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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C., 20549

Form 10-Q

Commission File Number 0-30321

(801) 324-2600
(Registrant’s telephone number, including area code)

Questar Market Resources, Inc.

Form 10-Q for the Quarterly Period Ended March 31, 2005

TABLE OF CONTENTS

Page #

GLOSSARY OF COMMONLY USED TERMS

3

FORWARD-LOOKING STATEMENTS

5

PART I FINANCIAL INFORMATION

8

Item 1.

Financial Statements

8

Consolidated Statements of Income for the three months

   ended March 31, 2005 and 2004

8

Condensed Consolidated Balance Sheets at March 31, 2005

   and December 31, 2004

9

Condensed Consolidated Statements of Cash Flows for the three months

   ended March 31, 2005 and 2004

10

Notes Accompanying Consolidated Financial Statements

11

Item 2.

Management’s Discussion and Analysis of Financial Condition and

   Results of Operations

15

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

21

Item 4.

Controls and Procedures

23

PART II.

OTHER INFORMATION

24

Item 1.

Legal Proceedings

24

Item 6.

Exhibits

24

Signatures

25

GLOSSARY OF COMMONLY USED TERMS

bbl

Barrel, which is equal to 42 U.S. gallons and is a common unit of measurement of crude oil.

basis

The difference between a reference or benchmark-commodity price and the corresponding sales price at various regional sales points.

bcf

One billion cubic feet, a common unit of measurement of natural gas.

bcfe

One billion cubic feet of natural gas equivalents. Oil volume is converted to natural gas equivalent using the ratio of one barrel of crude oil to 6,000 cubic feet of natural gas.

Btu

One British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

cash-flow hedge

A derivative instrument that complies with Statement of Financial Accounting Standards (SFAS) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

cf

Cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.73 pounds per square inch).    

development well

A well drilled into a known producing formation in a previously discovered field.

dew point

A specific temperature and pressure at which hydrocarbons condense to form a liquid.

dry hole

A well drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of production exceed expenses and taxes.

dth

Decatherms or ten therms. One dth equals one million Btu or approximately one Mcf.

exploratory well

A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.

finding costs

Finding costs are the sum of costs incurred for gas and oil exploration and development activities; including leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset-retirement obligations for a given period, divided by the total amount of estimated net-proved reserves added through discoveries, positive and negative revisions of previous estimates and purchases in-place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.

futures contract

An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.

gas

   All references to “gas” in this report refer to natural gas.

gross

“Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working interest.

hedging

The use of derivative-commodity and interest-rate instruments to reduce financial exposure to commodity-price and interest-rate volatility.

Mbbl

One thousand barrels.

Mcf

One thousand cubic feet.

Mcfe

One thousand cubic feet of natural gas equivalents. Oil volume is converted to natural gas equivalent using the ratio of one barrel of crude oil to 6,000 cubic feet of natural gas.

Mdth

One thousand decatherms.

Mdthe

One thousand decatherm equivalents. Oil volume is converted to natural gas equivalent using the ratio of one barrel of crude oil to 6,000 cubic feet of natural gas.

MMbbl

One million barrels.

MMBtu

One million British thermal units.

MMcf

One million cubic feet.

MMcfe

One million cubic feet of natural gas equivalents.

MMdth

One million decatherms.

MMgal

One million U. S. gallons.

natural gas liquids

Liquid hydrocarbons that are extracted and separated from the natural gas

(NGL)

stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.

net

Net gas and oil wells or net acres are determined by the sum of the fractional ownership working interest the Company has in those gross wells or acres.

production-

The production-replacement ratio is calculated by dividing the net-proved

replacement ratio

reserves added through discoveries, positive and negative revisions of previous estimates and purchases and sales in-place for a given period by the production for the same period, expressed as a percentage. The production-replacement ratio is typically reported on an annual basis.

proved reserves

Those quantities of natural gas, crude oil, condensate and NGL on a net-revenue-interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.

proved-developed

Reserves that include proved developed-producing reserves

reserves

and proved-developed behind-pipe reserves. See 17 C.F.R. Section 4-10(a)(3).

proved-developed-

Reserves expected to be recovered from existing completion intervals in

producing reserves

existing wells.

proved-undeveloped

Reserves expected to be recovered from new wells on proved-undrilled acreage

reserves

or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(4).

reservoir

A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

wet gas

Unprocessed natural gas that contains a mixture of heavier hydrocarbons including ethane, propane, butane and natural gasoline.

working interest

An interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act (Act) of 1934 as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” “forecast,” or “continue” or the negativ e thereof or variations thereon or similar terminology. Although these statements are made in good faith and are reasonable representations of Questar Market Resources, Inc.’s (Market Resources or the Company) expected performance at the time, actual results may vary from management’s stated expectations and projections due to a variety of factors.

