Item 1. Business.
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 gas properties. The Company was incorporated on November 14, 1979, under the laws of the Province of British Columbia, Canada. The Company continued into the Yukon Territory, Canada under Section 190 of the Business Corporations Act (Yukon Territory) on March 1, 2000. The Company’s operations are focused primarily in the Green River Basin of southwest Wyoming and Bohai Bay, offshore China. From time to time, the Company evaluates other opportunities for the acquisition, exploration and development of oil and gas properties.
As of December 31, 2004 Ultra owns interests in approximately 166,974 gross (92,997 net) acres in Wyoming covering approximately 260 square miles. The Company owns working interests in approximately 241 gross productive wells in this area and is operator of 41.5% of the 241 gross wells. The Company’s current domestic operations are focused on developing and expanding a tight gas sand project located in the Green River Basin in Southwest Wyoming. In 2004, the Company’s Wyoming production was approximately 92.8% of the Company’s total oil and natural gas production on a BOE basis and 97% of the Company’s estimated net proved reserves were in Wyoming. In 2004, capital expenditures in Wyoming comprised approximately 92% of the Company’s total capital expenditures.
Following the acquisition of Pendaries Petroleum Ltd. on January 16, 2001, the Company became active in oil and gas exploration and development in Bohai Bay, China. The Company holds an 18.182% exploration interest in the 04/36 Block and a 15.00% exploration interest in the 05/36 Block (jointly the “Blocks”) which interests are reduced upon initiation of development to an 8.91% working interest and a 7.35% working interest, respectively, for the development areas. On July 19, 2004 oil production began from the CFD 11-1 & 11-2 fields on Block 04/36. In 2004, the Company spent approximately 8% of its total 2004 capital budget on developing these China fields, as well as on engineering work focused on development of additional fields and continuing exploration. A wholly owned subsidiary of Kerr-McGee Corporation is the operator of the Blocks. At the time of the Pendaries acquisition, there were three oil discoveries on the Blocks. Since then, six new discoveries have been made on the Blocks.
The Company also owns interests in 15,518 gross (14,652 net) acres in Pennsylvania. A test well is planned to be drilled on this acreage in 2005. The Company owns interest in approximately 720 gross (320 net) acres and interests in three productive wells in Texas.
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 we make 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. The Company’s SEC filings are available on its website as soon as they are posted to the EDGAR database on the SEC’s website.
Business Strategy
Green River Basin, Wyoming
The Company will continue the ongoing program to identify, develop and explore the acreage position now held in the tight gas sand trend in the Green River Basin. The majority of the wells in the 2005 drilling program will be targeting 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 at a range of approximately 8,000 to 12,000 feet and Mesaverde at a range of approximately 12,000 to 14,000 feet as found in the Pinedale and Jonah fields area. The Company will continue to drill step-out and exploration wells on its Green River Basin acreage position in an ongoing attempt to further define and expand the current known producing area. In addition to the ongoing efforts in the Lance Pool section, the Company is continuing to evaluate the deeper potentially productive zones found on its acreage block below the Lance Pool. All of the Company’s drilling activity is conducted utilizing its extensive integrated geological and geophysical data set which includes what the Company believes is the most comprehensive 3D seismic data coverage on the Pinedale Field. 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.
Bohai Bay, China
In 2005, the Company plans to continue producing oil at the CFD 11-1 & 11-2 fields, begin development and appraisal work on existing discoveries and drill additional exploration wells. The Company has nine discovered oil fields in the Bohai Blocks. The first two oil fields, CFD 11-1 & 11-2, began producing in July 2004. Two additional fields are currently scheduled to go on production in late 2005 and engineering plans are being completed to bring three more fields into production in 2006 bringing the total to seven producing fields by year-end 2006. The two remaining fields are still in the appraisal stage.
Marketing and Pricing
The Company derives its revenues principally from the sale of its natural gas production, and associated condensate, from wells operated by the Company and others in the Green River Basin in Southwest Wyoming. To a lesser extent, the Company derives its revenues from the sale of its share of oil production from its producing fields in the Bohai Bay area, offshore China. The Company’s revenues are determined, to a large degree, by prevailing natural gas prices for production situated in the Rocky Mountain Region of the United States; specifically, Southwest Wyoming, as well as prevailing prices for crude oil produced in the Bohai Bay region of China of comparable quality. Energy commodity prices in general, and the Company’s regional prices in particular, have experienced a high degree of volatility in the past, and such high levels of volatility are expected to continue in the future. The Company cannot accurately predict or control the market prices that it receives for the sale of its natural gas, condensate, or oil production. However, the Company does, in the regular course of its business, from time to time, hedge a portion of its natural gas production through the use of fixed price, forward sales of physical gas, or through the limited use of financial swaps with creditworthy financial counterparties. The Company has not, to date, hedged any of its Chinese oil production; although it may do so in the future. For a more detailed description of the Company’s hedging activities, see Item 7A Quantitative and Qualitative Discussion about Market Risk. The Company’s hedging policy limits amounts 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 the spot prices that it would have received. However, the Company has determined that the certainty and predictability of a portion of its revenues that result from its hedging activities are both desirable and prudent.
Natural Gas Marketing
During 2004, the Company realized natural gas prices that were higher than those historically seen in the Southwest Wyoming region. The market price for natural gas in the Rockies generally, and in Southwest Wyoming specifically, is influenced by a number of regional and national factors; all of which are beyond the ability of the Company to control or to predict. These factors include weather, gas supplies, gas demand, and pipeline export capacity. The Rocky Mountain Region is a net-exporter of natural gas, since production there exceeds local demand for gas. Historically, natural gas production in Southwest Wyoming has 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”. As recently as the first quarter of 2003, the Company saw significant basis differentials for its Wyoming production, versus the “Henry Hub” pricing reference point in south Louisiana. As a result, during that time period, the Company realized prices that were significantly lower than those received by companies with production in other regions of the U.S. Since the second quarter of 2003, generally speaking, the Company has enjoyed, and expects to enjoy, improved basis differentials for its Wyoming natural gas production, due to significant increases in pipeline capacity to transport production from the Rockies production areas to markets in the West (Kern River Pipeline - in service May 2003) and the Midwestern U.S. (Cheyenne Plains Pipeline - in service February 2005). These expansions of pipeline export capacity have reduced but not eliminated the basis differential for gas prices in Southwest Wyoming gas production when compared to prices at the Henry Hub pricing reference point.
The Kern River Pipeline system was expanded by over 900 MMcfd, in May 2003, bringing its capacity to deliver natural gas produced in Southwest Wyoming to markets in Utah, Nevada and California to over 1.7 Bcf/d. Since that time, Colorado Interstate Gas Pipeline (a subsidiary of El Paso Corporation) has completed Phase I of the Cheyenne Plains Pipeline, which moves gas from Wyoming to Greensburg, Kansas, where it is interconnected with several large, interstate gas pipelines that supply gas to markets in the Midwestern U.S. The completion of Phase I of the Cheyenne Plains Pipeline adds 560 MMcfd of export capacity for Rocky Mountain gas to markets in the Midwest. There are numerous other proposed pipeline projects in various stages of planning or development that have been announced to transport Rockies and Wyoming gas production to markets. While the Company is optimistic that the pipeline infrastructure will continue to be expanded to provide
sufficient capacity to transport its gas production and to provide for reasonable basis differentials for its gas in the future, there can be no assurance that any such expansions, if built, will prevent large basis differentials from occurring in the future.
The Company 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 (daily, monthly and longer term). The sale of the Company’s natural gas is “as produced”, and 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.
Oil Marketing
With the commencement of production from the first two of its fields in Block 04/36 Bohai Bay offshore China in July 2004, the Company, through its wholly owned Sino-American Energy Corporation subsidiary, has begun marketing its share of oil production from the CFD 11-1/11-2 fields.
The sale of the Company’s Chinese oil production (CFD crude) is done on a tanker/cargo lifting basis. As the Company’s share of inventories on the CFD 11-1/11-2 field’s Floating Production Storage and Offloading Vessel (“FPSO”) become sufficient to schedule a lifting (typically 200,000 - 300,000 barrels per cargo), the Company coordinates with the operator and its markets to lift a cargo. By necessity, the Company will, from time to time, carry inventories of crude oil to accommodate the lifting schedules for its share of oil from the FPSO. Each of the partners in the CFD 11-1/11-2 fields are responsible for the disposition of their respective share of the CFD crude production. Kerr-McGee, as operator of these fields, manages the lifting schedule for production from these fields. During 2004, the Company lifted and sold 3 cargos of CFD crude for its account.
Currently, the CFD crude is a heavy, sweet crude oil, with an API gravity of approximately 19 degrees. The production from these fields is from multiple productive reservoirs, which have variability in the quality of oil. The Company believes that the quality of the oil produced from these fields will tend to improve as additional wells and reservoirs are completed and placed into production. Due to its quality, refiners and other markets for the CFD crude oil typically expect to be able to purchase CFD crude at prices that are lower than light sweet crude oils like West Texas Intermediate or Brent. Oil produced and sold from these fields is typically priced based upon the monthly official Indonesian Crude Price (ICP) for Duri field crude. The Duri crude, produced in Indonesia, is of similar quality to the CFD crude produced in the Bohai Bay area. The official ICP Duri price is a monthly weighted average of three (3) independent daily assessments of the price of Duri crude, reported by Platt’s, APPI (Asian Petroleum Price Index published by Seapac Services Limited), and RIM Intelligence Co. To the monthly official ICP Duri marker price, a premium or discount is added to reflect transportation and quality differentials for the CFD crude relative to the Duri marker crude. The premium or discount for the CFD crude (relative to the Duri price) is negotiated monthly between buyers and sellers.
To date, the Company has sold its share of the CFD production to an affiliate of its Chinese partner, Chinese National Offshore Oil Corporation (“CNOOC”) China, Ltd., at prices that reflect a slight discount to the ICP Duri monthly average price. The Company continues to assess its opportunities to market its share of the CFD oil production to other markets such as Korea, Japan and Singapore.
