals and resulted in further surpluses in gas storage inventory levels relative to historical averages. Since the end of November 2009, temperatures in the U.S. and in other parts of the world have generally been colder than normal, and storage levels have been drawn down to levels more consistent with historical averages.

 

The Company, from time to time, in the regular course of its business, hedges a portion of its natural gas production primarily through the use of financial swaps with creditworthy financial counterparties, or through the use of fixed price, forward sales of physical gas. The Company may elect to hedge additional portions of its forecasted natural gas production in the future, in much the same manner as it has done previously. 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. For a more detailed description of the Company’s hedging activities, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

In response to the lower price environment that began to emerge in mid-to-late 2008, the Company began to more aggressively hedge its exposure to lower natural gas prices by entering into forward sales for 2009 through 2011. This strategy of hedging resulted in greater price certainty for the Company’s production and helped protect the Company’s 2009 capital investment program. During the first quarter of 2009, the Company elected to convert its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This conversion allowed the Company to retain a higher level of discretion to shut-in physical natural gas sales in response to lower prices while still receiving the benefits of its hedges with prices that were higher than market.

 

Natural Gas Marketing

 

Ultra currently sells all of its natural gas production to a diverse group of third-party, non-affiliated entities in a portfolio of transactions of various durations and prices (daily, monthly and longer term). Historically, the Company’s customers were predominately located in the western United States — primarily California and the Pacific Northwest, as well as the Front Range area of Colorado and in Utah. With the REX pipeline operational into Ohio and with the addition of new gas production in Pennsylvania, the Company’s customer base has expanded to include a significant number of new customers situated in the Midwestern and Eastern regions of the United States.

 

The sale of the Company’s natural gas is “as produced”. As such, the Company does not maintain any significant inventories or imbalances of natural gas. The Company maintains credit policies intended to mitigate the

risk of uncollectible accounts receivable related to its sale of natural gas. The Company did not have any outstanding, uncollectible accounts for its natural gas sales at December 31, 2009.

 

Midstream services.  For its natural gas production in Wyoming, the Company has entered into various gathering and processing agreements with several midstream service providers that gather, compress and process natural gas owned or controlled by the Company from its producing wells in the Pinedale Anticline and Jonah fields in southwest Wyoming. Under these agreements, the midstream service providers have routinely expanded their facility’s capacity in southwest Wyoming to accommodate growing volumes from wells in which the Company owns an interest. The Company believes that the capacity of the midstream infrastructure related to its production will continue to be adequate to allow it to sell essentially all of its available natural gas production from Wyoming.

 

In Pennsylvania, the Company and its partners are constructing gas gathering pipelines and facilities, compression facilities and pipeline delivery stations to gather production from its newly completed natural gas wells. Construction on these facilities will continue throughout 2010 allowing the Company to manage its midstream capacity to coincide with increased capacity requirements from its drilling activities. To date, none of the Company’s natural gas production in Pennsylvania has required processing, treating or blending in order to remove natural gas liquids or other impurities and it is anticipated that facilities of this type will not be required in the future to accommodate the Company’s production.

 

Pipeline infrastructure.  The Company has previously taken and continues to take action to expand the pipeline infrastructure available to move its natural gas supplies away from southwest Wyoming to provide sufficient capacity to transport its natural gas production and to provide for reasonable prices 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. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. The Company’s commitment involves capacity of 200 MMMBtu per day of natural gas for a term of 10 years commencing with initial transportation in January 2008. The Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. The REX pipeline was built in multiple phases: REX West (Wyoming to Missouri — in service in 2008) and REX East (Missouri to Clarington, Ohio — in service in November 2009), with an expanded capacity of 1.8 Bcf per day. During the first quarter of 2009, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. This additional capacity will provide the Company with the ability to move additional volumes from its producing wells in Wyoming to markets in the eastern U.S.

 

Two additional new pipeline projects originating in Wyoming and designed to transport natural gas to markets not currently accessible to Wyoming producers have been announced and are in final stages of pre-construction sanctioning and approvals. The Ruby Pipeline, sponsored by El Paso Corporation, and the Bison Pipeline, sponsored by TransCanada Pipeline Corp., have received final EIS approvals from the FERC and are expected to begin construction in 2010. These two pipelines, when completed, will add aggregate export pipeline capacity for Rockies\Wyoming gas of approximately 1.7 Bcf per day, a 20% increase over current levels.

 

Basis differentials.  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. These factors include, among others, weather, natural gas supplies, natural gas demand, and natural gas pipeline capacity to export gas from the Rockies. The Rocky Mountain region is typically a net exporter of natural gas because local natural gas production typically exceeds local demand during non-winter months. As a result, natural gas production in southwest Wyoming has historically sold at a discount relative to other U.S. natural gas production sources or market areas. These regional pricing differentials, or discounts, are typically referred to as “basis” or “basis differentials” and are reflective, to some extent, of the costs associated with transporting the Company’s gas to markets in other regions or states. They are also reflective of the general relative abundance of, or lack of, export pipeline capacity to move gas out of the Rockies. NW Rockies basis was generally wide since 2006 but improved during the latter portion of 2009 and is anticipated to remain favorable in 2010 through 2012 mainly as a result of the completion of the REX pipeline into Ohio, as discussed above (See Pipeline Infrastructure).

The table below provides a historical and future perspective on average annual basis differentials for Wyoming natural gas (NW Rockies) and premium markets in the Northeast (Dominion South). The basis differential is expressed as a percentage of the Henry Hub price as reported by Platt’s on December 31, 2009.