Important assumptions and other significant factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements include:

Market Resources subsidiaries find, produce and sell natural gas, oil and NGL

Natural gas, oil and NGL prices are volatile and, therefore, Market Resources revenues, cash flow and earnings can be volatile. The Company cannot predict future natural gas, oil and NGL price movements, which are subject to forces beyond its control such as:

•

Domestic and foreign supply of natural gas and oil;

•

Regional basis differential due to pipeline-capacity constraints;

•

Domestic and global economic conditions;

•

Weather;

•

Domestic and foreign government regulations;

•

The price and availability of alternative fuels;

•

The costs and availability of drilling rigs and other materials and services.

Gas and oil prices are volatile

The Company uses financial contracts to hedge its exposure to volatile natural gas, oil and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity-price movements. While hedging reduces the impact of declining prices, it may also limit future revenues from favorable price movements. Market Resources believes its Wexpro subsidiary generates revenues that are not significantly sensitive to short-term fluctuations in natural gas and oil prices.

Market Resources’ profitability depends not only on prevailing prices for natural gas, oil and NGL, but also the Company’s ability to find, develop and acquire gas and oil reserves that are economically recoverable. Substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.

Estimating gas and oil reserves, production and future net cash flow is difficult

Questar Exploration and Production Company’s proved natural gas- and oil-reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas- and oil-reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of pre vious estimates. In addition, the estimates of future net revenues from proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may change. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates depends on the accuracy of the assumptions upon which they were based. Actual results may differ materially from the estimated results.

Drilling is a high-risk activity

Operating risks include: blow-outs; fire; unexpected drilling conditions such as uncontrollable flows of gas, oil, formation water or drilling fluids; abandonment costs; explosions; pipe, cement or casing failures; oil spills; natural gas leaks; pipeline ruptures; and discharges of toxic gases. The Company could incur substantial losses as a result of injury or loss of life; environmental damage; destruction of property; fines; or curtailment of operations. The Company maintains insurance against some, but not all, of these potential risks and losses.

Market Resources must comply with numerous regulations from the federal, state and local level

Market Resources is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and tend to become more onerous over time. In addition to the costs of compliance, the Company may incur substantial costs to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time but that now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.

Market Resources must comply with numerous and complex regulations governing their activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act and the National Historic Preservation Act. Federal and state agencies frequently impose conditions on the Company’s activities. These restrictions tend to become more stringent over time, and can limit or prevent the Company from exploring for, finding and producing natural gas and oil on its Rockies leasehold. Certain environmental groups oppose drilling on some of the Company’s federal and state leases.

Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with federal law. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native Ame rican tribal lands. Finally, lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase Market Resources’ costs of doing business on Native American tribal lands and have an impact on the viability of its gas and oil operations on such lands.

Other factors may affect Market Resources results

Market Resources results may also be affected by: changes in general economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers’ credit ratings; competition from other forms of energy; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the Company; changes in credit ratings; and availability of financing.

The Company cannot predict these factors nor can it assess the impact, if any, of such factors on its financial position or its results of operations. Accordingly, forward-looking statements should not be relied upon as a predictor of actual results. Market Resources undertakes no obligation to update any forward-looking statement provided in this report.

PART I. FINANCIAL INFORMATION

  ITEM 1. FINANCIAL STATEMENTS

#

See notes accompanying consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

Market Resources is a wholly owned subsidiary of Questar Corporation. The accompanying interim consolidated financial statements of Market Resources have not been audited by an independent registered public accounting firm, with the exception of the condensed consolidated balance sheet at December 31, 2004, which was derived from the audited financial statements at that date. The unaudited consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. The interim consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented. The preparation of conso lidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities. Actual results could differ from estimates. All significant intercompany accounts and transactions were eliminated in consolidation. Certain reclassifications were made to the 2004 financial statements to conform with the 2005 presentation.

The results of operations for the three-month period ended March 31, 2005, are not necessarily indicative of the results that may be expected for the year ending December 31, 2005, due to the volatility of gas and oil sales prices and other risk factors listed in the Forward-Looking Statements section of this report. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. For further information please refer to the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

Note 2 – Asset-Retirement Obligations (ARO)

Market Resources recognizes ARO in accordance with SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO applies primarily to plugging and abandonment costs associated with gas and oil wells and certain other properties. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. ARO are adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate.