Environmental Matters
In 1998, the U.S. Bureau of Land Management (“BLM”) initiated a requirement for an Environmental Impact Statement (“EIS”) for the Pinedale Anticline area in the Green River Basin. An EIS evaluates the effects that an industry’s activities will have on the environment in which the activity is proposed. This EIS encompasses the area north of the Jonah Field, including the Pinedale Anticline, which is where most of the Company’s exploration and development is taking place. This environmental study included an analysis of the geological and reservoir characteristics of the area plus the necessary environmental studies related to wildlife, surface use, socio-economic and air quality issues. On July 27, 2000, the BLM issued its Record of Decision (“ROD”) with respect to the final EIS. The ROD/EIS allows for the drilling of 700 producing surface locations within the area covered by the EIS, but does not authorize the drilling of particular wells. Ultra must submit applications to the BLM’s Pinedale field manager for permits to drill and for other required authorizations, such as rights-of-way for pipelines, for each specific well or pipeline location. Development activities in the Pinedale Anticline area, as on all federal leaseholds, remain subject to regulatory agency approval. In making its determination on whether to approve specific drilling or development activities, the BLM applies the requirements outlined in the ROD/EIS.
The ROD/EIS imposes limitations and restrictions on activities in the Pinedale Anticline area, including limits on winter drilling and completion activity, and proposes mitigation guidelines, standard practices for industry activities and best management practices for sensitive areas. The ROD/EIS also provides for annual reviews to compare actual environmental impacts to the environmental impacts projected in the EIS and provides for adjustments to mitigate such impacts, if necessary. The review team is comprised of operators, local residents and other affected persons. The process of reviews is currently undergoing changes to satisfy the Federal Advisory Committee Act. The Company cannot predict if or how these changes may affect permitting, development and compliance under the EIS. 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.
As of year end, the Company had approximately 55 approved permits to drill wells on Company operated federal leases in the Pinedale Anticline 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 substantial. Further, any additional limitations and mitigation measures could further increase production costs, delay exploration, development and production activities and curtail exploration, development and production activities altogether.
The Company also co-owns leases on state and privately owned lands in the vicinity of the Pinedale Anticline that do not fall under the jurisdiction of the BLM and are not subject to the EIS requirement.
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 is conducted under an EIS. The EA was required to address the potential environmental impacts of developing the field on a well density of two (2) wells per 80 acre drilling and spacing unit as opposed to the one (1) 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 Wyoming Oil and Gas Conservation Commission (WOGCC) for drilling of two (2) 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. Prior to these approvals, the Company had drilled 21 gross (7.7 net) wells in the field. Since the increased density approvals, the Company has drilled an additional 22 gross (14.0 net) wells in the field. All 43 wells drilled by the Company in the Jonah Field have been productive. Since this time various other operators have received approval for the drilling of increased density wells in pilot areas at well densities ranging from four (4) wells per 80 acre drilling and spacing unit to sixteen (16) 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 (8) wells per 80 acre drilling and spacing unit. The BLM is currently conducting a new EIS covering the Jonah Field to assess the impacts of this increased density development and define the parameters under which this increased density development will be allowed to proceed. The draft EIS was made available mid-February 2005. The Company is currently reviewing the document.
During 2003 and 2004 Ultra and other operators in the Pinedale Field received approval from the WOGCC to drill increased density pilot project wells in several areas of the Pinedale Field. These pilot projects are designed to test the feasibility of developing this field in well densities greater than the currently approved one well per 40 acres. The results of some of this work led to the WOGCC in July 2004 approving the development of the northern portion of the anticline on a two (2) wells per 40 acre density. The acreage is operated by Questar Exploration and Production Company (“Questar”), a working interest partner of the Company, and the Company owns a working interest in the majority of this acreage. This approval covers approximately 14,432 gross acres. Drilling of additional increased density pilot wells continues and the results of these are being evaluated to determine the appropriate course of action as to the overall development strategy for the Pinedale Field.
In April 2004 Questar asked the BLM to modify winter-access restrictions to specifically allow them to operate on three active pads with two drilling rigs per pad. This request required an EA to weigh the negative impacts of winter activity relative to the extensive mitigation measures proposed by Questar. On November 9, 2004 they received approval in the form of a “Finding of No Significant Impact” from the BLM to phase in over the next year their proposed year-round drilling program which allows two drilling rigs on one pad during the winter of 2004/2005. After Questar completes the proposed mitigation measures including construction of a water and
condensate gathering system during the summer of 2005, they will be allowed to operate six rigs from three active pads beginning in the winter of 2005/2006 through the winter of 2013/2014.
The BLM approved the Questar proposal after considering extensive input from the participating agencies received during the public comment process. Key components of the approval are: 1) One pad with two drilling rigs during the winter of 2004/2005; 2) three pads with two drilling rigs per pad in the winter of 2005/2006 and thereafter through the winter of 2013/2014; 3) activities during the May-November period will continue to be governed by the original Pinedale Anticline EIS; 4) directional drilling with up to 16 wells per pad resulting in only one-third of the drilling phase surface disturbance contemplated under the original EIS; 5) construction of a produced water and condensate gathering system in 2005; 6) funding for continued monitoring of mule deer and other critical wildlife for the duration of development activity; 7) use of flareless-completion technology to reduce noise, air and visual pollution during well-completion operations; 8) funding for air-quality monitoring; and 9) wildlife habitat enhancement as well as other monitoring and mitigation measures described in the BLM decision record.
In September 2002, the Company received the “Oil & Gas Wildlife Stewardship” award from the Wyoming Game and Fish Department in recognition of its contribution to wildlife management in the Pinedale area. During 2001, the Company received the “Agency/Corporation of the Year” award from the Wyoming Wildlife Federation and the “Regional Administrator’s Award for Environmental Achievement” from the U.S. Environmental Protection Agency.
Regulation
Oil and Gas Regulation
The availability of a ready market for oil and gas production depends upon numerous factors beyond the Company’s control. These factors include state and federal regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and 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 gas well may be “shut-in” because of a lack of an available 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 gas, protect rights to produce oil and gas between owners in a common reservoir, control the amount of oil and gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and gas plants are also subject to the jurisdiction of various federal, state and local agencies.
The Company’s sales of natural gas are affected by the availability, terms and costs of transportation both in the gathering systems that transport from the wellhead to the interstate pipelines and in the interstate pipelines themselves. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory Commission (“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 gas industry by making gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. On February 25, 2000, FERC issued a statement of policy and final rule concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their 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. FERC is also considering a number of regulatory initiatives that could affect the terms and costs of interstate transportation of gas by interstate pipelines on behalf of natural gas shippers, including policy inquiries about gas quality and interchangeability, selective discounting of transportation services by pipelines to shippers, and proposed rules governing pipeline creditworthiness and collateral standards. Because these regulatory initiatives have not been made final, the approach the FERC will take and the potential impact on gas suppliers are not clear.
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.
In the event 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, certain of such operations must be conducted pursuant to certain on-site security regulations, bonding requirements and applicable permits issued by the BLM or Minerals Management Service (“MMS”), Bureau of Indian Affairs (“BIA”), 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 at some time in the future might be determined to be non-reciprocal under the Mineral Act.
See “Risk Factors” for a discussion of the risks to our international operations.
Environmental Regulations
General. The Company’s activities in the United States are subject to existing federal, state and local laws and regulations governing environmental quality, oil spills and pollution control and its activities in China are subject to the laws and regulations of China. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company’s operations, capital expenditures, earnings or competitive position.
The Company’s activities with respect to exploration, drilling and production 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 environmental regulation by state and federal authorities, including the Environmental Protection Agency (“EPA”). Such regulation can increase the cost of planning, designing, installing and operating such facilities. In most instances, the regulatory requirements relate to water and air pollution control measures.
Solid and Hazardous Waste. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for the exploration and production of oil and gas for many years. Although the Company utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed of or released on or under the properties that the Company currently owns or leases or properties that the Company has owned or leased or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties over whom the Company had no 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 gas wastes and properties have gradually become stricter over time. Under new laws, the Company could be required to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future, or mitigate existing, contamination.
The Company may generate wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under the RCRA and state analogs (“Hazardous Wastes”) and is considering the adoption of stricter disposal standards for nonhazardous wastes. Furthermore, certain wastes generated by the Company’s oil and gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under the RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.
Superfund. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability 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 (“PRPs”), include current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated and will generate wastes that fall within CERCLA’s definition of Hazardous Substances. The Company may also be an owner or operator of facilities on which Hazardous Substances have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages. 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 those federal actions that are major federal actions significantly affecting the quality of the human environment, the federal agency taking such action must follow certain steps in evaluating the environmental impacts of the federal action. This evaluation generally takes the form of 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 alternatives. Actions such as drilling on federal lands, to the extent the drilling requires federal approval, likely trigger the requirements of the National Environmental Policy Act, with few exceptions. Certain of the Company’s activities may trigger these requirements. The requirements of the National Environmental Policy Act may result in increased costs, significant delays and the imposition of restrictions or obligations, including the restriction or prohibition of drilling, upon the Company’s activities.
Oil Pollution Act The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the CWA, imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may 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 require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require the Company to forego construction, modification or operation of certain air emission sources.
Clean Water Act. The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges 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 the Company to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, the Company may be liable for penalties and costs.
Endangered Species Act. The Endangered Species Act (“ESA”) was established to provide a means to conserve the ecosystems upon which endangered and threatened species depend, to provide a program for
conservation of these endangered and threatened species, and to take the appropriate steps that are necessary to bring any endangered or threatened species to the point where measures provided for in the ESA are no longer necessary. The Company conducts operations on federal oil and gas leases that have species, such as sage grouse or other sensitive species, that potentially could be listed as threatened or endangered under the ESA. If a species is listed as threatened or endangered, the U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and 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 us to organize and/or disclose information about hazardous materials used or produced in its operations.
The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company.
Employees
As of February 28, 2005, the Company had 41 full time employees, including officers.
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this document, including without limitation, statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct. Important factors that could cause actual results to differ materially from the Company’s expectations are included throughout this document. The Cautionary Statements expressly qualify all subsequent written and oral forward-looking statements attributable to the Company or persons acting on the Company’s behalf.