 

 

Oil Marketing

 

The Company markets its Wyoming condensate to various purchasers. The pricing of the Company’s condensate production varied significantly during 2009 and is based on New York Mercantile Exchange crude futures daily settlement prices, less a negotiated location and transportation discount or differential. All of the Company’s condensate sales are denominated in U.S. dollars per barrel and are paid for on a monthly basis. The Company routinely maintains only operating inventories of condensate production and sells its product on an “as produced” basis.

 

Historically, the Company’s condensate production was gathered from its Wyoming well locations by tanker trucks and then shipped to other locations for injection into crude oil pipelines or other facilities. During 2009, the Company initiated service on the first two (of four proposed) central gathering facilities. These facilities are part of the Company’s liquids gathering system designed to gather condensate and water from various leases and wells operated by the Company as contemplated under the Supplemental Environment Impact Statement (“SEIS”) Record of Decision (“ROD”) as discussed below in Environmental Matters. The condensate and water are transported to central points in the field where condensate can be loaded into trucks or delivered into pipelines.

 

Significant Counterparties

 

In 2009, the Company had three significant counterparties associated with sales of its natural gas production and commodity derivatives contracts. Sales and settlements of derivative contracts to Sempra Energy Trading Corp., J Aron & Company and JP Morgan Chase Bank, N.A. were $144.9 million, $101.3 million, and $97.1 million, respectively, which accounted for 16.2%, 11.3% and 10.8% of the Company’s total 2009 revenues (including realized gains on commodity derivatives), respectively. At December 31, 2009, the Company had outstanding receivables (which were received in full in January 2010) from Sempra Energy Trading Corp., J Aron & Company and JP Morgan Chase Bank, N.A. totaling $19.7 million.

 

Environmental Matters

 

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

 

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

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

 

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

 

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

 

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

 

Ultra, Shell and Questar (“Proponents”) submitted a development proposal for the Pinedale field which includes broad application of operations principles being evaluated in the demonstration project area. The Proponents entered into a memorandum of understanding with the BLM to commence the preparation of a SEIS

for year-round access in the Pinedale field. The SEIS process included assessment of alternative considerations and mitigation requirements that were considered as alternatives, or in addition, to those included in the proposal. The proposal included commitments to reduce surface disturbance by utilizing fewer overall pads and drilling more directional wells than called for in the 2000 Pinedale Anticline Project Area (“PAPA”) ROD.

 

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

 

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

 

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

 

In July 2009, Ultra, along with Shell and Questar, were awarded the BLM’s 2009 Environmental Best Management Practices Award for Responsible Stewardship of Air Resources in the PAPA.

 

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, including regulations governing environmental quality and pollution control and 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, which can affect our operations.

 

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 9, 2000, the FERC issued a final rule concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for services. The final rule revises the FERC’s pricing policy and current regulatory framework to improve the

efficiency of the market and further enhance competition in natural gas markets. The FERC has also issued several other generally pro-competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, the FERC generally reaffirmed its policy allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, the FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline-by-pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, the FERC established criteria to allow providers to charge market-based (i.e. negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short-term releases by shippers of interstate pipeline transportation capacity.

 

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

 

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

 

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

 

Environmental Regulations

 

General.  The Company’s exploration, drilling and production activities from wells and natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products are subject to stringent federal, state and local laws and regulations relating to 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 them 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 or 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, including proposed amendments to the federal Safe Drinking Water Act (“SDWA”) related to hydraulic fracturing operations, it is possible the Company could be required to remediate property, including ground water, containing or impacted by operations by the Company or by such third party operators, or 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”) under the federal Resource Conservation and Recovery Act (“RCRA”) and some 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 are 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.  Under 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 releases and threats of releases to protect 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.  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 environmental impact statement (EIS). In the EIS, the agency is required to evaluate alternatives to the proposed action and the environmental impacts of the proposed action and of such alternatives. Actions of the Company, such as drilling on federal lands, to the extent the drilling requires federal approval, may trigger the requirements of the National Environmental Policy Act, including the requirement that an EIS be prepared. The requirements of the National Environmental Policy Act may result in increased costs, significant delays and the imposition of restrictions or obligations on the Company’s activities, including but not limited to the restricting or prohibiting of drilling.

 

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. OPA assigns liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and for 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, the 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 agencies can bring actions for failure to comply with air pollution regulations or permits and generally enforce compliance through administrative, civil or criminal enforcement actions, which may result in fines, injunctive relief and imprisonment.

Clean Water Act.  The Clean Water Act (“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.

 

Application of Safe Drinking Water Act to Fracturing.  The Safe Drinking Water Act (“SDWA”) regulates, among other things, underground injection operations. Recent legislative activity has occurred which, if successful, would impose additional regulation under the SDWA upon the use of hydraulic fracturing fluids. The U.S. Senate and House of Representatives are considering two companion bills entitled the “Fracturing Responsibility and Chemical Awareness Act of 2009.” If enacted, the legislation would impose on our hydraulic fracturing operations permit and financial assurance requirements, requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. Neither piece of legislation has been passed. If this or similar legislation is enacted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

 

Endangered Species Act.  The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The Company conducts operations on federal and other oil and natural gas leases that have species, such as raptors, that are listed and species, such as sage grouse, that 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 or the mere presence of threatened or endangered species 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 the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

 

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

 

Climate Change Legislation.  Laws and regulations relating to climate change and greenhouse gases (“GHGs”), including methane and carbon dioxide, may be adopted and could cause the Company to incur material expenses in complying with them. The U.S. House of Representatives passed and the U.S. Senate is considering climate change-related legislation to regulate GHG emissions that could affect the Company’s operations and its regulatory costs, as well as the value of oil and natural gas generally. Independent of that legislation, the EPA is moving forward with climate change-related regulatory initiatives, having found GHGs may reasonably be anticipated to endanger human health and the environment. These regulatory initiatives could also affect our operations and costs. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These or other potential federal and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in the Company incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from its operations. These regulatory initiatives also could adversely affect the marketability of the

oil and natural gas the Company produces. Ultra’s current activities are not applicable as a “covered entity” in respect to climate change legislation because its activities do not exceed 25,000 tons of carbon dioxide equivalent.