Changes in asset-retirement obligations were as follows:

Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming. Pursuant to the stipulation, Wexpro collects and deposits in trust certain funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At March 31, 2005, approximately $3.1 million was held in this trust invested in a short-term bond index fund.

Note 3 – Investment in Unconsolidated Affiliates

Market Resources uses the equity method to account for investments in unconsolidated affiliates where the Company does not have control. These entities are engaged in gathering and compressing natural gas, and have no debt obligations with third-party lenders. The principal affiliates and Market Resources’ ownership percentage as of March 31, 2005, were: Rendezvous Gas Services, LLC (Rendezvous), a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%).

Summarized operating results of the businesses representing 100% interest are listed below:

Note 4 - Operations by Line of Business

Market Resources has four primary reportable segments: Questar Exploration and Production Company (Questar E&P), Wexpro Company (Wexpro), Questar Gas Management Company (Gas Management) and Questar Energy Trading Company (Energy Trading). Lines of business information are presented according to management’s basis for evaluating performance including differences in the nature of products and services. Certain intersegment sales include intercompany profits.

Note 5 – Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive income or loss reported in Common Shareholder’s Equity. Other comprehensive income or loss includes changes in the market value of gas or oil-price derivatives and are not reported in current income or loss. Income or loss is realized when the physical gas or oil underlying the derivative instrument is sold. A summary of comprehensive income is shown below:

Note 6 – Recent Accounting Development

On April 4, 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs.” FSP FAS 19-1 modifies a requirement of SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to capitalize the costs of drilling exploratory wells pending determination of whether the well has found proved reserves. The capitalized costs become part of the entity’s wells, equipment and facilities if the well successfully located proved reserves. However, if the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value. FSP FAS 19-1 states that exploratory well costs can be capitalized beyond the previously prescribed one-year limit if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserve s and the economic and operating viability of the project.

The Company drills exploratory wells in onshore U.S. petroleum-producing regions with good access to downstream markets. Factors such as weather, seasonal access restrictions on federal land, or delays caused by permitting production facilities can cause minor delays in connecting successful exploratory wells to downstream markets, but those delays are typically less than one year. The Company currently has no completed exploratory wells classified as suspended.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

(Unaudited)

Summary

Market Resources operates through several subsidiaries. Questar Exploration and Production Company (Questar E&P) explores for, acquires, develops and produces gas and oil. Wexpro Company (Wexpro) develops and produces cost-of-service reserves for an affiliated company, Questar Gas. Questar Gas Management Company (Gas Management) provides gas-gathering and processing services for affiliates and third parties. Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services and through Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir. Following is a comparison of net income by line of business:

Results of Operations

Consolidated Results

Market Resources net income for the first quarter of 2005 totaled $56.6 million compared with $40.3 million for the year earlier period, a 41% increase. Operating income increased to $94.7 million versus $69.3 million in the 2004 quarter, a 37% increase. Following is a summary of Market Resources’ financial and operating results for the first quarter of 2005 compared with 2004

Questar E&P

For the first quarter of 2005, Questar E&P net income increased 44% to $36.3 million compared with $25.2 million for the same period in 2004. The increase was driven by a combination of increased gas production volumes and higher realized natural gas, oil and NGL prices.

Questar E&P’s production for the first three months of 2005 was 26.3 bcfe versus 25.4 bcfe for the 2004 period, a 4% increase. Current quarter production was negatively impacted by weather-related completion and workover delays on Uinta Basin and western Midcontinent properties, in addition to delays caused by seasonal access restrictions on Rockies Legacy properties. Seasonal access restrictions exist over much of Market Resources federal leasehold acreage in the Rockies. Delays in obtaining rigs to drill planned development wells in the western Midcontinent also impacted first quarter 2005 production growth.

Natural gas remains the primary focus of Questar E&P’s exploration and production strategy. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P’s production for the first quarter of 2005. A comparison of energy equivalent production by region is shown in the following table.

Questar E&P’s first quarter 2005 production from Pinedale increased 24% to 7.5 bcfe versus 6.1 bcfe in the first quarter of 2004. Production at Pinedale typically declines during the first through third quarters of each year due to mid-November to early May seasonal access restrictions imposed by the Bureau of Land Management (BLM) that restrict the company’s ability to complete wells during the period.

Uinta Basin production declined 9% to 5.7 bcfe in the 2005 quarter compared to 6.3 bcfe a year ago. Abnormal weather slowed completion and connection of new wells and routine workovers on existing wells. Weather-related conditions (mud) improved in mid-March, and Questar E&P has since reduced the backlog of well completions and workovers. In addition, high gathering-system pressures caused by a higher-pressure deep well continued to depress production from older lower-pressure wells. The company will install a separate gathering system for existing and new high-pressure wells, which should mitigate the impact on production from older wells.