Internal Control Systems. There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. 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 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 certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.
Competition. The Company competes with numerous other companies in virtually all facets of its business. The competitors in development, exploration, acquisitions and production include major integrated oil
and 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. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable prospects for future exploration and development.
Historically, the Company’s projects have been financed through debt and internally generated cash flow. There is competition for capital to finance oil and gas drilling. The ability of the Company to obtain such financing is uncertain and can be affected by numerous factors beyond its control. The inability of the Company to raise capital in the future could have an adverse effect its financial condition and results of operations.
Marketing of Oil and Natural Gas. The ability to market oil and natural gas depends on numerous factors beyond the Company’s control. These factors include:
• the extent of domestic production and imports of oil and natural gas;
• the availability of pipeline capacity;
• the effects of inclement weather;
• the demand for oil and natural gas by utilities and other end users;
• the availability of alternative fuel sources;
• the proximity of natural gas production to natural gas pipelines;
• state and federal regulations of oil and natural gas marketing; and
• federal regulation of natural gas sold or transported in interstate commerce.
Because of these factors, the Company may be unable to market all of the oil and natural gas that it produces, including oil and natural gas that may be produced from the Bohai Bay properties. In addition, the Company may be unable to obtain favorable prices for the oil and natural gas it produces.
Volatility of Oil and Gas Prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the Company’s control. 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 (“OPEC”), governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign oil and gas imports and the availability of alternate fuel sources and transportation interruption. Any substantial and extended decline in the price of oil or gas could have an adverse effect on the carrying value of the Company’s proved reserves, borrowing capacity, the Company’s ability to obtain additional capital, and the Company’s revenues, profitability and cash flows from operations.
Volatile oil and 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 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.
Price of Wyoming Production. The Company produces natural gas in Wyoming. The market price for this natural gas differs from the market indices for natural gas in the Gulf Coast region of the United States due potentially to insufficient pipeline capacity and/or low demand in the summer months for natural gas in the Rocky Mountain region of the United States. Therefore, the effect of a price decrease may more adversely affect the price received for the Company’s Wyoming production than production in the other U.S. regions.
Government Regulations. The Company’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:
• require that the Company acquire permits before commencing drilling;
• restrict the substances that can be released into the environment in connection with drilling and production activities;
• limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas;
• require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and
• require governmental approval of the overall development plan prior to the start of development of fields in China.
Under these laws and regulations, 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 maintains limited insurance coverage for sudden and accidental environmental damages, but does not maintain insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages. Accordingly, the Company may be subject to liability or may be required to cease production from properties in the event of environmental damages.
A significant percentage of the Company’s United States operations are conducted on federal lands. These operations are subject to a variety of on-site security regulations as well as other permits and authorizations issued by the BLM, the Wyoming Department of Environmental Quality and other agencies. A portion of the Company’s acreage is affected by winter lease stipulations that prohibit exploration, drilling and completing activities generally from November 15 to April 30, but allow production activities all year round. To drill wells in Wyoming, the Company is required to file an Application for Permit to Drill with the Wyoming Oil and Gas Conservation Commission. Drilling on acreage controlled by the federal government requires the filing of a similar application with the BLM. These permitting requirements may adversely affect the Company’s ability to complete its drilling program at the cost and in the time period currently anticipated. On large-scale projects, lessees may be required to perform environmental impact statements to assess the environmental impact of potential development, which can delay project implementation and/or result in the imposition of the environmental restrictions that could have a material impact on cost or scope.
Limited Financial Resources. The Company’s ability to continue exploration and development of its properties and to replace reserves may be dependent upon its ability to continue to raise significant additional financing, including debt financing that may be significant, or obtain some other arrangements with industry partners in lieu of raising financing. Any arrangements that may be entered into could be expensive to the Company. There can be no assurance that the Company will be able to raise additional capital in light of factors such as the market demand for its securities, the state of financial markets for independent oil companies (including the markets for debt), oil and 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 the Company’s capital budget.
The Company expects to continue using its bank credit facility to borrow funds to supplement its available cash flow. The amount the Company may borrow under the credit facility may not exceed a borrowing base determined by the lenders based on their projections of the Company’s future production, future production costs and taxes, commodity prices and other factors. The Company cannot control the assumptions the lenders use to calculate the borrowing base. The lenders may, without the Company’s consent, adjust the borrowing base at any time. If the Company’s borrowings under the credit facility exceed the borrowing base, the lenders may require that the Company repay the excess. If this were to occur, the Company may have to sell assets or seek financing from other sources. The Company can make no assurances that it 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.”
Interruptions from Severe Weather. The Company’s operations are conducted principally in the Rocky Mountain region. The weather in this area can be extreme and can cause interruption in the Company’s exploration and production operations. Moreover, especially severe weather can result in damage to facilities entailing longer operational interruptions and significant capital investment. Likewise, the Company’s Rocky Mountain operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to the Company’s facilities. A portion of the Company’s acreage is affected by winter lease stipulations that restrict the period of time during which operations may be conducted on the leases. The Company’s leases that are affected by the winter stipulations prohibit drilling and completing activities from mid-November to mid-May, but allow production activities all year round.
The Company Invests Heavily in Exploration. The Company has historically invested a significant portion of its capital budget in drilling exploratory wells in search of unproved oil and gas reserves. The Company cannot be certain that the exploratory wells it drills will be productive or that it will recover all or any portion of its investments. In order to increase the chances for exploratory success, the Company often invests in seismic or other geoscience data to assist it in identifying potential drilling objectives. Additionally, the cost of drilling, completing and testing exploratory wells is often uncertain at the time of the Company’s initial investment. Depending on complications encountered while drilling, the final cost of the well may significantly exceed that which the Company originally estimated. The Company uses the full cost method of accounting for exploration
and development activities as defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment and are then depleted using the unit of production method based on the Company’s proved reserves.
Replacement of Reserves. The Company’s future success may depend on its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, the Company’s reserves and production will decline. The Company can give no assurance that it will be able to find, develop or acquire additional reserves at acceptable costs.
Operating Hazards and Uninsured Risks. The oil and 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, gas leaks, and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by the Company could have a material adverse impact on the Company. The Company and the operators of its 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 the Company’s financial condition.
Drilling and Operating Risks. The Company’s oil and gas operations are subject to all of the risks and hazards typically associated with drilling for, and production and transportation of, oil and 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 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 the Company’s investment in such activity. If oil or 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.
Drilling Plans Subject to Change. This report includes certain descriptions of the Company’s future drilling plans with respect to its prospects. A prospect is an area which the Company’s geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. The Company’s prospects are in various stages of review. Whether or not the Company ultimately drills a prospect may depend on the following factors: receipt of additional seismic data or reprocessing of existing data; material changes in oil or gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; availability and cost of capital; changes in the estimates of costs to drill or complete wells; the approval of partners to participate in the drilling or, in the case of CNOOC, approval of expenditures for budget purposes; the Company’s ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; decisions of the Company’s joint working interest owners; and the BLM’s interpretation of the EIS and the results of the permitting process. The Company will continue to gather data about its prospects, and it is possible that additional information may cause the Company to alter its drilling schedule or determine that a prospect should not be pursued at all.
Financial Reporting Impact of Full Cost Method of Accounting. The Company follows the full cost method of accounting for its oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which the Company conducts exploration and/or production activities. Under such method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and gas prices in effect at the time of the calculation are held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and 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.
Risks Arising From Being Non-Operator in Bohai Bay. Because the Company is not the operator and holds a minority interest it cannot control the pace of exploration or development in the Bohai Bay properties or major decisions affecting drilling of wells or the plan for development and production, although contract
provisions give the Company certain consent rights in some matters. Kerr-McGee’s influence over these matters can affect the pace at which the Company spends money on this project. If Kerr-McGee were to shift its focus from this project, the pace of development of the Blocks could slow down or stop altogether. The Company currently does not believe it has sufficient funds to purchase Kerr-McGee’s interests in these Blocks if they were offered. On the other hand, if Kerr-McGee were to decide to accelerate development of this project, the Company could be required to fund its share of costs at a faster pace than anticipated, which might exceed its ability to raise funds. If, because of this, the Company were unable to pay its share of costs, it could lose or be forced to sell its interest in the Bohai Bay properties or be forced to not participate in the exploration or development of specific prospects or fields on the Blocks, potentially diminishing the value of its Bohai Bay assets.
Political, Economic or International Factors Affecting China. Ownership of property interests and production operations in areas outside the United States are subject to various risks inherent in foreign operations. These risks may include:
• loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrections;
• increases in taxes and governmental royalties;
• renegotiation of contracts with governmental entities and quasi-governmental agencies;
• change in laws and policies governing operations of foreign based companies;
• labor problems;
• other uncertainties arising out of foreign government sovereignty over its international operations; and
• currency restrictions and exchange rate fluctuations.
Tensions between China and its neighbors or various Western countries, regional political or military disruption, changes in internal Chinese leadership, social or political disruptions within China, a downturn in the Chinese economy, or a change in Chinese laws or attitudes toward foreign investment could make China an unfavorable environment in which to invest. Although all the foreign interest owners in the Bohai Bay properties have the right to sell production in the world market, the regulation of the concession by China, and the likely participation by CNOOC as a large working interest owner, make Chinese internal and external affairs important to the investment in the Bohai Bay. If any of these negative events were to occur, it could lead to a decision that there is an intolerable level of risk in continuing with the investment, or the Company may be unable to attract equity investors or lenders, or satisfy any then-existing lenders.
In the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in the United States or a potentially more favorable country.
In addition, the Company’s China PSCs terminate after 15 years of production, unless extended as provided for, which may be prior to the end of the productive life of the fields.
Operating Risks in China. Offshore operations, such as the Company’s Bohai Bay properties, are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and/or loss from storms or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, the Company could incur substantial liabilities that could result in financial losses or failures. China has many regulations similar to those addressed in Item I, Environmental Regulation, that may expose the Company to liability. Offshore projects, like the China field developments, are typically large, complex construction projects that are potentially subject to delays which may cause delays in achieving production and profitability.