 

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, 2009, the Company had 94 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 and future operating costs 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.

 

The present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. In accordance with SEC requirements, we base the present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves on the average oil and natural gas prices during the 12-month period before the ending date of the period covered by this report determined as an unweighted, arithmetic average of the first-day-of the-month price for each month within such period, adjusted for quality and transportation. The costs to produce the reserves remain constant at the costs prevailing on the date of the estimate.

Actual current and future prices and costs may be materially higher or lower. In addition, the 10% discount factor, which the SEC requires us to use in calculating our discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on our cost of capital from time to time and/or the risks associated with our business.

 

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

 

We compete with numerous other companies in virtually all facets of our business. Our 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 of the Company permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. 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.

 

Our derivative transactions may limit our gains and expose us to other risks.

 

We enter into transactions with derivative instruments from time to time to manage our exposure to commodity price risks. These transactions limit our potential gains if commodity prices rise above the levels established by our derivative instruments. These transactions may also expose us to other risks of financial losses, for example, if our

production is less than we anticipated at the time we entered into a derivative instrument or if a counterparty to our derivative instrument fails to perform the contracts.

 

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

 

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.

 

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

 

The unprecedented disruption in the U.S. and international credit markets in 2008 resulted in a rapid deterioration in the worldwide economy and tightening of the financial markets. The outlook for the economy in 2010 is uncertain. The current global credit and economic environment has reduced worldwide demand for energy and resulted in significantly lower natural gas prices than in earlier periods. A sustained reduction in the prices we receive for our natural gas production could have a material adverse effect on our results of operations. In addition, any worsening of conditions in the credit and equity markets could increase our financing costs and limit our financial flexibility. Any worsening of domestic and global economic conditions could adversely affect our business and results of operations.

 

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

 

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

 

 

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

could be caused by 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 operations are conducted on federal and state lands. These operations are subject to a wide variety of regulations as well as other permits and authorizations which must be obtained from and issued by state and federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Complying with any of these requirements may adversely affect our ability to complete our drilling programs at the costs and in the time periods anticipated.

 

Climate Change Legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and gas we produce.

 

On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (“ACESA”), which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

 

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

 

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

The U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal SDWA to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells and increase our costs of compliance and doing business.

 

The adoption of derivatives legislation or regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

 

Legislation has been proposed in Congress and by the Treasury Department to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Under proposed legislation, OTC derivative dealers and other major OTC derivative market participants could be subjected to substantial supervision and regulation. The legislation generally would expand the power of the Commodity Futures Trading Commission (“CFTC”), to regulate derivative transactions related to energy commodities, including oil and natural gas, to mandate clearance of derivative contracts through registered derivative clearing organizations, and to impose conservative capital and margin requirements and strong business conduct standards on OTC derivative transactions. The CFTC has proposed regulations that would implement speculative limits on trading and positions in certain commodities. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or the CFTC may issue new regulations, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

 

We may not be able to obtain funding on acceptable terms or at all.

 

Global financial markets and economic conditions have been disrupted and volatile due to a variety of factors. As a result, the cost of raising money in the debt and equity capital markets and the availability of funds from those markets is unpredictable. Although we have been able to successfully raise money in the current economic climate, we may not be successful in the future. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

 

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

 

Our ability to continue exploration and development of our properties and to replace reserves may be dependent upon our ability to continue to raise significant additional financing, including debt financing or obtain other potential arrangements with industry partners in lieu of raising financing. Any arrangements that may be entered into could be expensive to us. There can be no assurance that we will be able to raise additional capital in light of factors such as the market demand for our securities, the state of financial markets for independent oil and

gas companies (including the markets for debt), oil and natural gas prices and general market conditions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of our capital budget.

 

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

 

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

 

Our operations are conducted primarily in the Rocky Mountain region of the United States, and will be conducted to some extent in north-central Pennsylvania area of the Appalachian Basin. The weather in these areas 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 operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.

 

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 and possible liabilities. 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 in 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. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period, 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.

 

We have limited control over activities conducted on properties we do not operate.

 

We own interests in properties that are operated by third parties. The success and timing of drilling and other development activities on our non-operated properties depend on a number of factors that are beyond our control. Because we have only a limited ability to influence and control the operations of our non-operated properties, we can give no assurances that we will realize our targeted returns with respect to those properties.

 

We may fail to fully identify problems with any properties we acquire.

 

We acquired a portion of our acreage position in Pennsylvania through property acquisitions and acreage trades, and we may acquire additional acreage in Pennsylvania or other regions in the future. Although we conduct a

review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify.

 

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. Except for statements of historical facts, all statements included in this document, including 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 extends the lease terms until cessation of that production. The leases in Pennsylvania include both those from private individuals and companies, and from the Commonwealth of Pennsylvania. The leases in Pennsylvania are mostly undeveloped at this time and typically have primary lease terms of five years until establishment of production.

 

Green River Basin, Wyoming

 

As of December 31, 2009, the Company owned developed oil and natural gas leases totaling approximately 21,000 gross (10,000 net) acres in the Green River Basin of Sublette County, Wyoming which represents approximately 77% of the Company’s total developed net acreage. The Company owns undeveloped oil and natural gas leases totaling approximately 91,000 gross (46,000 net) acres in the Green River Basin of Sublette County, Wyoming which represents approximately 22% of the Company’s total undeveloped net acreage. The Company’s acreage in the Green River Basin primarily covers the Pinedale and Jonah fields with several other undeveloped acreage blocks north and west of the Pinedale field. Lease maintenance costs in Wyoming were approximately $0.4 million for the year ended December 31, 2009. The Company currently owns 39 leases totaling 65,345 gross (36,618 net) acres currently held by production and activities (“HBP”) in Wyoming. The HBP acreage includes all of the Company’s leases within the productive area of the Pinedale and Jonah fields.