Production from Rockies Legacy properties in the current quarter was 4.1 bcfe compared to 4.4 bcfe during the 2004 period, a 9% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties except Pinedale and the Uinta Basin. Current period Legacy properties production was negatively impacted by normal decline and seasonal restrictions that limited access to the company’s leases and wells during the winter months.

Midcontinent production was 9.0 bcfe in the first quarter of 2005 compared to 8.6 bcfe for the same period of 2004, a 5% increase. During the quarter, the company continued one-rig-development programs in both the Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and the ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana. Delays in obtaining rigs to drill a backlog of development wells and weather-related downtime negatively impacted production volumes and workover activity in the western Midcontinent region.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the current quarter the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $4.76 per Mcf compared to $4.05 per Mcf for the same period in 2004, an 18% increase. For the 2005 quarter, realized oil and NGL prices averaged $38.74 per bbl, compared with $29.46 per bbl during the first quarter of 2004, a 32% increase. A comparison of average realized prices by region, including hedges, is shown in the following table:

Approximately 88% of Questar E&P’s gas production in the first quarter of 2005 was hedged or pre-sold at an average price of $4.98 per Mcf net to the well (which reflects adjustments for regional basis, gathering and processing costs and gas quality). Hedging reduced gas revenues $9.6 million during the quarter. Questar E&P also hedged approximately 56% of its oil production for the period at an average net to the well price of $34.64 per bbl. Hedging reduced oil revenues $4.0 million.

Market Resources may hedge up to 100 percent of its forecasted production from proved developed reserves to lock in acceptable returns on invested capital and to protect cash flows and earnings from a decline in commodity prices. During the quarter, Questar E&P has continued to take advantage of higher natural gas and oil prices to add to its hedge positions in 2005, 2006 and 2007. Natural gas and oil hedges as of March 31, 2005, are summarized in Part I, Item 3 of this report.

During the current quarter, Questar E&P’s pre-income tax cost structure per unit of production (the sum of depreciation, depletion and amortization expense, lifting costs, general and administrative expense and allocated-interest expense) increased 13% to $2.67 per Mcfe versus $2.37 per Mcfe in the first quarter of 2004.

Lifting costs in the 2005 period increased 12% versus the 2004 quarter due to a $0.04 per Mcfe increase in production taxes and a $0.07 per Mcfe increase in lease operating expenses. Most production taxes are based on a fixed percentage of commodity sales prices. Higher lease-operating expenses reflect a general increase in well service costs, including costs of contracted services and production-related supplies, increased workover and production enhancement projects and additional weather-related costs during the current period.

Depreciation, depletion and amortization expense rose 13% over the past year to $1.11 per Mcfe due to normal decline in production from older, lower cost successful-efforts pools, negative reserve revisions over the past 12 months at the company’s Uinta Basin properties and higher reserve replacement (finding and development) costs. Higher day rates for rigs and other services in core operating areas, along with sharply higher steel prices, resulted in higher drilling and completion costs.

General and administrative expenses increased $0.07 per Mcfe, or 26%, to $0.34 in the first quarter of 2005. The company continued to adjust employee compensation in response to industry competition for skilled professionals. Higher allocated corporate overhead (primarily employee benefits and compliance costs) also contributed to the increase.

Questar E&P’s pre-income tax cost structure is summarized in the following table:

Abandonment and impairment expense declined $3.0 million in the first quarter of 2005 primarily due to an impairment expense in the first quarter of 2004 resulting from collapsed well casing.

Pinedale Anticline Drilling Activity

As of May 10, 2005, Market Resources operated 107 producing wells on the Pinedale Anticline compared to 76 at the end of the year-earlier quarter. Drilling continued on one winter pad with two rigs active throughout the quarter. A total of eight wells will be drilled from the current winter pad. Barring drilling problems, the company expects all eight wells to be drilled to total depth (TD) and cased before the end of the second quarter of 2005. In addition to the winter pad drilling activity, at the end of the current quarter the company had two rigs active on a state land section near the southern end of its Pinedale acreage. The company also completed and turned to sales two wells on the state land section that were drilled and cased in late 2004.

As of May 10, 2005, the company had the following wells in progress:

·         On the 2004/2005 winter pad, four wells drilled to TD, awaiting completion, two wells drilled to intermediate casing point and two wells drilling below intermediate casing point.