Item 2.
Item 2. Properties.
Location and Characteristics
The Company is dependent on oil and gas leases in Wyoming and two petroleum contracts in China in order to explore for and produce oil and gas. The leases in Wyoming are primarily federal leases with 10-year lease terms until establishment of production. Production on the lease extends the lease terms until cessation of that production. There are approximately 93,865 gross (42,298 net) acres currently held by production. The China petroleum contracts are for a maximum of 30 years and are divided into 3 periods; exploration, development and production. The exploration period is for approximately 7 years and work is to be performed and expenditures are to be incurred to delineate the extent and amount of hydrocarbons, if any, for each block.
The development period occurs when a field is discovered and commences on the date of approval of the Ministry of Energy. There is no limit on the time allowed to develop a field. The production period of any oil and gas field in a block is a period of 15 consecutive years commencing on the date of commencement of commercial production from the field, unless extended.
Green River Basin, Wyoming
As of December 31, 2004, the Company owned developed oil and gas leases totaling 9,686 gross (4,022 net) acres in the Green River Basin of Sublette County, Wyoming which represents 93% of the Company’s total domestic developed gross acreage. The Company owned undeveloped oil and gas leases totaling 157,288 gross (88,975 net) acres in the Green River Basin of Sublette County, Wyoming which represents 91% of the Company’s total domestic undeveloped gross acreage. The Company’s acreage in the Green River Basin is primarily covering the Pinedale Anticline with several other undeveloped acreage blocks north and west of the Pinedale Anticline as well as acreage in the Jonah Field. Holding costs of leases in Wyoming not held by production were approximately $109,250 for the fiscal year ended December 31, 2004. The primary target on the Company’s Wyoming acreage is the tight gas sands of the upper Cretaceous Lance formation.
Exploratory Wells. During the year-ended December 31, 2004, the Company participated in the drilling and completion of a total of 32 gross (14.00 net) successful exploratory wells on the Green River Basin properties. At year end there were 14 gross (7.43 net) additional exploratory wells that commenced during the year that were either still drilling or had drilling operations suspended for winter.
Development Wells. During the year-ended December 31, 2004, the Company participated in the drilling and completion of 34 gross (14.48 net) successful development wells in the Pinedale Field area. At year end there were 4 gross (1.08 net) additional development wells that commenced during 2004 that were either still drilling or had drilling operations suspended for winter. For purposes of this report, development wells are wells identified as proven undeveloped locations by the Company’s independent petroleum engineering firm Netherland, Sewell & Associates, Inc. at the previous year-end reserve evaluation. When drilled, these locations will be counted as development wells.
Bohai Bay, China
Block 04/36: The Petroleum Sharing Contract (“PSC”) covering this block became effective October 1, 1994. Negotiations with the Chinese government in 2004 resulted in an extension of the third exploration term to September 2005. As the contract now stands, the exploration period will end at the end of September 2005. Barring an extension, at that time all acreage not under appraisal, development or production must be relinquished. The Company holds an 18.182% exploration interest in the exploration portion of the block and an 8.92% development interest in the CFD 11-1 & 11-2 field development portion. The Company holds 431,513 gross (78,536 net) acres under the exploration phase and 22,486 gross (2,006 net) acres under development, or 66% of the Company’s total gross international acreage.
Block 05/36: The PSC covering this block became effective March 1, 1996. Negotiations with the CNOOC at the end of 2004 resulted in an extension of the third exploration term to February 28, 2006 when, barring an extension, all acreage not under appraisal, development or production must be relinquished. The extension granted by CNOOC must be ratified by the Chinese Government which the foreign parties anticipate will happen. The Company holds a 15.00% exploration interest in this block which is 233,300 gross (34,995 net) acres, or 34% of the Company’s total gross international acreage.
Exploration/Appraisal Activity: In 2004 the Company participated in drilling one exploration well (0.182 net) which failed to find commercial quantities of oil. The primary target formations on the blocks are the Upper and Lower Minghuazhen, Guantao and Dongying formations.
Development Activity: In July of 2004, the Company started production at the CFD 11-1 & 11-2 fields on the 04/36 Block. The field currently consists of two production platforms and an anchored FPSO vessel. During start up of the initial (Phase 1) development in 2004, the Company participated in drilling 33 gross (2.94 net) oil producers and 3 gross (0. 27 net) water injection wells into the primary producing horizons of the Upper and Lower Minghuazhen, Guantao and Dongying formations. At completion of Phase 2 of the development in early 2006, as many as 65 wells may have been drilled in the two fields.
Under the PSC, the Company is responsible for 18.182% of all expenses incurred on any portion of the blocks not declared as development areas (“Exploration Interest”). Upon declaration of commerciality of a field
or area by CNOOC, the Company’s share of all expenses within that area is decreased by 51%, with the participation by CNOOC, to 8.92% (“Development Interest”). Upon initiation of production, the sharing of production is determined by the language of the PSC which (in general terms) states that for each individual field: 1) a Chinese National Industrial Tax (VAT) and Royalty are applied to 100% of the gross volumes of oil, 2) Lease Operating Expenses (LOE) are then taken out of the remainder oil and 3) after these deductions, 62.5% of the remaining production stream is dedicated to Exploration and Development Cost Recovery for the participants. The Exploration Cost Recovery shall be recovered without interest, while the Development Cost Recovery shall be calculated with a fixed annual interest rate of nine (9%) percent uplift, and 4) the remaining 37.5% of production goes to the “remainder oil” category which is divided into a “share oil” for CNOOC and an “allocable remainder oil” for the contractors determined by a sliding scale (determined by yearly production) “X” factor. Project profit is subject to Chinese Corporate tax.
On October 16, 2003, a 15 year contract which provides for extensions for up to an additional 10 years was signed by the operator to lease the FPSO. The Company ratified the contract for its net share which is 8.92%. The FPSO is a 110,000-150,000 dead weight tons (“DWT”), double-hull FPSO with a 900,000-1,100,000 barrels storage capacity, with Single Point Mooring (“SPM”) and a processing plant capable of processing 60,000 barrels oil/day (expandable to 80,000 barrels oil/day). The FPSO service agreement calls for a day rate lease payment and a sliding scale per barrel payment that decreases based on cumulative barrels processed.
Pennsylvania
The Company owns 15,518 gross (14,652 net) acres in Pennsylvania, which represents 9% of the Company’s total domestic undeveloped gross acreage. A location has been selected and permitted for the drilling of an initial test well on this acreage in 2005. The drilling objectives in this area are the carbonates of the Ordovician age Trenton and Black River formations. These objectives have been the target of ongoing successful exploration efforts by other operators in portions of New York state, just north of the Company’s prospect area in Pennsylvania.
Texas
The Company operates one gross (0.66 net) well and owns working interests in an additional two gross (0.22 net) wells in Texas and owns 720 gross (382 net) developed acres which represents 7% of the Company’s total developed gross acreage. In 2003 the Company leased 15,121 gross (11,002 net) acres in Edwards County, Texas. The Company drilled one gross (0.73 net) well on this Edwards County acreage in 2004 that was unsuccessful and the Company subsequently dropped the acreage.
Oil and Gas Reserves
The following table sets forth the Company’s quantities of domestic proved reserves, for the years-ended December 31, 2004, 2003 and 2002 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. The table summarizes the Company’s domestic proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2004, 2003 and 2002. In accordance with Ultra’s three-year planning and budgeting cycle, proved undeveloped reserves included in this table include only economic locations that are forecast to be on production before January 1, 2008. Proved undeveloped reserves represent 63.6% of total proved reserves.
The following table sets forth the Company’s quantities of proved reserves in China, for the year-ending December 31, 2004, as estimated by independent petroleum engineers Ryder Scott Company. In accordance with the Company’s new field reserve booking policy, proved reserves were booked after production commenced. The table summarizes the Company’s proved reserves in China, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2004. In accordance with Ultra’s three-year planning and budgeting cycle, proved undeveloped reserves included in this table include only economic locations that are forecast to be on production before January 1, 2008. Proved undeveloped reserves represent 42.6% of total proved reserves.
The following table sets forth the Company’s quantities of total proved reserves both domestically and in China, for the years-ended December 31, 2004, 2003 and 2002 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. and Ryder Scott Company. The table summarizes the Company’s total proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2004, 2003 and 2002. In accordance with Ultra’s three-year planning and budgeting cycle, proved undeveloped reserves included in this table include only economic locations that are forecast to be on production before January 1, 2008. Proved undeveloped reserves represent 63.0% of total proved reserves.
Production Volumes, Average Sales Prices and Average Production Costs
The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with Ultra’s sale of oil and natural gas for the periods indicated.
*
Average production costs include lifting costs and remedial workover expenses.
Productive Wells
As of December 31, 2004, the Company’s total gross and net wells were as follows:
*
Productive wells are producing wells plus shut-in wells the Company deems capable of production. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests the Company owns in gross wells.
Oil and Gas Acreage
As of December 31, 2004, the Company had total gross and net developed and undeveloped oil and gas leasehold acres in the United States as set forth below. The developed acreage is stated on the basis of spacing units designated by state regulatory authorities. The acreage and other additional information concerning the Company’s oil and gas operations are presented in the following tables.
United States Acreage:
As of December 31, 2004, the Company had total gross and net developed and undeveloped oil and gas leasehold acres in the Bohai Bay, China as set forth below.
Bohai Bay Acreage:
Drilling Activities
For each of the three fiscal years ended December 31, 2004, 2003 and 2002, the number of gross and net wells drilled by the Company was as follows:
Wyoming - Green River Basin
At year end there were 4 gross (1.08 net) additional development wells that were either drilling or had drilling operations suspended over winter.
At year end there were 14 gross (7.43 net) additional exploratory wells that were either drilling or had drilling operations suspended over winter.
Texas
China - Bohai Bay
*
A successful appraisal well is a well that is drilled into a formation shown to be productive of oil or gas by an earlier well for the purpose of obtaining more information about the reservoir.