 

Exploration and development wells are identified with new criteria as of December 31, 2009. In SEC Release No. 33-8995, Modernization of Oil and Gas Reporting (“SEC Release No. 33-8995”), additional clarity is provided regarding the certainty of reserve forecasts for individual wells and the characterization of this certainty within the modernized reserve reporting framework. As a result, this clarification provides for the Company to modify its criteria for reserve reporting and classification. Accordingly, many wells that were previously characterized as exploratory simply due to prior classification as proved undeveloped reserves are more accurately characterized as developmental in nature due to the clarification of reasonable certainty under the new criteria.

 

Exploratory Wells.  During 2009, the Company participated in the drilling of a total of 8 gross (2.80 net) productive exploratory wells on the Green River Basin properties. At December 31, 2009, there was one gross (0.27 net) additional exploratory well that commenced during the year that was either still drilling or had operations suspended at a depth short of total depth and thus a determination of productive capability could not be made at year end.

 

Development Wells.  During 2009, the Company participated in the drilling of 155 gross (76.09 net) productive development wells on the Green River Basin properties. At year end 2009, there were 58 gross (34.78 net) additional development wells that commenced during the year and were either still drilling or had operations suspended at a depth short of total depth.

 

Pennsylvania

 

As of December 31, 2009, the Company owned developed oil and gas leases totaling approximately 6,000 gross (3,000 net) acres in the Pennsylvania portion of the Appalachian Basin which represents 23% of the Company’s total developed net acreage. The Company owns undeveloped oil and gas leases totaling approximately 320,000 gross (166,000 net) acres in this area which represents 78% of the Company’s total undeveloped net acreage. Lease maintenance costs in Pennsylvania were approximately $5.5 million for the year ended December 31, 2009. The Company owns approximately 6,000 gross (3,000 net) acres currently held by production or activities in Pennsylvania.

Exploratory Wells.  During the year ended December 31, 2009, the Company participated in the drilling of a total of 35 gross (21.00 net) wells on the Pennsylvania properties. At December 31, 2009, there were 2 gross (1.50 net) additional exploratory wells that commenced during the year that were either still drilling or had operations suspended at a depth short of total depth and thus a determination of productive capability could not be made at year end. In its operated Marshlands area, the Company completed a 30 square mile 3-D seismic survey and began a horizontal drilling campaign in the Marcellus Shale. Also, a multi-rig, horizontal drilling program of Marcellus wells began during 2009 in the non-operated AMI area of the Company’s acreage. In 2009, all activities and investments in Pennsylvania were considered exploratory for purposes of this report.

 

Oil and Gas Reserves

 

The following table sets forth the Company’s quantities of proved reserves for the years ended December 31, 2009, 2008, and 2007 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. The table summarizes the Company’s 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, 2009, 2008 and 2007. 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 drilled before January 1, 2013. As of December 31, 2009, proved undeveloped reserves represent 58.8% of the Company’s total proved reserves. During 2009, the Company invested $741.4 million in its properties, of which, 82% was invested to convert reserves to proved developed status. We have substantially more locations than we can drill in the next three years based on our planning and budgeting process. We continually attempt to identify and schedule for drilling during the next three years the proved undeveloped locations that we believe will yield the highest return on capital invested. Additional information, changes in economics and acquisitions may cause us to alter the drilling locations included in our proved undeveloped reserves from time to time in order to permit us to develop what we identify as the highest return opportunities within the capital budget and other resources available to us.

 

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. The Director — Reservoir Engineering & Planning is primarily responsible for overseeing the preparation of the Company’s reserve estimates by our independent engineers, Netherland, Sewell & Associates, Inc. The Director has a Bachelor and Master of Science degree in Petroleum Engineering and is a licensed Professional Engineer with over 15 years experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

 

All of the information regarding reserves in this annual report is derived from the report of Netherland, Sewell & Associates, Inc. The report of Netherland, Sewell & Associates, Inc. is included as an Exhibit to this annual report. The principal engineer at Netherland, Sewell & Associates, Inc. responsible for preparing our reserve estimates has a Bachelor of Science degree in Mechanical Engineering and is a licensed Professional Engineer with over 25 years of experience, including significant experience throughout the Rocky Mountain basins.

 

 

 

 

Since January 1, 2009, no crude oil or natural gas reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

Production Volumes, Average Sales Prices and Average Production Costs

 

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

 

 

 

 

Productive Wells

 

As of December 31, 2009 the Company’s total gross and net wells were as follows:

 

 

 

 

Oil and Gas Acreage

 

As of December 31, 2009 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 material acreage expiry.

 

The acreage and other additional information concerning the Company’s oil and natural gas operations are presented in the following tables.

 

 

Drilling Activities

 

As of December 31, 2009, SEC Release No. 33-8995 provides additional clarity regarding the criteria for determining the development status of wells such that exploration and development wells are identified with new criteria. The Company implemented the new criteria as of December 31, 2009 and previous years do not reflect the updated guidelines.

For each of the three fiscal years ended December 31, 2009, 2008 and 2007 the number of gross and net wells drilled by the Company was as follows:

 

Wyoming — Green River Basin

 

At year end, there were 58 gross (34.78 net) additional development wells that were either drilling or had operations suspended. This includes wells in both the Pinedale and Jonah fields.

 

 

At year end, there was one gross (0.27 net) additional exploratory well that was either drilling or had operations suspended. This includes wells in both the Pinedale and Jonah fields.