Item 3.
Item 3. Legal Proceedings.
The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of the Company’s security holders during the fourth quarter of the fiscal year ended December 31, 2004.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities.
The common shares of the Company have been listed and posted for trading on the American Stock Exchange (“AMEX”) since January 17, 2001 under the symbol “UPL” and were traded on the Toronto Stock Exchange (“TSE”) from September 30, 1998 to March 31, 2004 under the symbol “UP”. The following table sets forth the high and low closing sales prices on the AMEX and TSE for 2004 and 2003 as reported by each exchange, respectively.
AMERICAN STOCK EXCHANGE (US$)
TORONTO STOCK EXCHANGE (CDN$)
AMERICAN STOCK EXCHANGE (US$)
TORONTO STOCK EXCHANGE (CDN$)
On February 28, 2005, the last reported sale price of the common stock on the AMEX was $56.35 per share. As of February 28, 2005 there were approximately 415 holders of record of the common stock.
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. In addition, the Company’s current credit facility prohibits payment of dividends on its common stock.
Item 6.
Item 6. Selected Financial Data
.
The selected consolidated financial information presented below for the years ended December 31, 2004, 2003, 2002, 2001 and 2000 is derived from the Consolidated Financial Statements of the Company.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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 segment, natural gas and oil exploration and development with two geographical segments, the United States and China.
The Company currently generates the majority of its revenue, earnings and cash flow from the production and sales of natural gas and oil from its property in southwestern Wyoming. The price of natural gas in the southwest Wyoming region is a critical factor to the Company’s business. The price of gas in southwest Wyoming historically has been volatile. The average annual realizations for the period 2001-2004 have ranged from $2.33 to $5.13 per Mcf. This volatility could be very detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into forward sales and derivative contracts for gas in southwest Wyoming. The average realization for the Company’s gas during calendar 2004 was $5.13 per Mcf, basis Opal, Wyoming, including the effect of hedges. For the quarter ended December 31, 2004, the average realization for the Company’s gas was $5.70 per Mcf, basis Opal, Wyoming, including the effect of hedges.
On July 18, 2004 the Company initiated production at the first two fields of the nine fields discovered on its oil properties offshore Bohai Bay, China. Production from these fields is characterized as a Heavy, Sweet Crude. The Company sold its first cargos of oil in September 2004. At that time, the price of oil in east Asia became much more relevant to the Company. During the twelve-month period ended December 31, 2004, the Company sold 593,332 barrels of its Chinese oil production at a price based on the official ICP posting for Duri field crude, less a discount for location and quality differences. These sales were made to an affiliate of CNOOC, Ltd., the Company’s Chinese partner, at an average price of $32.31 USD per barrel. For the quarter ended December 31, 2004, the Company sold 288,818 barrels of its Chinese crude for an average price of $27.66. There can and will be differences in timing between the sale of the Company’s crude oil cargos and the Company’s pro-rata share of production. As of February 28, 2005, the Duri price was approximately $39.04 USD (before discount) per barrel.
The Company expects to sell at least one cargo of its Chinese crude oil production approximately every two months during 2005. The Company has the right to export and sell its crude at market prices into the international markets, and is evaluating options to do so in the future. Other markets for the Company’s Chinese oil may be potentially developed in South Korea, Japan, Singapore or other countries.
The Company has grown its natural gas and oil production significantly over the past four years and management believes it has the ability to continue growing production by drilling already identified locations on its leases in Wyoming and by bringing into production the already discovered oil fields in China. The Company delivered 74.5% production growth on an Mcfe basis during the quarter ended December 31, 2004 as compared to the same quarter in 2003 and 70.7% for the year-ended December 31, 2004 compared to the same period in 2003. Management expects to deliver additional production growth during 2005 by drilling and bringing into production additional wells in Wyoming and bringing into production the next two fields in China.
The Company conducts operations in both the United States and China. Separate cost centers are maintained for each country in which the Company has operations. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities. Inflation has not had a material impact on the Company’s results of operations and is not expected to have a material impact on the Company’s results of operations in the future.
Critical Accounting Policies
The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. 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.
Use of Estimates. The more significant areas requiring the use of assumptions, judgments and estimates relate to volumes of oil and gas reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations and the amount of abandonment obligations used in such calculations. Assumptions, judgments and estimates are also required in determining impairments of undeveloped properties and the valuation of deferred tax assets.
Oil and Gas Reserves. The Company emphasizes that the volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. These estimates are currently made annually by independent petroleum engineers and reviewed by the Company’s engineers. The reserves are periodically reviewed and revised, either upward or downward, if warranted by additional data. Revisions are necessary due to changes in assumptions based on, among other things, reservoir performance, prices, economic conditions and governmental restrictions. 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 could also result in a full cost ceiling writedown (see discussion below).
The present value of oil and gas properties represents the estimated future net cash flows from proved oil and gas reserves, discounted using a prescribed 10% discount rate (“PV 10”). Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered “proved” if they can be produced economically as demonstrated by either actual production or conclusive formation tests. “Proved developed” oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
Due to the volatility of commodity prices, the oil and gas prices on the last day of the period significantly impact the calculation of the PV 10. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas.
Full Cost Method of Accounting. The Company uses the “full cost method” of accounting for its oil and gas operations. 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. Effective with the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations,” the carrying amount of oil and gas properties includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. The sum of net capitalized costs and estimated future development costs of oil and gas properties for each full cost center are depleted using the units-of-production method. Changes in estimates of reserves, future development costs or asset retirement obligations are accounted for prospectively in our depletion calculation.
Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.
Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test 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 on a country-by-country basis. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves. For purposes of the full cost ceiling calculation, future cash outflows associated with settling asset retirement obligations that have been accrued on the Company’s balance sheet are excluded from the computation of the present value of estimated future net revenues. This ceiling is compared to the net book value of the oil and gas properties
reduced by any related deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash writedown is required. A ceiling test impairment can give the Company a significant loss for a particular period; however, future depletion, depreciation and amoritization expense would be reduced.
The Company did not have any writedowns related to the full cost ceiling limitation in 2004, 2003 or 2002. As of December 31, 2004, the ceiling limitation exceeded the carrying value of the Company’s oil and gas properties by approximately $1.3 billion in the U.S. and $110 million in China. Estimates of discounted future net cash flows at December 31, 2004 were based on average natural gas prices of approximately $5.54 per MCF in the U.S. and on average liquids prices of approximately $42.80 per barrel in the U.S. In China, estimates of discounted future net cash flows on crude oil were based on a net realized price of $29.46 per barrel. A reduction in oil and gas prices and/or estimated quantities of oil and gas reserves would reduce the ceiling limitation in the U.S. and could result in a ceiling test writedown.
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 gas properties. SFAS No. 143 requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A.
Entitlements Method of Accounting for Oil and Gas Sales. The Company generally sells natural gas, condensate and crude oil under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. The Company accounts for oil and 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. Under the alternative “sales method” of accounting for oil and gas sales, revenue would be recorded based on volumes taken by the Company or allocated to it by third parties, regardless of whether such volumes are more or less than its ownership share of volumes produced. Reserve estimates would be adjusted to reflect any over-produced or under-produced positions. Receivables or payables would be recognized on a company’s balance sheet only to the extent that remaining reserves are not sufficient to satisfy volumes over- or under-produced.
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 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 bases (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. In order to fully realize its U.S. net deferred tax asset at December 31, 2004, the Company will need to generate future taxable income prior to the expiration of the net operating loss carryforwards in 2005 to 2024. Based upon the level of historical taxable income and projections for future taxable income over the periods which the deferred tax assets are deductible, management believes it is more likely than not the Company will realize the benefits of these
deductible differences at December 31, 2004. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward periods are reduced.
Commodity Derivative Instruments and Hedging Activities. The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company primarily utilizes price swaps, which are generally placed with major financial institutions or with counter-parties of high credit quality that it believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices the Company receives. Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. The Company currently does not have any derivative contracts in place that do not qualify as cash flow hedges.
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.
Results of Operations - Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Oil and gas revenues increased to $258.0 million for the year ended December 31, 2004 from $121.6 million for the same period in 2003. This increase was attributable to an increase in both the Company’s production and prices received for that production. During this period the Company’s production increased to 43.7 Bcf of gas and 349.7 thousand barrels of condensate in Wyoming and 593.3 thousand barrels of crude oil in China, up from 27.6 Bcf of gas and 211.6 thousand barrels of condensate in Wyoming. This 71% increase on a Mcfe basis was attributable to the Company’s successful drilling activities during 2004 and 2003 in Wyoming and initiation of production in China. During the year ended December 31, 2004 the average product prices were $5.13 per Mcf and $41.92 per barrel of condensate in Wyoming and $32.31 per barrel for crude oil in China, compared to $4.16 per Mcf and $31.86 per barrel in Wyoming for the same period in 2003.
In Wyoming, direct lease operating (LOE) costs increased to $6.3 million in 2004 from $3.6 million in 2003 due to sharply higher production. On a unit of production basis, LOE costs were $0.14 per Mcfe in 2004, as compared to $0.13 per Mcfe in 2003. Production taxes in 2004 were $28.2 million, compared to $13.8 million in 2003, or $0.57 per Mcfe in 2004, compared to $0.48 per Mcfe in 2003. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased the cost on a per unit basis. Gathering fees for the period increased to $13.1 million in 2004 from $7.8 million in 2003, attributable to higher production volumes.
In Wyoming, depletion, depreciation and amortization (“DD&A”) expenses increased to $27.4 million during the year ended December 31, 2004 from $16.2 million for the same period in 2003, attributable to increased production volumes and higher depletion rate, attributable to forecasted increased future development costs. On a unit basis, DD&A increased to $0.60 per Mcfe in 2004 from $0.56 per Mcfe in 2003.
In China, production costs were $2.3 million in 2004, or $0.64 per Mcfe or $3.85 per BOE. DD&A was $2.9 million or $0.82 per Mcfe or $4.89 per BOE in 2004. Production in China started during July 2004.
Interest expense for the period increased to $3.8 million in 2004 from $2.8 million in 2003. This increase was attributable to the increase in borrowings under the senior credit facility combined with increasing interest rates.
Deferred income tax expense for the period increased to $58.0 million in 2004 from $25.3 million in 2003. This increase was attributable to an increase in net income from continuing operations. Deferred income taxes were booked at the rate of 34.7% as compared to a rate of 35.8% in 2003. The Company was not liable for current payment of any material amount of income taxes for the period ending December 31, 2004.
Results of Operations - Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Oil and gas revenues increased to $121.6 million for the year ended December 31, 2003 from $42.3 million for the same period in 2002. This increase was attributable to an increase in both the Company’s production and prices received for that production. During this period the Company’s production increased to 27.6 Bcf of gas and 211.6 thousand barrels of condensate, up from 16.5 Bcf of gas and 151.2 thousand barrels of condensate for the same period in 2002. This 66% increase on a Mcfe basis was attributable to the Company’s successful drilling activities during 2003 and 2002. During the year ended December 31, 2003 the average product prices were $4.16 per Mcf and $31.86 per barrel, compared to $2.33 per Mcf and $25.39 per barrel for the same period in 2002.
Production costs increased to $3.6 million in 2003 from $2.4 million in 2002 primarily due to increased production. On a unit of production basis, costs were $0.13 per Mcfe in 2003, as compared to $0.14 per Mcfe in 2002. Production taxes in 2003 were $13.8 million, compared to $4.1 million in 2002, or $0.48 per Mcfe in 2003, compared to $0.24 per Mcfe in 2002. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased the cost on a per unit basis. Gathering fees for the period increased to $7.8 million in 2003 from $4.9 million in 2002, attributable to higher production volumes.
Depletion, depreciation and amortization (“DD&A”) expenses increased to $16.2 million during the year ended December 31, 2003 from $9.7 million for the same period in 2002, also attributable to increased production volumes. On a unit basis, DD&A remained flat at $0.56 per Mcfe in 2003.
Interest expense for the period increased to $2.8 million in 2003 from $2.7 million in 2002. This increase was attributable to the increase in borrowings under the senior credit facility which was partially offset by lower interest rates.
Deferred income tax expense for the period increased to $25.3 million in 2003 from $5.1 million in 2002. This increase was attributable to an increase in net income from continuing operations. Deferred income taxes were booked at the rate of 35.8% as compared to a rate of 38.5% in 2002. The Company was not liable for current payment of any material amount of income taxes for the period ending December 31, 2003.
At year-end 2003, the Company had an inventory account of $13.6 million as compared to $0.0 at year-end 2002. This inventory is tubular materials related to the purchase of pipe for the Company’s operated drilling program in Wyoming. In previous years the Company did not purchase tubular materials prior to when they would be used.
Liquidity and Capital Resources
In the year-ended December 31, 2004, the Company relied on cash provided by operations and borrowings under its senior credit facility to finance its capital expenditures. The Company participated in the drilling of 84 wells in Wyoming and continued to participate in the development process in the China blocks, including the ongoing drilling of development wells. Due to this continued development in China, the Company saw first production from these properties in July 2004. For the year-ended December 31, 2004 net capital expenditures were $174.1 million. At December 31, 2004, the Company reported a cash position of $16.9 million compared to $1.8 million at December 31, 2003. Working capital deficit at December 31, 2004 was $(10.0) million as compared to $(22.1) million at December 31, 2003. As of December 31, 2004, the Company had incurred bank indebtedness of $102.0 million and other long-term obligations of $9.3 million comprised of items payable in more than one year, primarily related to production taxes.
The Company’s positive cash provided by operating activities, along with the availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital expenditures for 2005, which are currently projected to be $290.0 million. Of the $290.0 million budget, the Company plans to spend
approximately $263.0 million of its 2005 budget in Wyoming and approximately $20.0 million in China with the balance allocated to evaluating other areas. With the $263.0 million for Wyoming, the Company plans to drill or participate in an estimated 100 gross wells in 2005, of which approximately 30% will be for exploration wells and the remaining will be for development wells. Of the $20.0 million budgeted for China, approximately 14% will be for exploratory/appraisal activity and the balance will be for development activity. The Company currently has no budget for acquisitions in 2005.
The Company (through its subsidiary) participates in a long-term credit facility with a group of banks led by Bank One N.A. The agreement specifies a maximum loan amount of $500 million and an aggregate borrowing base of $400 million and a commitment amount of $200 million at November 1, 2004. The commitment amount may be increased up to the lesser of the borrowing base amount or $500 million at any time at the request of the Company. Each bank shall have the right, but not the obligation, to increase the amount of their commitment as requested by the Company. In the event that the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to bring additional banks into the facility. At December 31, 2004, the Company had $102 million outstanding and $98 million unused and available under the current committed amount.
The credit facility matures on May 1, 2008. The note bears interest at either the bank’s prime rate plus a margin of one-quarter of one percent (0.25%) to seven-eighths of one percent (0.875%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and one-quarter percent (1.25%) to one and seven-eighths of one percent (1.875%) based on the percentage of available credit drawn. For the purposes of calculating interest, the available credit is equal to the borrowing base. An average annual commitment fee of 0.30% to 0.50%, depending on the percentage of available credit drawn, is charged quarterly for any unused portion of the commitment amount.
The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the banks and may be decreased or increased depending on a number of factors, including the Company’s proved reserves and the bank’s forecast of future oil and gas prices. If the borrowing base is reduced to an amount less than the balance outstanding, the Company has sixty days from the date of written notice of the reduction in the borrowing base to pay the difference. Additionally, the Company is subject to quarterly reviews of compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital and advances to Sino-American Energy Corporation. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility. As of December 31, 2004, the Company was in compliance with required ratios of the bank facility.
The debt outstanding under the credit facility is secured by a majority of the Company’s proved domestic oil and gas properties.
During the year ended December 31, 2004, net cash provided by operating activities was $175.3 million as compared to $90.1 million for the year ended December 31, 2003. The increase in cash provided by operating activities was primarily attributable to the increase in earnings, DD&A and deferred taxes, all attributable to higher production levels.
During the year ended December 31, 2004, cash used in investing activities was $165.0 million as compared to $103.6 million for the year ended December 31, 2003. The change is primarily attributable to increased activity for drilling and completion operations in Wyoming. The $173.1 million used in oil and gas property expenditures consists of $195.6 million incurred for drilling and completion activities in 2004, offset by $(22.5) million attributable to capital expenditures incurred but not yet paid.
During the year ended December 31, 2004, cash provided by financing activities was $4.8 million as compared to $14.0 million for the year ended December 31, 2003. The change is primarily attributable to drawing down additional debt under the senior credit facility and proceeds of employee stock option exercises.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2004:
As of December 31, 2004 the Company had committed to drilling obligations in progress that will continue into 2005.
The Company’s senior credit facility with its group of banks matures on May 1, 2008. Unless the facility is extended or a new facility put into place, the full amount drawn under the facility would become due and payable at that time. The Company believes that it will be able to extend or renew the facility or one substantially similar to the existing facility prior to May 1, 2008.
On October 16, 2003 the operator of the Company’s properties in China, Kerr-McGee (“Operator”), signed a 15 year contract, which provides for up to an additional 10 years, to lease the FPSO. The Company ratified the contract for its net share which is 8.92%. The FPSO service agreement calls for a day rate lease payment and a sliding scale per barrel processing fee that decreases based on cumulative barrels processed. The lease contains a cancellation fee for the Company based on a sliding time-scale (cancellation fee decreases with time) which as of December 31, 2004 was $3.87 million net to the Company’s 8.92% interest. The Company considers it very unlikely that a lease cancellation situation will occur. Due to the terms of the lease, the Company cannot estimate with any degree of accuracy the costs it may incur during the life of the lease. The Company’s net share for the costs of the FPSO in 2004 was approximately $1.3 million.
In May 2003 the Company amended its prior office lease in Englewood, Colorado, which it has committed to through June 2008. The Company’s total remaining commitment of this lease is $702,441. In December 2003, the Company signed a lease for office space in Houston, Texas, which it has committed to through April 2007 for a total remaining commitment of $121,643. The total remaining commitment for both offices is $824,083.
Additionally, in maintaining its acreage base that is not held by production, the Company incurs certain expenses including delay rental costs. From year to year, the Company’s acreage base varies, sometimes dramatically, rendering it impossible to forecast with any accuracy what the amount of these holding expenses will be. In 2004, total holding costs for all of the Company’s leases not held by production were $109,250.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s major market risk exposure is in the pricing applicable to its 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 gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations ranged from a monthly low of $4.64 per Mcf to a monthly high of $6.15 per Mcf during 2004. Realized natural gas prices are derived from the financial statements which include the effects of hedging and gas balancing.
The Company uses derivative instruments as one way to manage its exposure to commodity prices. The Company has periodically entered into fixed price to index price swap agreements in order to hedge a portion of its production. The purpose of the swaps is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices on the hedged volumes. The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment of the changes in fair value as specified in SFAS No. 133 is dependent upon whether or not a derivative instrument is
designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as oil and gas revenue. For all other derivatives, changes in fair value are recognized in earnings as income or expense. At December 31, 2004 the Company had a current derivative liability of $3,739,406, which is included in current liabilities in our balance sheet. The Company designates these derivatives as cash flow hedges.
During 2004, the Company made payments on financially settled swaps to counterparties totaling $8,493,300 as its net cost from hedging activities. This total includes $1,383,300 for the first quarter of 2004, $1,870,725 for the second quarter of 2004, $1,988,700 for the third quarter of 2004, and $3,250,575 for the fourth quarter of 2004.
At December 31, 2004, the Company had the following open derivative contracts to manage price risk on a portion of its natural gas production (all prices southwest Wyoming basis). (The Company’s gas contains approximately 1.06 MMBtu per Mcf upon delivery at the sales point.)
*
Unrealized losses are not adjusted for income tax effect.
The Company also utilizes fixed price forward gas sales at southwest Wyoming delivery points to hedge its commodity exposure. In addition to the derivative contracts discussed above, the Company had the following physical delivery contracts in place at December 31, 2004. (The Company’s average net interest in physical gas sales is approximately 80%.)