 

Pennsylvania

 

At year end, there were 2 gross (1.50 net) additional exploratory wells that were either drilling or had operations suspended.

 

China — Bohai Bay

 

 

 

 

 

The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict 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, 2009.

 

 

The Company’s common stock trades on the New York Stock Exchange (“NYSE”) 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.

 

 

As of February 17, 2010, the last reported sales price of the common stock on the NYSE was $49.38 per share and, there were approximately 376 holders of record of the common stock.

 

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the NYSE Composite Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oils Stock Index) from December 31, 2004 through December 31, 2009. This marks a successful transition from the Standard & Poor’s Composite 500 Stock Index and takes into consideration the name change of the Dow Jones Wilshire Exploration and Production Index.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Ultra Petroleum Corp., The NYSE Composite Index
And The Dow Jones US Exploration & Production TSM Index

 

 

 

 

Copyright ^© 2010 Dow Jones & Co.  All rights reserved.

 

 

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

 

The selected consolidated financial information presented below for the years ended December 31, 2009, 2008, 2007, 2006 and 2005 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 operate in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.

 

The Company currently generates substantially all of its revenue, earnings and cash flow from the production and sales of natural gas and condensate from its property in southwest Wyoming. The price of natural gas is a critical factor to the Company’s business and the price of natural gas has historically been volatile. 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 fixed price forward physical delivery contracts and swap agreements for natural gas. The average price realization for the Company’s natural gas during 2009 was $4.88 per Mcf, including realized gains and losses on commodity derivatives. During the quarter ended December 31, 2009, the average price realization for the Company’s natural gas was $4.86 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas, excluding realized gains and losses on commodity derivatives, was $3.49 per Mcf and $4.20 per Mcf for the year and quarter ended December 31, 2009, respectively. (See Note 7).

 

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 and Pennsylvania. The Company delivered 24% production growth on an Mcfe basis during the year ended December 31, 2009 as compared to the same period in 2008.

 

 

The Company currently conducts operations exclusively in the United States. Substantially all of its 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.

 

Outlook

 

In 2008 and 2009, we saw significant changes in the business environment in which we operate, including severe economic uncertainty, increasing market volatility and continued tightening of credit markets. These market conditions contributed to record high commodity prices during the first half of 2008 and nearly unprecedented drops in these commodity prices in the second half of 2008 and throughout 2009.

 

We believe we are well positioned for the current economic environment because of our status as a low cost operator in the industry combined with our financial flexibility. In 2009, the Company established new production records while maintaining a low cost structure which contributes to the consistency of the Company’s growth and returns. Although our net cash provided by operating activities was negatively affected by general economic conditions, we believe that we will continue to generate positive cash flow from operations, which, along with our available cash, will provide sufficient liquidity to allow us to return value to our shareholders.

 

While we continue to monitor the overall health of the credit markets, we expect to rely on our available cash, our existing credit facility and the cash we generate from our operations to meet our obligations and to fund our capital investments and operations over the next twelve months. A renewed, long-term disruption in the credit markets could make financing more expensive or unavailable, which could have a material adverse effect on our operations.

 

Critical Accounting Policies

 

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. 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 related to 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.

 

Oil and Gas Reserves.  On January 6, 2010, the FASB issued Accounting Standards Update (“ASU”), Oil and Gas Reserve Estimation and Disclosures. The ASU amends FASB ASC Topic 932, Extractive Activities — Oil and Gas (“FASB ASC 932”) to align the reserve calculation and disclosure requirements of FASB ASC 932 with the requirements in SEC Release No. 33-8995. The ASU is effective for reporting periods ending on or after December 31, 2009.

 

On December 31, 2008, the SEC issued SEC Release No. 33-8995 amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K revising oil and gas reserves estimation and disclosure requirements. The new rules include changes to pricing used to estimate reserves, the ability to include non-traditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The primary objectives of the revisions are to increase the transparency and information value of reserve disclosures and improve comparability among oil and gas companies. The rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009.

 

Accordingly, the Company adopted the update to FASB ASC 932 as of December 31, 2009 in order to conform to the requirements in SEC Release No. 33-8995.

 

In accordance with our three-year planning and budgeting cycle, proved undeveloped reserves included in the current, as well as previous reserve estimates, include only economic well locations that are forecast to be drilled within a three-year period. As a result of our self-imposed three-year limit on proved undeveloped reserves inventory, we have not booked any proved undeveloped reserves beyond five years. As a result, it is the Company’s opinion that the proved reserves included in this report would not be significantly different if they were filed under the previous guidelines.

 

The Company utilizes reliable technology such as seismic data and interpretation, wireline formation tests, geophysical logs and core data to assess its resources. However, none of these technologies have contributed to a material addition to the proved reserves in this report. The proved reserves estimates are prepared by Netherland, Sewell and Associates, an independent, third-party engineering firm.

 

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 a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events. 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. The Company has historically based the fourth quarter depletion calculation on the respective year end reserve report. This methodology was utilized in computing the fourth quarter 2009 depletion expense.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being 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. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% 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.

 

During the first quarter of 2009, the Company recorded a $1.0 billion ($673.0 million net of tax) non-cash write-down of the carrying value of the Company’s proved oil and gas properties as of March 31, 2009, as a result of the ceiling test limitation, which is reflected as write-down of proved oil and gas properties in the accompanying consolidated statements of operations. The March 31, 2009 ceiling test limitation was calculated prior to the adoption of SEC Release No. 33-8995 and was based on prices in effect on the last day of the reporting period, March 31, 2009, reflecting wellhead prices of $2.47 per Mcf for natural gas and $33.91 per barrel for condensate. The Company did not have any write-downs related to the full cost ceiling limitation in 2008 or 2007.