Subsequent to December 31, 2004 and through March 2, 2005, the Company has entered into additional contracts for fixed price physical delivery of gas during Calendar 2006 for an additional 25,000 MMBTU/day at an average price of $6.015 per MMBTU.
As of March 2, 2005, the Company’s fixed price forward gas sales contracts represented net volumes equal to approximately 45% of the Company’s currently forecasted production for Calendar 2005 and 19% for Calendar 2006.
Item 8.
Item 8. Financial Statements and Supplementary Data.
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 principal executive officer and principal 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, 2004.
Michael D. Watford
Chief Executive Officer
March 15, 2005
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Ultra Petroleum Corp.
We have audited management’s assessment, included in the accompanying Management’s Report On Internal Control Over Financial Reporting, that Ultra Petroleum Corp. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Ultra Petroleum Corp. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Ultra Petroleum Corp. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations and retained earnings, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 15, 2005 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Denver, Colorado
March 15, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Ultra Petroleum Corp.
We have audited the consolidated balance sheets of Ultra Petroleum Corp. and subsidiaries as of December 31, 2004 and 2003, and the consolidated statements of operations and retained earnings, shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ultra Petroleum Corp. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in accordance with U.S. generally accepted accounting principles.
As explained in Note 1 to the Financial Statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Ultra Petroleum Corp. and subsidiaries internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG, LLP
Denver, Colorado
March 15, 2005
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
Approved on behalf of the Board:
, Director
, Director
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
See accompanying notes to consolidated financial statements.
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
See accompanying notes to consolidated financial statements.
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOW
See accompanying notes to consolidated financial statements.
ULTRA PETROLEUM CORP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in U.S. dollars unless otherwise noted)
Years ended December 31, 2004, 2003 and 2002
DESCRIPTION OF THE BUSINESS
Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil and gas properties. The Company is incorporated under the laws of the Yukon Territory, Canada. The Company’s principal business activities are in the Green River Basin of southwest Wyoming and Bohai Bay, China.
1. SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries UP Energy Corporation, Ultra Resources, Inc. and Sino-American Energy Corporation. The Company presents its financial statements in accordance with U.S. GAAP. All material inter-company transactions and balances have been eliminated upon consolidation.
(b) Accounting principles: The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States.
(c) Cash and cash equivalents: We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
(d) Restricted cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. Wyoming law requires that these funds be held in a federally insured bank in Wyoming.
(e) Capital assets: Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life.
(f) Oil and gas properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
The sum of net capitalized costs and estimated future development costs of oil and gas properties are amortized using the unit-of-production method based on the proven reserves as determined by independent petroleum engineers. Oil and gas reserves and production are converted into equivalent units based on relative energy content. Operating fees received related to the properties in which the Company owns an interest are netted against expenses. Fees received in excess of costs incurred are recorded as a reduction to the full cost pool. Effective with the adoption of SFAS 143 asset retirement obligations are included in the base costs for calculating depletion.
Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The
amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (DD&A) pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information.
Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, generally using prices in effect at the end of the period held flat for the life of production excluding the estimated abandonment cost for properties with asset retirement obligations recorded on the balance sheet and including the effect of derivative contracts that qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development. The effect of implementing SFAS 143 has no effect on the ceiling test calculation as the future cash outflows associated with settling asset retirement obligations are excluded from this calculation.
(g) Inventories: Crude oil products and merchandise inventories are carried at the lower of current market value or cost. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less. Inventory at December 31, 2004 includes depletion and lease operating expenses of $628,311, associated with the Company’s crude oil production in China.
(h) Derivative transactions: The Company has entered into commodity price risk management transactions to manage its exposure to gas price volatility. These transactions are in the form of price swaps with financial institutions and other credit worthy counterparties. These transactions have been designated by the Company as cash flow hedges. As such, unrealized gains and losses related to the change in fair market value of the derivative contracts are recorded in other comprehensive income in the balance sheet to the extent the hedges are effective.
(i) Income taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
(j) Earnings per share: Basic earnings per share is computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.
The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2004, 2003 and 2002:
(k) Use of estimates: Preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(l) Reclassifications: Certain amounts in the financial statements of the prior years have been reclassified to conform to the current year financial statement presentation.
(m) Accounting for stock-based compensation: SFAS No. 123 defines a fair value method of accounting for employee stock options and similar equity instruments. SFAS No. 123 allows for the continued measurement of compensation cost for such plans using the intrinsic value based method prescribed by APB Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), provided that pro forma results of operations are disclosed for those options granted. The Company accounts for stock options granted to employees and directors of the Company under the intrinsic value method. Had the Company reported compensation costs as determined by the fair value method of accounting for option grants to employees and directors, net income and net income per common share would approximate the following pro forma amounts:
For purposes of pro forma disclosures, the estimated fair value of options is amortized to expense over the options’ vesting period. The weighted-average fair value of each option granted is estimated on the date of grant using the Black Scholes option pricing model with the following assumptions: at December 31, 2004, expected volatility of 38.4% and a risk free rate of 3.713% at December 31, 2003, expected volatility of 25.0% and a risk free rate of 4.35% and at December 31, 2002, expected volatility of 30.0% and a risk free rate of 4.85%. At December 31, 2004 options have expected lives of 6.5 years, and at December 31, 2003 and 2002 options had expected lives of ten years.
(n) Revenue Recognition. Natural gas revenues are recorded on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest. The Company records its entitled share of revenues based on estimated production volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes that are supported by third party pipeline statements or cash receipts. Since there is a ready market for natural gas, the Company sells the majority of its products soon after production at various locations at which time title and risk of loss pass to the buyer. Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2004 and 2003, the Company had net gas imbalance receivables of $2 million in both years.
Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title is transferred.
(o) Impact of recently issued accounting pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (FAS 123R), “Share-based Payment.” FAS 123R requires compensation costs related to share-based payments to be recognized in the income statement over the vesting period. The amount of the compensation cost will be
measured based on the grant-date fair value of the instrument issued. FAS 123R is effective as of July 1, 2005, for all awards granted or modified after that date and for those awards granted prior to that date that have not vested. Beginning after July 1, 2005 the Company will begin expensing share based compensation. All outstanding awards issued prior to this date will have fully vested.
2. ASSET RETIREMENT OBLIGATIONS:
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company has recorded a liability of $744,512 ($321,506 U.S and $423,006 China) to account for future obligations associated with its assets in both the United States and China.
3. OIL AND GAS PROPERTIES:
4. CAPITAL ASSETS:
5. LONG-TERM LIABILITIES:
Bank indebtedness: The Company (through its subsidiary) participates in a revolving credit facility with a group of banks led by Bank One N.A. The agreement specifies a maximum loan amount of $500 million and an aggregate borrowing base of $400 million and a commitment amount of $200 million at November 1, 2004. The commitment amount may be increased up to the lesser of the borrowing base amount or $500 million at any time at the
request of the Company. Each bank shall have the right, but not the obligation, to increase the amount of their commitment as requested by the Company. In the event that the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to bring additional banks into the facility. At December 31, 2004, the Company had $102 million outstanding and $98 million unused and available under the current committed amount.
The credit facility matures on May 1, 2008. The note bears interest at either the bank’s prime rate plus a margin of one-quarter of one percent (0.25%) to seven-eighths of one percent (0.875%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and one-quarter percent (1.25%) to one and seven-eighths of one percent (1.875%) based on the percentage of available credit drawn. For the purposes of calculating interest, the available credit is equal to the borrowing base. An average annual commitment fee of 0.30% to 0.50%, depending on the percentage of available credit drawn, is charged quarterly for any unused portion of the commitment amount. In 2004 the Company’s total commitment fee was $374,096, $249,788 in 2003 and $13,791 in 2002.
The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the banks and may be decreased or increased depending on a number of factors, including the Company’s proved reserves and the bank’s forecast of future oil and gas prices. If the borrowing base is reduced to an amount less than the balance outstanding, the Company has sixty days from the date of written notice of the reduction in the borrowing base to pay the difference. Additionally, the Company is subject to quarterly reviews of compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital and advances to Sino-American Energy Corporation. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility. As of December 31, 2004, the Company was in compliance with required ratios of the bank facility.
The debt outstanding under the credit facility is secured by a majority of the Company’s proved domestic oil and gas properties.
Other long-term obligations: These costs relate to the long-term portion of production taxes payable, a liability associated with imbalanced production, the long-term portion of the fair value estimate of our hedging liability and our asset retirement obligations mentioned in Note 2.
6. STOCK BASED COMPENSATION:
The Company’s Stock Incentive Plans are administered by the board of directors (the “Plan Administrator”). The Plan Administrator may make awards of stock options to employees, directors, officers and consultants of the Company as long as the aggregate number of common shares issuable to any one person pursuant to incentives does not exceed 5% of the number of common shares outstanding at the time of the award. In addition, no participant may receive during any fiscal year of the Company’s awards of incentives covering an aggregate of more than 500,000 common shares. The Plan Administrator determines the vesting requirements and any vesting restrictions or forfeitures in certain circumstances. Incentives may not have an exercise period longer than 10 years. The exercise price of the stock may not be less than the fair market value of the common shares at the time of award, where “fair market value” means the weighted average trading price of the common shares for the five trading days preceding the date of the award. The following table summarizes the changes in stock options for the three-year period ended December 31, 2004:
No compensation resulted from the granting of these options as all were granted at or above the market value of the common shares at the date of grant. Stock options granted to consultants have been assessed at fair value and capitalized to the full cost pool based on the nature of the services provided by the consultants. The Company’s stock options vest each quarter over a one-year period. At December 31, 2004, all stock options granted to date were fully vested.