 

As of December 31, 2009, the ceiling limitation exceeded the carrying value of the Company’s oil and natural gas properties. Estimates of standardized measure at December 31, 2009 were based on wellhead prices which averaged $3.04 per Mcf for natural gas and $52.18 per barrel for condensate. The average prices reflect the prices in effect on the first day of the month for the preceding twelve month period. 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. FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”) 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 costs, including revisions thereto, are charged to expense through DD&A.

 

Entitlements Method of Accounting for Oil and Natural Gas Sales.  The Company generally sells natural gas and condensate 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 collectability 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, 2009, the Company had net deferred tax assets totaling $53.5 million which management considers is more likely than not to be realized.

 

Derivative Instruments and Hedging Activities.  Currently, the Company largely relies on commodity derivative contracts (generally, financial swaps) to manage its exposure to commodity price risk. Additionally, and from time to time, the Company enters into physical, fixed price forward natural gas sales in order to mitigate its commodity price exposure on a portion of its natural gas production. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”).

 

Effective November 3, 2008, the Company changed its method of accounting for natural gas commodity derivatives to reflect unrealized gains and losses on commodity derivative contracts in the income statement rather than on the balance sheet. The Company previously followed hedge accounting for its natural gas hedges. Under this prior accounting method, the unrealized gain or loss on qualifying cash flow hedges (calculated on a mark to market basis, net of tax) was recorded on the balance sheet in stockholders’ equity as accumulated other comprehensive income (loss). When an unrealized hedging gain or loss was realized upon contract expiration, it was reclassified into earnings through inclusion in natural gas sales revenues. The Company continues to record the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, but records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. There is no resulting effect on overall cash flow, total assets, total liabilities or total stockholders’ equity, and there is no impact on any of the financial covenants under the Company’s Senior Credit Facility, 2008 Senior Notes or 2009 Senior Notes (See Note 5).

 

During the first quarter of 2009, the Company converted its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This change provides operational flexibility to curtail gas production in the event of continued declines in natural gas prices. The contracts were converted at no cost to the Company and the conversion of these contracts to derivative instruments was effective upon entering into these transactions in March 2009, with upcoming settlements for production months through December 2010.

 

Fair Value Measurements.  The Company adopted FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), as of January 1, 2008. The implementation of these requirements was applied prospectively for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact on consolidated results of operations, financial position or liquidity. For those non-financial assets and liabilities measured or disclosed at fair value on a non-recurring basis, primarily our asset retirement obligation, this respective subtopic of FASB ASC 820 was effective January 1, 2009.

Implementation of this portion of the standard did not have a material impact on consolidated results of operations, financial position or liquidity. See Note 8 for additional information.

 

Under FASB ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the fair value of the Company’s commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

 

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

 

The fair values summarized below were determined in accordance with the requirements of FASB ASC 820 and we aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by FASB ASC 820. The balance of net unrealized gains and losses recognized for our energy-related derivative instruments at December 31, 2009 is summarized in the following table based on the inputs used to determine fair value:

 

 

 

 

 

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

 

Share-Based Payment Arrangements.  The Company follows FASB ASC Topic 718, Compensation — Stock Compensation (“FASB ASC 718”) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized under FASB ASC 718 for the years ended December 31, 2009, 2008 and 2007 was $10.9 million, $5.8 million and $5.7 million, respectively. See Note 6 for additional information.

 

Results of Operations — Year Ended December 31, 2009 vs. Year Ended December 31, 2008

 

During the year ended December 31, 2009, production increased on a gas equivalent basis to 180.1 Bcfe from 145.3 Bcfe for the same period in 2008 attributable to the Company’s successful drilling activities during 2009. Realized natural gas prices, including realized gain and loss on commodity derivatives, decreased 33% to $4.88 per Mcf during the year ended December 31, 2009 as compared to $7.26 per Mcf for the same period in 2008. During

the year ended December 31, 2009, the Company’s average price for natural gas was $3.49 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $7.11 per Mcf for the same period in 2008. The decrease in average natural gas prices partially offset by the increase in production contributed to a 39% decrease in revenues for the year ended December 31, 2009 to $666.8 million as compared to $1.1 billion in 2008.

 

Lease operating expense (“LOE”) increased to $40.7 million for the year ended December 31, 2009 compared to $37.0 million during the same period in 2008 due primarily to increased well counts resulting from the Company’s drilling program. On a unit of production basis, LOE costs decreased to $0.23 per Mcfe at December 31, 2009 compared to $0.25 per Mcfe at December 31, 2008 as a result of increased production volumes and a higher mix of Ultra operated production during the year ended December 31, 2009.

 

During the year ended December 31, 2009, production taxes were $67.0 million compared to $119.5 million during the same period in 2008, or $0.37 per Mcfe, compared to $0.82 per Mcfe. The decrease in per unit taxes is attributable to decreased sales revenues as a result of lower realized gas prices during the year ended December 31, 2009 as compared to the same period in 2008. Production taxes are calculated based on a percentage of revenue from production and were 10.0% of revenues for the year ended 2009 and 11.0% for the same period in 2008.

 

Gathering fees increased to $45.2 million for the year ended December 31, 2009 compared to $37.7 million during the same period in 2008 largely due to increased production volumes. On a per unit basis, gathering fees decreased to $0.25 per Mcfe for the year ended December 31, 2009 as compared to $0.26 per Mcfe for the same period in 2008.

 

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas, the Company incurred firm transportation charges totaling $58.0 million for the period ended December 31, 2009 as compared to $46.3 million for the same period in 2008 in association with REX Pipeline transportation charges. On a per unit basis, transportation charges remained flat at $0.32 per Mcfe (on total company volumes) for the periods ended December 31, 2009 and 2008.

 

DD&A increased to $201.8 million during the period ended December 31, 2009 from $184.8 million for the same period in 2008, attributable to increased production volumes, partially offset by a lower depletion rate due mainly to a lower depletable base as a result of the ceiling test limitation during the first quarter of 2009. On a unit of production basis, DD&A decreased to $1.12 per Mcfe at December 31, 2009 from $1.27 at December 31, 2008. The Company recorded a $1.0 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties at March 31, 2009 as a result of the ceiling test limitation. The write-down reduced earnings in the first quarter of 2009 and results in lower DD&A expense in future periods.

 

General and administrative expenses increased to $19.8 million for the period ended December 31, 2009 compared to $17.0 million for the same period in 2008. The increase in general and administrative expenses is primarily attributable to increased headcount and related compensation. On a per unit basis, general and administrative expenses decreased to $0.11 per Mcfe for the year ended December 31, 2009 as compared to $0.12 per Mcfe for the same period in 2008.

 

Interest expense increased to $37.2 million during the period ended December 31, 2009 compared to $21.3 million during the same period in 2008 as a result of increased borrowings during the period ended December 31, 2009. At December 31, 2009, the Company had $795.0 million in borrowings outstanding.

 

Other expense increased to $2.9 million as of December 31, 2009 primarily as a result of rig termination payments during the period ended December 31, 2009.

 

During the year ended December 31, 2009, the Company recognized $239.4 million related to realized gain on commodity derivatives as compared to $19.0 million during the year ended December 31, 2008. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts.

 

During the year ended December 31, 2009, the Company recognized $92.8 million related to unrealized loss on commodity derivatives as compared to $14.2 million related to unrealized gain on commodity derivatives during

the year ended December 31, 2008. The unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments.

 

The Company recognized a loss before income taxes of $696.2 million for the year ended December 31, 2009 compared with income of $654.4 million for the same period in 2008. The decrease in earnings is primarily a result of the non-cash write-down of oil and gas properties associated with the ceiling test limitation, decreased natural gas prices partially offset by increased production and realized gains on commodity derivatives during the period ended December 31, 2009 as compared to the same period in 2008.

 

The income tax benefit recognized for the year ended December 31, 2009 was $245.1 million compared with an income tax provision of $240.5 million for the year ended December 31, 2008 due to a net loss during the year ended December 31, 2009 primarily as a result of the non-cash write-down of oil and gas properties associated with the ceiling test limitation.

 

For the year ended December 31, 2009, the Company recognized a net loss of $451.1 million or ($2.98) per diluted share as compared with net income of $414.3 million or $2.65 per diluted share for the same period in 2008. The decrease is primarily attributable to the non-cash write-down of oil and gas properties associated with the ceiling test limitation, decreased natural gas prices partially offset by increased production and realized gains on commodity derivatives during the year ended December 31, 2009 as compared to the same period in 2008.

 

Results of Operations — Year Ended December 31, 2008 vs. Year Ended December 31, 2007

 

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

 

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

 

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

 

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

 

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

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

 

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

 

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

 

During the year ended December 31, 2008, the Company recognized $19.0 million and $14.2 million related to realized gain on commodity derivatives and unrealized gain on commodity derivatives, respectively. These amounts relate to derivative contracts that the Company entered into during the first quarter of 2008 in order to mitigate commodity price exposure on a portion of the forecasted production which was expected to be sold on REX. Due to limited historical data correlating REX sales points and NWPL — Rockies (the basis of the contracts), the Company was unable to effectively demonstrate correlation between the derivative instrument and the forecasted transaction according to the contemporaneous documentation as set forth under the requirements of SFAS No. 133 causing the derivative contracts to no longer qualify for hedge accounting treatment. The realized gain on commodity derivatives relates to actual amounts received under these derivative contracts while the unrealized gain on commodity derivatives represents the change in the fair value of these derivative instruments.

 

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

 

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

 

Discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese operations) decreased to $0.4 million for the year ended December 31, 2008 from $82.8 million for the same period in 2007. The decrease is primarily related to the closing of the sale of Sino-American Energy Corporation for net proceeds of $208.0 million, which resulted in a pre-tax gain on sale of properties of $98.1 million during the quarter ended December 31, 2007. (See Note 12).

 

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

 

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. GAAP. In addition, application of generally accepted accounting principles 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.

LIQUIDITY AND CAPITAL RESOURCES

 

During the year ended December 31, 2009, the Company relied on cash provided by operations along with borrowings under the senior credit facility and the issuance of the 2009 Senior Notes to finance its capital expenditures. The Company participated in the drilling of 259 wells in Wyoming and Pennsylvania during 2009. For the year ended December 31, 2009, net capital expenditures were $741.4 million. At December 31, 2009, the Company reported a cash position of $14.3 million compared to $14.2 million at December 31, 2008. Working capital deficit at December 31, 2009 was $137.5 million compared to a deficit of $149.4 million at December 31, 2008. At December 31, 2009, we had $260.0 million in outstanding borrowings and $240.0 million of available borrowing capacity under our credit facility. In addition, the Company had $535.0 million outstanding in senior notes (See Note 5). Other long-term obligations of $35.9 million at December 31, 2009 is comprised of items payable in more than one year, primarily related to production taxes and our asset retirement obligation.

 

The Company’s positive cash provided by operating activities, along with availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital investment program for 2010, which is currently projected to be approximately $1.1 billion. Of the $1.1 billion budget, the Company plans to allocate approximately 60% to Wyoming and 40% to Pennsylvania.

 

On December 21, 2009, the Company announced that it had signed a purchase and sale agreement to acquire additional acreage in the Pennsylvania Marcellus Shale in order to increase the scale of its Marcellus position. On February 22, 2010, the transaction closed for $333.0 million. This transaction is incremental to the 2010 budgeted capital investment program discussed above.

 

Additionally, on January 28, 2010, the Company’s subsidiary, Ultra Resources, Inc., agreed to issue an aggregate amount of $500.0 million of Senior Notes (the “2010 Senior Notes”) pursuant to a Second Supplement to its Master Note Purchase Agreement dated March 6, 2008. Of the 2010 Senior Notes: $270.0 million of the 2010 Senior Notes were issued January 28, 2010 and $230.0 million of the 2010 Senior Notes were issued February 16, 2010. The 2010 Senior Notes rank pari passu with Ultra Resources’ bank revolving credit facility and other outstanding Senior Notes. Proceeds from the 2010 Senior Notes were used to repay revolving credit facility debt, but did not reduce the borrowings available under the revolving credit facility, and for general corporate purposes, including funding the Pennsylvania Marcellus Shale acquisition that closed on February 22, 2010.

 

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

 

Loans under the credit facility are unsecured and bear interest, at the Company’s 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 the Company’s consolidated leverage ratio (100.0 basis points per annum as of December 31, 2009).

 

The facility has restrictive covenants that include the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to exceed 31/2 times; and as long as the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total funded debt of at least 1.75 to 1.00. At December 31, 2009, the Company was in compliance with all of its debt covenants under the credit facility. (See Note 5).

 

Senior Notes:  On March 6, 2008, the Company’s wholly-owned subsidiary, Ultra Resources, Inc. issued $300.0 million Senior Notes (“the 2008 Senior Notes”) pursuant to a Master Note Purchase Agreement between the Company and the purchasers of the Notes. On March 5, 2009, the Company’s wholly-owned subsidiary, Ultra Resources, Inc., issued $235.0 million Senior Notes (“the 2009 Senior Notes”) pursuant to a First Supplement to the Master Note Purchase Agreement.

The Senior Notes rank pari passu with the Company’s bank credit facility. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation.

 

Proceeds from the sale of the Senior Notes were used to repay bank debt or for general corporate purposes, but did not reduce the borrowings available to the Company under the revolving credit facility. The Senior Notes are pre-payable in whole or in part at any time and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At December 31, 2009, the Company was in compliance with all of its debt covenants under the Senior Notes. (See Note 5).

 

Operating Activities.  During the year ended December 31, 2009, net cash provided by operating activities was $592.6 million, a 30% decrease from $840.8 million for the same period in 2008. The decrease in net cash provided by operating activities was largely attributable to the decrease in realized natural gas prices partially offset by increased production during the year ended December 31, 2009 as compared to the same period in 2008.

 

Investing Activities.  During the year ended December 31, 2009, net cash used in investing activities was $820.6 million as compared to $915.3 million for the same period in 2008. The decrease in net cash used in investing activities is largely due to decreased capital expenditures associated with the Company’s drilling activities in 2009 as compared to 2008 partially offset by the timing of payments associated with capital costs incurred during 2008 and paid during 2009.

 

Financing Activities.  During the year ended December 31, 2009, net cash provided by financing activities was $228.1 million as compared to net cash provided by investing activities of $78.0 million for the same period in 2008. The increase in cash provided by net financing activities is primarily attributable to decreased share repurchases during 2009 as compared to 2008.

 

OFF BALANCE SHEET ARRANGEMENTS

 

The Company did not have any off-balance sheet arrangements as of December 31, 2009.

 

Contractual Obligations

 

The following table summarizes our contractual obligations as of December 31, 2009:

 

 

Transportation contract.  In December 2005, the Company agreed to become an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. The Company’s commitment involves a capacity of 200 MMMBtu per day of natural gas for a term of 10 years commencing with initial transportation in January 2008, and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper.

During the first quarter of 2009, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. This additional capacity will provide the Company with the ability to move additional volumes from its producing wells in Wyoming to markets in the eastern U.S.

 

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

 

Office space lease.  In May 2007, the Company amended its office leases in Englewood, Colorado and Houston, Texas, both of which it has committed through 2012. The Company’s total remaining commitment for office leases is $1.6 million at December 31, 2009 ($0.8 million in 2010, $0.7 million in 2011 and $0.1 million in 2012).

 

 

Objectives and Strategy:  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.

 

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program.

 

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.

 

Commodity Derivative Contracts:  During the first quarter of 2009, the Company converted its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This change provides operational flexibility to curtail gas production in the event of continued declines in natural gas prices. The contracts were converted at no cost to the Company and the conversion of these contracts to derivative instruments was effective upon entering into these transactions in March 2009, with upcoming settlements for production months through December 2010. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

From time to time, the Company also utilizes fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC 815.

 

Fair Value of Commodity Derivatives:  FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments. The application of hedge accounting was discontinued by the Company for periods beginning on or after November 3, 2008.

 

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current expense or income in the income statement. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and does not impact operating cash flows on the cash flow statement.

At December 31, 2009, 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. See Note 8 for the detail of the asset and liability values of the following derivatives.

 

 

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007 (refer to Note 1 for details of unrealized gains or losses included in accumulated other comprehensive income in the Consolidated Balance Sheets):

 

 

 

 

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, 2009.

 

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

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Shareholders of Ultra Petroleum Corp.

 

We have audited the accompanying consolidated balance sheets of Ultra Petroleum Corp. as of December 31, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

 

As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

 

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, 2009, 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 26, 2010 expressed an unqualified opinion thereon.

 

 

Houston, Texas

February 26, 2010

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, 2009, 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, 2009, 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, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009 of Ultra Petroleum Corp. and our report dated February 26, 2010 expressed an unqualified opinion thereon.

 

 

Houston, Texas

February 26, 2010