The following table summarizes information about the stock options outstanding at December 31, 2004:
7. DERIVATIVE FINANCIAL INSTRUMENTS:
The Company uses derivative instruments as one way to manage its exposure to commodity prices. The Company has periodically entered into fixed-price to index-price swap agreements in order to hedge a portion of its production. The purpose of the swaps is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices on the hedged volumes. The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment of the changes in fair value as specified in SFAS No. 133 is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as oil and gas revenue. For all other derivatives, changes in fair value are recognized in earnings as income or expense. At December 31, 2004 the Company had a current derivative liability of $3,739,406, which is included in current liabilities in its balance sheet. The Company designates these derivatives as cash flow hedges.
During 2004, the Company made payments on financially settled swaps to counter-parties totaling $8,493,300 as its net cost from hedging activities. This total includes $1,383,300 for the first quarter of 2004, $1,870,725 for the second quarter of 2004, $1,988,700 for the third quarter of 2004, and $3,250,575 for the fourth quarter of 2004.
At December 31, 2004, the Company had the following open derivative contracts to manage price risk on a portion of its natural gas production (all prices southwest Wyoming basis).
* Unrealized losses are not adjusted for income tax effect.
The Company also utilizes fixed price forward gas sales at southwest Wyoming delivery points to hedge its commodity exposure. In addition to the derivative contracts discussed above, the Company had the following physical delivery contracts in place at December 31, 2004.
Subsequent to December 31, 2004 and through March 2, 2005, the Company entered into additional contracts for fixed price physical delivery of gas during Calendar 2006 for an additional 25,000 MMBTU/day at an average price of $6.015 per MMBTU.
8. INCOME TAXES:
Income (loss) before income taxes is as follows:
In assessing the realizability of the deferred tax assets, Management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the recognition of future taxable income during the periods in which the temporary differences are available. Among other items, management considers the reversal of deferred tax liabilities, projections of future taxable income and available tax planning strategies.
As of December 31, 2004, the Company has U.S. federal regular tax net operating loss carryforwards (“NOL’s”) of approximately $16.7 million which are available to offset future U.S. taxable income. If not used, these carryforwards will expire between 2019 and 2021. The Company has not recorded any valuation allowance attributable to it’s U.S. NOL’s as management estimates that it is more likely than not that these assets will be fully utilized before they expire.
The Company has Canadian non-capital tax loss carryforwards of approximately $7.3 million and $7.5 million as of December 31, 2004 and December 31, 2003 respectively. The benefit of the Canadian loss carryforwards can only be utilized to the extent the Company generates future taxable income in Canada. If not utilized, the $7.3 million Canadian loss carryforward will expire between 2005 and 2011.
Since the Company currently has no income producing operations in Canada, management estimates that it is more likely than not that the Canadian loss carryforwards will not be utilized. A valuation allowance has been recorded at December 31, 2004 and December 31, 2003 attributable to this deferred tax asset.
The Company uses derivative instruments designated as cash flow hedges as a method of managing its exposure to commodity price fluctuations. To the extent these hedges are effective, changes in the fair value of these derivative instruments are recorded in Other Comprehensive Income, net of income tax. A tax benefit attributable to unrecognized loss on derivative instruments of $1,440,236 and $1,840,713 has been allocated directly to Other Comprehensive Income as of December 31, 2004 and December 31, 2003 respectively.
9. EMPLOYEE BENEFITS:
The Company sponsors a qualified tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its U.S. employees. Employees may defer up to 15% of their compensation, subject to certain limitations. The Company matches the employee contributions up to 5% of employee compensation along with a profit sharing contribution of 8%. The plan operates on a calendar year basis and began in February 1998. The expense associated with the Company’s contribution was $396,684, $299,832 and $236,765 for the years ended December 31, 2004, 2003 and 2002, respectively.
10. SEGMENT INFORMATION
The Company has two reportable operating segments, one domestic and one foreign, which are in the business of natural gas and crude oil exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before price-risk management and other, general and administrative expenses and interest expense. The Company’s reportable operating segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:
11. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES:
In September 2003, the AcSB (Accounting Standards Board) released revised transitional provisions for Stock-Based Compensation and Other Stock-Based Payments, Section 3870, to provide the same alternative methods of transition as is provided in the US for voluntary adoption of the fair value based method of accounting. These provisions permit either retroactive (with or without restatement) or prospective application of the recognition provisions to awards not previously accounted for at fair value. Prospective application is only available to enterprises that elect to apply the fair value based method of accounting to that type of award for fiscal years beginning before January 1, 2004.
The AcSB has also amended Section 3870 to require that all transactions whereby goods and services are received in exchange for stock-based compensation and other payments result in expenses that should be recognized in financial statements, and that this requirement would be applicable for financial periods beginning on or after January 1, 2004. Section 3870 requires that share-based transactions be measured on a fair value basis.
As described in Note 1, had the Company expensed the fair value of options vested during the period, net income would have been reported as $92,358,232 for the year ended December 31, 2004, $43,799,671 for the year ended December 31, 2003 and $5,167,990 for the year ended December 31,2002.
Recorded in other comprehensive loss in the equity section of the Company’s balance sheet is an offset of $2,616,767 to a liability that measures a future effect of the fixed price to index price swap agreements that the Company currently has in place. The Company has recorded this in compliance with FASB No. 133 which addresses accounting impacts of derivative instruments.
The AcSB issued a new Accounting Guideline (“Guideline”), AcG-13, Hedging Relationships, in December 2001 in connection with amendments to CICA Handbook Section 1650, Foreign Currency Translation. The Guideline is applicable to hedging relationships in effect in fiscal years beginning on or after July 1, 2003 (the AcSB changed the original effective date of January 1, 2002 in its December 2001 meeting, and further deferred the effective date in its September 2002 meeting). The Guideline is not applicable to prior periods, but requires the discontinuance of hedge accounting for hedging relationships established in prior periods that do not meet the conditions for hedge accounting at the date it is first applied.
The Guideline supplements some of the requirements on accounting for hedges of foreign currency items in Section 1650, but is equally applicable to accounting for hedges of other types of risk exposure. The Guideline deals with the identification, documentation, designation and effectiveness of hedges and also the discontinuance of hedge accounting, but does not specify hedge accounting methods.
The Guideline is intended to improve the quality and consistency of hedge accounting under Canadian GAAP. The Guideline incorporates certain features of the U.S. hedge accounting standards as requirements.
The AcSB has attempted to avoid creating any additional GAAP differences, i.e., requirements that prevent an entity from adopting a U.S. requirement. However, Canadian hedge accounting remains inconsistent with U.S. GAAP in some fundamental ways.
In May 2003 the Company amended its prior office lease in Englewood, Colorado, which it has committed to through June 2008. The Company’s total remaining commitment at December 31, 2004 on this lease is $702,441. In December 2003, the Company signed a lease for office space in Houston, Texas, which it has committed to through April 2007 for a total remaining commitment at December 31, 2004 of $121,643.
On October 16, 2003 the operator of the Company’s properties in China, Kerr-McGee (“Operator”), signed a 15 year contract, which provides for up to an additional 10 years, to lease a floating production storage offloading unit (“FPSO”). The Company ratified the contract for its net share which is 8.92%. The FPSO service agreement calls for a day rate lease payment and a sliding scale per barrel processing fee that decreases based on cumulative barrels processed. The lease contains a cancellation fee based on a sliding time-scale (cancellation fee decreases with time), which as of December 31, 2004 was $3.87 million net to the Company’s 8.92% interest. The Company considers it very unlikely that a lease cancellation situation will occur. Due to the terms of the lease, the Company cannot estimate with any degree of accuracy the costs it may incur during the life of the lease. The Company’s net share for the costs of the FPSO in 2004 was approximately $1.3 million.
The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company.
For certain of the Company’s financial instruments, including accounts receivable, notes receivable, accounts payable and accrued liabilities, the carrying amounts approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying value for notes payable approximates fair market value because the interest rates are similar to the current rates presently available to the Company for loans with similar terms and maturity.
The Company’s revenues are derived principally from uncollateralized sales to customers in the gas and oil industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company had two significant customers, BP Energy Company and Sempra Energy Trading, that accounted for 10% or more of the Company’s total gas and oil sales during 2004.
14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
15. DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):
The following information about the Company’s oil and gas producing activities is presented in accordance with Financial Accounting Standards Board Statement No. 69, Disclosure About Oil and Gas Producing Activities:
A. OIL AND GAS RESERVES:
The determination of oil and gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. The following unaudited tables as of December 31, 2004, 2003 and 2002 are based upon estimates prepared by Netherland, Sewell & Associates, Inc. dated January 24, 2005, January 23, 2004 and January 21, 2003, respectively. The estimates for properties in China were prepared by Ryder Scott Company in a report dated February 11, 2005. These are estimated quantities of proved oil and gas reserves for the Company and the changes in total proved reserves as of December 31, 2004, 2003 and 2002. All such reserves are located in the Green River Basin, Wyoming and Bohai Bay, China.
B. ANALYSES OF CHANGES IN PROVEN RESERVES:
C. STANDARDIZED MEASURE:
The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved gas reserves. Gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues were $5.46, $5.59, and $2.94 per Mcf of gas at December 31, 2004, 2003 and 2002, respectively. The calculated weighted average crude oil price at December 31, 2004 for China was a Duri price of $29.46. The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference
between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers (US $000).
The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses.
D. SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (US$000)
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 the control of the Company. 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 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 subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and gas prices have fluctuated widely.
E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES (US$000):
UNITED STATES
CHINA
F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (US$000):
UNITED STATES
CHINA
Item 9.
Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosures.
None
Item 9A.
Item 9A. Controls and Procedures.
The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-K.
There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
Part III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
The information required by this item will be included in the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated herein by reference.
The information required by this item will be included in the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by Item 403 of Regulation S-K will be included in the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions.
The information required by this item will be included in the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated herein by reference.
Item 14.
Item 14. Principal Accountants Fees and Services
The information required by this item will be included in the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2004, and is incorporated herein by reference.
Part IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
The following documents are filed as part of this report:
1. Financial Statements: See Index to Consolidated Financial Statements in Item 8.
2. Financial Statement Schedules: None
3. Exhibits. The following Exhibits are filed herewith pursuant to Rule 601 of the Regulation S-K or are incorporated by reference to previous filings. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX