Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2005

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 001-31539

ST. MARY LAND & EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)


Delaware		41-0518430
(State or other jurisdiction		(I.R.S. Employer Identification No.)
of incorporation or organization)

	1776 Lincoln Street, Suite 700, Denver, Colorado 80203
	(Address of principal executive offices) (Zip Code)

	(303) 861-8140
	(Registrant's telephone number, including area code)

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

Title of each class		Name of each exchange on which registered
Common Stock, $.01 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of 55,026,022 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter, of $28.98 per share as reported on the New York Stock Exchange was $1,594,654,118. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the Company to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 15, 2006, the registrant had 56,953,893 shares of common stock outstanding, net of 250,000 treasury shares held by the Company.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrant's definitive proxy statement relating to its 2006 annual meeting of stockholders to be filed within 120 days after December 31, 2005.

TABLE OF CONTENTS

ITEM		PAGE
	PART I
ITEM 1.	BUSINESS	1
	Background and Strategy	1
	Significant Developments since December 31, 2004	3
	Major Customers	4
	Employees and Office Space	4
	Title to Properties	4
	Seasonality	5
	Competition	5
	Government Regulations	5
	Cautionary Information about Forward-Looking Statements	7
	Available Information	8
	Glossary	9
ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	19

ITEM 2.	PROPERTIES	20
	Operations	20
	Acquisitions and Divestitures	23
	Reserves	24
	Production	25
	Productive Wells	25
	Drilling Activity	26
	Acreage	27

ITEM 3.	LEGAL PROCEEDINGS	28

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	28

ITEM 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	28

	PART II

ITEM 5.	MMARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	29

ITEM 6.	SELECTED FINANCIAL DATA	32

TABLE OF CONTENTS

(Continued)

ITEM		PAGE

ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
	Overview of the Company	34
	Overview of Liquidity and Capital Resources	41
	Critical Accounting Policies and Estimates	51
	Additional Comparative Data in Tabular Format	55
	Comparison of Financial Results and Trends Between 2005 and 2004	56
	Comparison of Financial Results and Trends Between 2004 and 2003	58
	Other Liquidity and Capital Resource Information	60
	Accounting Matters	60
	Environmental	60
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included with the content of ITEM 7)	60

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	60

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	61

ITEM 9A.	CONTROLS AND PROCEDURES	61

ITEM 9B.	OTHER INFORMATION	63

	PART III

ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	63

ITEM 11.	EXECUTIVE COMPENSATION	63

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	64

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	64

ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	64

	PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K	65

PART I

When we use the terms “St. Mary,” “the Company,” “we,” “us” or “our,” we are referring to St. Mary Land & Exploration Company and its subsidiaries, unless the context otherwise requires. We have included technical terms important to an understanding of our business under “Glossary”. Throughout this document we make statements that are classified as “forward-looking”. Please refer to the “Cautionary Information about Forward-Looking Statements” section of this document for an explanation of these types of statements.

ITEM 1. BUSINESS

Background and Strategy

We are an independent oil and gas company engaged in the exploration, exploitation, development, acquisition and production of natural gas and crude oil. We were founded in 1908 and incorporated in Delaware in 1915. Our principal offices are located at 1776 Lincoln Street, Suite 700, Denver, Colorado 80203, and our telephone number is (303) 861-8140.

Our objective is to build stockholder value through consistent economic growth in reserves and production that increase net asset value per share and earnings per share. We seek to invest in oil and gas producing assets that result in a superior return on equity while preserving underlying capital, resulting in a return on equity to stockholders that reflects capital appreciation as well as the payment of cash dividends.

Our operations are focused in the following five core operating areas in the United States:

	·	the Rocky Mountain region consisting of the Williston Basin in eastern Montana and western North Dakota as well as basins in Wyoming. Recent activity in the northern Rockies includes drilling in the Middle Bakken formation, continued development in the Red River formation, and horizontal drilling prospects in the Mission Canyon and Ratcliffe formations. As a follow on to the acquisitions made in the last three years, the Company has increased its activity in Wyoming, with development of the Tensleep formation in the Big Horn Basin, development in the Wind River Basin and gas development in the Greater Green River Basin. Our development of coalbed methane reserves in the Hanging Woman Basin is included in our Rockies region;

	·	the Mid-Continent region in Oklahoma and northern Texas, primarily in the Anadarko and Arkoma basins. The most significant activity is in the Northeast Mayfield area in Beckham and Roger Mills counties and the Centrahoma area in Coal County where we are pursuing development of a horizontal well program in the Wapanucka limestone, Cromwell sandstone and Woodford shale formations;

	·	the ArkLaTex region spans northern Louisiana, southern Arkansas, Mississippi and eastern Texas. Recent activity includes the horizontal program in the James Lime formation at the Spider field. The ArkLaTex region is using its horizontal well expertise to expand into the limestones of the Glen Rose, James, Rodessa, and Pettet formations throughout the region. The ArkLaTex region manages our interest in a significant vertical well development effort at the Elm Grove field as well as our interest in the Cotten Valley interval at Terryville field;

	·	the Gulf Coast region consists of onshore Texas and Louisiana properties and includes the Judge Digby field in Pointe Coupee Parish, our fee property in St. Mary Parish, Louisiana, and a presence in the offshore Gulf of Mexico. The region is using 3-D seismic to identify direct hydrocarbon indicators along the Gulf Coast and in the Gulf of Mexico; and

	·	the Permian Basin in eastern New Mexico and western Texas, includes the waterflood projects at Parkway Delaware Unit and East Shugart Delaware Unit in New Mexico.

As of December 31, 2005, we had estimated proved reserves of 62.9 MMBbl of oil and 417.1 Bcf of natural gas, or a total of 794.5 BCFE with a PV-10 value of $2.5 billion. Of these reserves, 82 percent were proved developed and 53 percent were natural gas. This represents an increase in reserve volumes of 21 percent and a 66 percent increase in PV-10 value from a year earlier. For the year ended December 31, 2005, we produced 87.4 BCFE, representing average daily production of 239.4 MMCFE, a 16 percent increase from 2004. Our reserve replacement percentage in 2005 was 256 percent of production. This percentage would not change if sales of reserves were included in the calculation. The proved reserve total at December 31, 2005, includes 25.2 Bcf of natural gas reserves associated with our coalbed methane project at Hanging Woman Basin.

Our reserve replacement percentage, excluding acquisitions and sales, was 199 percent in 2005. This is a result of the overall strength of our drilling programs in the Bakken, at Northeast Mayfield and our participation in the Elm Grove field, as well as the exceptionally strong performance of our Paggi Broussard well in Jefferson County, Texas. The percentage of PUD reserves increased from 15 percent at the end of 2004 to 18 percent at December 31, 2005. This increase is directly related to the continuing development of our Atoka and Granite Wash program in the Northeast Mayfield area and the Centrahoma area in the Mid-Continent region as well as recognition of proved reserves in the ArkLaTex region at Elm Grove. We believe that the use of the term, “reserve replacement percentage” is widely understood and utilized by those who are involved in and those who make investment decisions related to the exploration and production industry. Therefore, this measure provides a useful basis of comparison to other companies and provides a measure of growth.

We attempt to focus our resources in selected domestic basins where we believe our expertise in geology, geophysics and drilling and completion techniques provide us with competitive advantages. In 2005 we spent $319.3 million in capital expenditures related to drilling activities, $87.8 million on acquisition of oil and gas properties and $14.3 million on leasing activity.

Our total capital budget for 2006 is $600 million. As a company, we are placing a greater emphasis on growth through the drill bit rather than from acquisitions. This is evidenced by our reserve replacement from the drill bit, and the fact that our 2006 capital program contemplates $500 million of spending on drilling operations and $100 million on acquisitions. The increase in budgeted spending represents a 42 percent increase over 2005. This increase includes our estimate of drilling program inflation, but the majority relates to our activity level and prospect inventory. We have assembled a balanced program of low-to-medium-risk development and exploitation projects to provide the foundation for steady growth. We believe that the development of resource plays in the Bakken, Atoka and Granite Wash at Northeast Mayfield, the Wapanucka limestone, Cromwell sandstone, and Woodford shale at Centrahoma, the Cotton Valley and Hosston at Elm Grove, and coalbed methane in the Hanging Woman Basin help provide us with a core inventory of prospects for the future. We measure and rank our investment decisions based on their risk-adjusted estimated internal rate of return and return on investment. In 2005 all acquisitions were funded with cash flow generated from operations. Additionally, we were able to repay the $37 million of borrowings from our revolving credit facility that was outstanding at the beginning of the year. When we issue stock for the acquisition of properties or a corporate entity, we base our investment decision primarily on the impact to net asset value per share.

Although our acquisition budget is lower than in prior years on a percentage basis, we will continue to seek selective acquisitions of oil and gas properties that complement our existing operations, offer economies of scale and provide further development, exploitation and exploration opportunities based on proprietary geologic concepts. We will be focusing on areas where we have specialized geologic knowledge or operating experience to enable us to acquire attractively priced properties. In addition, we have and will pursue corporate acquisitions that we believe are accretive and that we are capable of integrating. In 2005 we acquired the stock of Agate Petroleum, Inc. for cash. Other examples of corporate acquisitions include the acquisition of Goldmark Engineering in 2004 for cash and the acquisitions of Nance Petroleum Corporation and King Ranch Energy, Inc. in 1999, both of which were accomplished with the issuance of our common stock. The Flying J Oil & Gas Inc. property acquisition transaction completed in 2003 was not a corporate acquisition, yet we used a combination of restricted stock, a loan to Flying J and options on our common stock for this transaction.

We divest selected non-core assets when market conditions and prices are attractive, and we will continue to evaluate such opportunities in the future as we believe it to be appropriate. During 2005 we sold properties with estimated proved reserves of 630 MMCFE, or less than one-tenth of one percent of our reserves as of the beginning of the year.

We seek to develop our existing property base and acquire acreage with additional potential in our core areas. From January 1, 2003 through December 31, 2005, we participated in the drilling or recompletion of 1,118 gross wells with a success rate of 89 percent. During the three-year period we added estimated proved reserves of 592.6 BCFE at an average finding cost of $1.64 per MCFE. These results represent a three-year average reserve replacement percentage of 247 percent, not including the effect of sales. Production has grown from an average daily rate of 210.7 MMCFE per day in 2003 to 239.4 MMCFE per day in 2005.

As of December 31, 2005, we had an acreage position of 2,106,884 gross (1,103,961 net) acres of which 1,178,845 gross (712,323 net) acres were undeveloped. Our current leasehold position represents a seven percent increase on a gross acre basis and a six percent increase on a net acre basis from 2004. In addition to the leased acreage position, we own 24,914 net acres of fee properties in St. Mary Parish, Louisiana, and mineral servitudes representing 14,663 gross (9,868 net) acres in other portions of Louisiana. We believe this lease position provides a competitive advantage in certain locations and is a strategic asset for the Company.

Our senior technical managers in each region possess from 15 to 40 years of industry experience and lead fully-staffed regional technical offices that are supported by centralized administration from our Denver office. We use our comprehensive base of geological, geophysical, engineering and production experience in each of our core operating areas to source prospects for our ongoing low-to-medium-risk development and exploitation programs. We conduct detailed geologic studies and use an array of technologies and tools including 2-D and 3-D seismic imaging, hydraulic fracturing and reservoir stimulation techniques, horizontal drilling, secondary recovery and specialized logging tools to enhance the potential of our existing properties.

We believe it is important to control geologic and operational decisions as well as the timing of those decisions. As of December 31, 2005, we operated 67 percent of our properties on a reserve volume basis and 64 percent on a PV-10 value basis. We plan to operate approximately 73 percent of our 2006 exploration and development capital budget.

Conservative use of financial leverage has long been a critical element of our strategy. We believe that maintaining a strong balance sheet is a significant competitive advantage that enables us to pursue acquisition and other opportunities, especially in weaker price environments. It also provides us with the financial resources to weather periods of volatile commodity prices or escalating costs. Our debt to book capitalization ratio was 15 percent at the end of December 2005.

In summary, we believe that our dedication to making decisions based on net asset value per share, our long-standing geologic and engineering experience in the regions in which we operate, our application of technology, our established networks of local industry relationships and our acreage holdings in our core operating areas provide us with our competitive advantages.

Significant Developments since December 31, 2004

	·	2005 Acquisition of Oil and Gas Properties. Our total acquisitions of proved and unproved oil and gas properties in 2005 were $87.8 million. The two most significant acquisitions were the Agate Petroleum, Inc. corporate acquisition that closed on January 5, 2005, for $40.0 million in cash and the Wold Oil Properties, Inc. property acquisition that closed on August 1, 2005, for $37.1 million in cash. Assets acquired from Agate Petroleum, Inc. are located in the Williston and Arkoma Basins and the properties acquired from Wold Oil Properties, Inc., are located primarily in the Wind River and Powder River Basins.

	·	Coalbed Methane Development. Our total proved reserves at Hanging Woman Basin at the end of 2005 grew to 25.2 Bcf. During 2005 we drilled 131 wells, 114 of which we operate, and our total production was 0.5 Bcf. The 2006 capital program for the Hanging Woman Basin development is currently budgeted at $50 million for approximately 260 wells. Environmental and regulatory permitting issues may impact the timing of drilling approximately 60 wells located in Montana and 60 wells located in Wyoming. The potential Montana delays are a result of the necessary regulatory approval of our water development plan on state and fee acreage. Delays in Wyoming permitting could result from the scheduling of drilling in areas that are affected by stipulations associated with sage grouse.

	·	Increase in 2005 Year-End Reserves. Proved reserves increased 21 percent to 794.5 BCFE at December 31, 2005, from 658.6 BCFE at December 31, 2004. We added 140.1 BCFE from our drilling program, 49.8 BCFE from acquisitions, and 33.9 BCFE from upward reserve revisions. Included in the revision number is 23.1 BCFE of upward revisions resulting from increases in oil and gas prices. We sold properties with reserves of less than one BCFE in 2005.

	·	Drilling Results. Reserve additions came principally from drilling results in the Rockies, Mid-Continent and ArkLaTex regions. The increase in the Rockies can be attributed primarily to continued development of the Middle Bakken play in Montana. The Red River formation continues to provide reserve additions in the Rockies as we take full advantage of 3-D seismic to identify multi-pay structures. Our Mid-Continent reserve additions were primarily from the continued development of the Northeast Mayfield area and the Centrahoma area. The Northeast Mayfield development has shifted to the Atoka and Granite Wash formations from the deeper Morrow sand that provided growth in earlier years. The Centrahoma play includes the start of a horizontal program in the Wapanucka limestone, Cromwell sandstone and Woodford shale formations. The ArkLaTex region grew from total proved reserves of 75.6 BCFE at the end of 2004 to 111.3 BCFE this year end. This growth is a reflection of the value we are deriving from the Elm Grove field development at Bossier Parish, Louisiana.

	·	Hedging of Oil and Natural Gas through 2011. Beginning in October 2005, we entered into financial derivative transactions to hedge oil and gas prices on a significant portion of our proved developed producing assets. These hedges have been placed in the form of zero-cost collars. We have also hedged specific production related to our acquisitions as well as a portion of existing production for our 2006 Northeast Mayfield development program using swap contracts.

	·	Repurchase of Common Stock. In 2005 we repurchased a total of 1,175,282 shares of our common stock at an average cost of $24.51 per share. These repurchases were funded from available cash. As of December 31, 2005, the number of additional shares that we may repurchase under the program is 3,846,118.

Major Customers

During 2005, sales to Tesoro Refining and Marketing accounted for 13 percent of our total oil and gas production revenue. During 2004 sales to Tesoro Refining and Marketing accounted for 20 percent of our total oil and gas production revenue. During 2003 sales to BP America Production Company accounted for 14 percent, sales to Midcoast Energy accounted for 13 percent and sales to Tesoro Refining and Marketing accounted for 11 percent of our total oil and gas production revenue.

Employees and Office Space

As of February 15, 2006, we had 305 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good. We lease approximately 56,900 square feet of office space in Denver, Colorado for our executive and administrative offices, of which 9,500 square feet is subleased. We also lease approximately 18,600 square feet of office space in Tulsa, Oklahoma; approximately 11,700 square feet in Shreveport, Louisiana; approximately 13,700 square feet in Houston, Texas; approximately 32,200 square feet in Billings, Montana; and approximately 2,000 square feet in Casper, Wyoming.

Title to Properties

Substantially all of our working interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of drilling operations on properties. We have obtained title opinions or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of the value of our properties is subject to a mortgage under our credit facility, customary royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. We perform only a minimal title investigation before acquiring undeveloped leasehold.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by generally higher prices in the winter. Seasonal anomalies such as mild winters sometimes lessen these fluctuations. The impact of seasonality has somewhat been mitigated by the overall supply and demand economics related to crude oil because there is a narrow margin of production capacity in excess of existing worldwide demand.

Competition

The oil and gas industry is intensely competitive. This is particularly true in the acquisition of prospective oil and natural gas properties and oil and gas reserves. We believe that our leasehold position provides a sound foundation for a robust drilling program. Our competitive position also depends on our geological, geophysical and engineering expertise, and our financial resources. We believe that the location of our leasehold acreage, our exploration, drilling and production expertise and the experience and knowledge of our management and industry partners enable us to compete effectively in our core operating areas. Notwithstanding our talents and assets, we still face stiff competition from a substantial number of major and independent oil and gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for the drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time. Currently, access to incremental drilling equipment in certain regions is difficult but is not, at this time, anticipated to have any material negative impact on our ability to deploy our capital drilling budget for 2006. Finally, we also compete for people. As drilling activities have accelerated, the need for talented people has grown at a time when the number of people available is constrained.

Government Regulations

Our business is subject to various federal, state and local laws and governmental regulations that may be changed from time to time in response to economic or political conditions. Matters subject to regulation include the issuance of drilling permits, discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental protection. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.

Energy Regulations. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction, most notably interstate natural gas transmission companies. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and final FERC decisions. Regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain petroleum product pipelines. In addition, some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress and the courts. The natural gas industry historically has been very heavily regulated, and there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. We do not believe that we will be more materially affected by any action taken by the FERC than other natural gas producers and marketers with whom we compete.

Certain operations we conduct involve federal minerals administered by the Minerals Management Service. The MMS issues leases covering such lands through competitive bidding. These leases contain relatively standardized terms and require compliance with federal laws and detailed MMS regulations. For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. Lessees must also comply with detailed MMS regulations governing, among other things:

	·	engineering and construction specifications for offshore production facilities;

	·	safety procedures;

	·	flaring of production;

	·	plugging and abandonment of Outer Continental Shelf wells;

	·	calculation of royalty payments and the valuation of production for this purpose; and

	·	removal of facilities.

To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial, and we may not be able to continue to obtain bonds or other surety in all cases. Under certain circumstances the MMS may require our operations on federal leases to be suspended or terminated.

Many of the states in which we conduct our oil and gas drilling and production activities regulate such activities by requiring, among other things, drilling permits and bonds and reports concerning operations. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing of waste material, plugging and abandonment of wells, restoration requirements, unitization and pooling of natural gas and oil properties and establishment of maximum rates of production from natural gas and oil wells. Some states prorate production to the market demand for oil and natural gas.

Environmental Regulations. Our operations are subject to numerous existing federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations may require that permits be obtained before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, and limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing endangered animal species. As a result, these laws and regulations may substantially increase the costs of exploring, developing or producing oil and gas and may prevent or delay the commencement or continuation of a project. In addition, these laws and regulations may impose substantial clean-up, remediation and other obligations in the event of any discharges or emissions in violation of such laws and regulations.

Our coalbed methane gas production from the Hanging Woman Basin is similar to our traditional natural gas production as to the physical producing facilities and the product produced. However, the subsurface mechanisms that allow the gas to move to the wellbore and the producing characteristics of coalbed methane wells are very different from traditional natural gas production. Unlike conventional gas wells, which require a porous and permeable reservoir, hydrocarbon migration and a natural structural and/or stratigraphic trap, coalbed methane gas is trapped in the molecular structure of the coal itself until released by pressure changes resulting from the removal of in situ water. Frequently, coalbeds are partly or completely saturated with water. As the water is removed, internal pressures on the coal are decreased, allowing the gas to desorb from the coal and flow to the wellbore. Unlike traditional gas wells, new coalbed methane wells often produce water for several months and then, as the water production decreases, natural gas production increases.

Coalbed methane gas production in the Hanging Woman Basin requires state permits for the use of well-site pits and evaporation ponds for the disposal of produced water. Groundwater produced from the coal seams can generally be discharged into arroyos, surface waters, well-site pits and evaporation ponds without a permit if it does not exceed surface discharge permit levels, and meets state and federal primary drinking water standards. All of these disposal options require an extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit standards. Where water of lesser quality is involved or the wells produce water in excess of the applicable volumetric permit limits, additional disposal wells may have to be drilled to re-inject the produced water back into deep underground rock formations.

A portion of our acreage at Hanging Woman Basin is on federal lands, with a segment of the lands in Montana. We are subject to delays in permitting associated with the completion of a supplemental Environmental Impact Statement covering the contemplation of phased development on Federal leases in Montana. We are also affected by considerations for sage grouse that are native to the area. Each of these issues has the potential to impact the timing of our permitting and drilling operations associated with development of our reserves at Hanging Woman Basin.

To date we have not experienced any material adverse effect on our operations from obligations under environmental laws and regulations. We believe that we are in substantial compliance with currently applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us.

Cautionary Information about Forward-Looking Statements

This Form 10-K contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “intend,” “plan,” “will” and “project” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as:

	·	The amount and nature of future capital expenditures and the availability of capital resources to fund capital expenditures;

	·	The drilling of wells and other exploration and development plans, as well as possible future acquisitions;

	·	Reserve estimates and the estimates of both future net revenues and the present value of future net revenues that are included in their calculation;

	·	Future oil and gas production estimates;

	·	Our outlook on future oil and gas prices;

	·	Cash flows, anticipated liquidity and the future repayment of debt;

	·	Business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations, and our outlook on future financial condition or results of operations; and

	·	Other similar matters such as those discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this Form 10-K.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties which may cause our actual results to differ materially from results expressed or implied by the forward-looking statements. These risks are described in the “Risk Factors” section of this Form 10-K, and include such factors as:

	·	the volatility and level of realized oil and natural gas prices;

	·	unexpected drilling conditions and results;

	·	the risks of various exploration and hedging strategies;

	·	the uncertain nature of the expected benefits from the acquisition of oil and gas properties;

	·	production rates and reserve replacement;

	·	the imprecise nature of oil and gas reserve estimates;

	·	drilling and operating service availability;

	·	uncertainties in cash flow;

	·	the financial strength of hedge contract counterparties;

	·	the availability of economically attractive exploration, development and property acquisition opportunities and any necessary financing; and

	·	competition, litigation, environmental matters, and the potential impact of government regulations.

We caution you that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those expressed or implied in the forward-looking statements. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.

Available Information

Our Internet website address is www.stmaryland.com. Through our website’s financial information section we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC.

We also make available through our website’s corporate governance section our corporate governance guidelines, code of business conduct and ethics, and the charters for our Board of Directors’ audit committee, compensation committee, executive committee and nominating and corporate governance committee. These documents are also available in print to any stockholder who requests them. Requests for these documents may be submitted to:

St. Mary Land & Exploration Company

Investor Relations

1776 Lincoln Street, Suite 700

Denver, Colorado 80203

Telephone: (303) 863-4322

Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this document.

Glossary

The terms defined in this section are used throughout this Form 10-K.

2-D seismic or 2-D data. Seismic data that is acquired and processed to yield a two-dimensional cross-section of the subsurface.

3-D seismic or 3-D data. Seismic data that is acquired and processed to yield a three-dimensional picture of the subsurface.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. Billion cubic feet, used in reference to natural gas.

BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond its known horizon.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Fee land. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated by dividing the amount of total capital expenditures for oil and gas activities, including the effect of asset retirement obligations, by the amount of estimated net proved reserves added through discoveries, acquisitions, and revisions of previous estimates during the same period. The information for this calculation is included in the note regarding disclosures about oil and gas producing activities contained in the Notes to Consolidated Financial Statements included in this Form 10-K.

Gross acre. An acre in which a working interest is owned.

Gross well. A well in which a working interest is owned.

Hydraulic fracturing. A procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability and porosity.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MBOE. One thousand barrels of oil equivalent.

MMBOE. One million barrels of oil equivalent.

Mcf. One thousand cubic feet, used in reference to natural gas.

MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

MMcf. One million cubic feet, used in reference to natural gas.

MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

MMBtu. One million British Thermal Units. A British Thermal Unit is the amount of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Net acres or net wells. The sum of our fractional working interests owned in gross acres or gross wells.

Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock.

NYMEX. New York Mercantile Exchange.

PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.

Productive well. A well that is producing oil or gas or that is capable of production.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.

Reserve replacement percentage - excluding sales. The sum of reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period of time. This is believed to be a useful non-GAAP measure that is widely utilized within the exploration and production industry as well as by investors. It is an easily calculable number and is representative of the relative success a company is having in replacing its production from its declining asset base as well as its ability to grow the overall company.

Reserve replacement percentage - including sales. The sum of sales of reserves, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period of time. This is believed to be a useful non-GAAP measure that is widely utilized within the exploration and production industry as well as by investors. It is an easily calculable number and is representative of the relative success a company is having in replacing its production from its declining asset base as well as its ability to grow the overall company.

Royalty. The share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil and gas production free of costs of exploration, development and production operations.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated net proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production, sales, and costs.

Item 1A. RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should be carefully considered when evaluating St. Mary.

Risks Related to Our Business

Oil and natural gas prices are volatile, and a decline in prices could hurt our profitability, financial condition and ability to grow.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on the prices we receive for oil and natural gas sales. Oil and gas prices also affect our cash flows and borrowing capacity, as well as the amount and value of our oil and gas reserves.

Historically, the markets for oil and gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and gas, market uncertainty and other factors that are beyond our control, including:

	·	worldwide and domestic supplies of oil and natural gas;

	·	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

	·	pipeline, transportation, or refiner capacity constraints in a regional or localized area may put downward pressure on the realized price for oil or natural gas;

	·	political instability or armed conflict in oil or gas producing regions;

	·	worldwide and domestic economic conditions;

	·	the level of consumer demand;

	·	the availability of transportation facilities;

	·	weather conditions; and

	·	governmental regulations and taxes.

These factors and the volatility of oil and gas markets make it very difficult to predict future oil and gas price movements with any certainty. Declines in oil or gas prices would reduce our revenues and could also reduce the amount of oil and gas that we can produce economically and therefore could have a material adverse effect on us.

If we are not able to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. Our properties produce oil and gas at a declining rate over time. In order to maintain current production rates we must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We may do this even during periods of low oil and gas prices. In addition, competition for the acquisition of producing oil and gas properties is intense and many of our competitors have financial and other resources for acquisitions that are substantially greater than those available to us. Therefore, we may not be able to acquire oil and gas properties that contain economically recoverable reserves, or we may not be able to acquire such properties at prices acceptable to us. Without successful drilling or acquisition activities, our reserves, production and revenues will decline rapidly.

Competition in our industry is intense, and many of our competitors have greater financial and technical resources than we do.

We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers, and institutional and individual investors who are actively seeking oil and gas properties throughout the world, along with the equipment, expertise, labor and materials required to operate oil and gas properties. Many of our competitors have financial and technical resources vastly exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties or in which our competitors have technological information or expertise to evaluate and successfully bid for the properties that is not available to us. In addition, shortages of equipment, labor or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition.

We compete for people. As drilling activities have accelerated, the need for talented people has grown at a time when the number of people available is constrained.

The actual quantities and present values of our proved oil and gas reserves may be less than we have estimated.

This Form 10-K and other SEC filings by us contain estimates of our proved oil and gas reserves and the estimated future net revenues from those reserves. Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and therefore changes often occur as these variables evolve and commodity prices fluctuate. Therefore, these estimates are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present values of proved reserves disclosed by us, and the actual quantities and present values may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

As of December 31, 2005, approximately 18 percent of our estimated proved reserves (by volume) were proved undeveloped. Estimates of proved undeveloped reserves and proved developed non-producing reserves are nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. Our estimates of proved undeveloped reserves assume that we will make significant capital expenditures to develop these reserves, including an estimated $153 million in 2006. Although we have estimated our reserves and the costs associated with these reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.

You should not assume that the PV-10 values included in this Form 10-K represent the current market value of our estimated oil and natural gas reserves. Management has based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, in accordance with SEC requirements, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2005, were estimated using a calculated weighted-average sales price of $10.08 per Mcf of gas (Gulf Coast spot price) and $61.04 per Bbl of oil (NYMEX). We ensure that we consider basis and location differentials as of that date in estimating our reserves. During 2005 our monthly average realized gas prices, excluding the effect of hedging, were as high as $12.69 per Mcf and as low as $6.06 per Mcf. For the same period our monthly average realized oil prices were as high as $61.59 per Bbl and as low as $44.38 per Bbl. Many other factors will affect actual future net cash flows, including:

	·	the amount and timing of actual production;

	·	supply and demand for oil and natural gas;

	·	curtailments or increases in consumption by oil and natural gas purchasers; and

	·	changes in governmental regulations or taxes.

The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10 values. In addition, the ten percent discount factor required by the SEC to be used to calculate PV-10 values for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business and the oil and natural gas industry in general are subject.

Our producing property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain.

In connection with our acquisitions, we perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the deficiencies and potential of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and gas properties with economically recoverable reserves on acceptable terms.

In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited.

Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions.

Exploration and development drilling may not result in commercially productive reserves.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas will be found. The cost of drilling and completing wells is often uncertain, and oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

	·	unexpected drilling conditions;

	·	title problems;

	·	pressure or irregularities in formations;

	·	equipment failures or accidents;

	·	adverse weather conditions;

	·	compliance with environmental and other governmental requirements;

	·	shortages or delays in the availability of or increases in the cost of drilling rigs and the delivery of equipment; and

	·	shortages in availability of experienced drilling crews.

The prevailing prices of oil and gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies that we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry wells or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.

Our future drilling activities may not be successful, or our overall drilling success rate or our drilling success rate for activity within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.

Our hedging transactions may limit the prices that we receive for oil and gas sales and involve other risks.

To manage our exposure to price risks in the sale of our oil and natural gas, we enter into commodity price risk management arrangements from time to time with respect to a portion of our current or future production. We have hedged a significant portion of anticipated future production from our currently producing properties using zero-cost collars and swaps. Commodity price hedging may limit the prices that we receive for our oil and gas sales if oil or natural gas prices rise substantially over the price established by the hedge. In addition, these transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

	·	our production is less than expected; or

	·	the counterparties to our hedge contracts fail to perform under the contracts.

Some of our hedging agreements may also require us to furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by us to the counterparties, which would encumber our liquidity and capital resources. In addition, some of our hedging transactions use derivative instruments that may involve basis risk. Basis risk in a hedging contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.

Future oil and gas price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.

The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write-down the costs of each such field to our estimate of fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.

We review the carrying value of our properties quarterly based on prices in effect as of the end of each quarter or as of the time of reporting our results. Once incurred, a writedown of oil and gas properties cannot be reversed at a later date even if oil or gas prices increase.

Substantial capital is required to replace our reserves.

We need to make substantial capital expenditures to find, acquire, develop and produce oil and natural gas reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, our success in locating and producing new reserves and prices of oil and natural gas. If oil or gas prices decrease or we encounter operating difficulties that result in our cash flows from operations being less than expected, we may have to reduce our capital expenditures unless we can raise additional funds through debt or equity financing. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms.

If our revenues were to decrease due to lower oil or gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facility or other acceptable debt or equity financing arrangements, our ability to execute our development plans, replace our reserves or maintain production levels could be greatly limited.

A decrease in oil or gas prices could limit our ability to borrow under our credit facility.

Our credit facility has a maximum loan amount of $500 million, subject to a borrowing base that the lenders periodically redetermine based on the value of our oil and gas properties, which in turn is based in part on oil and gas prices. Lower oil or gas prices in the future could limit our borrowing base and reduce our ability to borrow under the credit facility.

We could incur substantial additional debt, which could limit our financial flexibility.

As of December 31, 2005, we had $100.0 million in outstanding long-term debt under our 5.75 % Senior Convertible Notes due 2022. Our long-term debt represented 15 percent of our total book capitalization as of December 31, 2005. Our credit facility has a maximum loan amount and current borrowing base of $500 million, with a current commitment amount we have elected of $200 million, against which no borrowings were outstanding as of December 31, 2005.

Our level of debt could have important consequences for our operations, including:

	·	requiring us to dedicate a substantial portion of our cash flows from operations to make required payments on debt, thereby reducing the availability of cash flows for working capital, capital expenditures and other general business activities;

	·	limiting our ability to obtain additional financing in the future for working capital, capital expenditures and other general business activities, or increasing the costs for such additional financing;

	·	limiting our flexibility in planning for, or reacting to, changes in our business and our industry; and

	·	increasing our vulnerability to adverse effects from a downturn in our business or the general economy.

We may incur additional debt, including secured debt under our credit facility or otherwise, in order to make future acquisitions or to develop our properties. An increased level of debt increases the risk that we may default on our debt obligations. We may not be able to generate sufficient cash flow from operations or be able to make other arrangements for the repayment or refinancing of the debt.

In addition, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing or arrange new financing, we may be forced to sell significant assets.

We are subject to operating and environmental risks and hazards that could result in substantial losses.

Oil and gas operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, adverse weather such as hurricanes in the Gulf Coast region, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.

Under certain limited circumstances we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

Following the hurricanes in 2004 and 2005, the insurance markets have suffered significant losses. As a result, the availability of coverage and the cost at which such coverage will be available in the future is uncertain.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant, but limited coverage for sudden environmental damages. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks presented. Accordingly, we may be subject to liability or may lose substantial portions of certain properties in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss.

Our operations are subject to complex laws and regulations, including environmental regulations, that result in substantial costs and other risks.

Federal, state and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. Noncompliance with statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability.

Governmental authorities regulate various aspects of oil and gas drilling and production, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. To cover the various obligations of leaseholders in federal waters, federal authorities generally require that leaseholders have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or other assurances can be substantial, and we may not be able to obtain bonds or other assurances in all cases. Under limited circumstances, federal authorities may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could have a material adverse effect on our operations. Our development at Hanging Woman Basin is particularly affected, as a portion of our acreage is on federal lands.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We could face significant liabilities to governmental authorities and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, may have a material adverse effect on us.

We depend on transportation facilities owned by others.

The marketability of our oil and gas production depends in part on the availability, proximity and capacity of pipeline transportation systems owned by third parties. The lack of available transportation capacity on these systems and facilities could result in the shutting-in of producing wells, the delay or discontinuance of development plans for properties, or lower price realizations. Although we have some contractual control over the transportation of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Ownership of royalty interests by an executive officer may create conflicts of interest.

As a result of his employment with another company prior to 1995, with which St. Mary engaged in a number of transactions, Kevin E. Willson, an executive officer of St. Mary, owns royalty interests in a number of our properties, which were earned as part of the prior employer’s employee benefit programs. Accordingly, conflicts of interest may exist between Mr. Willson and us, and such conflicts may not always be resolved in our favor.

Risks Related to Our Common Stock

The price of our common stock may fluctuate significantly, which may result in losses for investors.

From January 1, 2004, to February 15, 2006, the last daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $13.92 per share to a high of $44.23 per share, as adjusted to reflect our 2-for-1 stock split effected in the form of a stock dividend on March 31, 2005. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:

	·	changes in oil or natural gas prices;

	·	variations in quarterly drilling, recompletions, acquisitions and operating results;

	·	changes in financial estimates by securities analysts;

	·	changes in market valuations of comparable companies;

	·	additions or departures of key personnel; and

	·	future sales of our common stock.

We may fail to meet expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result.

Our certificate of incorporation and bylaws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment.

Our certificate of incorporation and bylaws contain provisions that may have the effect of delaying or preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the election of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of Directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other and with the shareholder rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.

Under our shareholder rights plan, if the Board of Directors determines that the terms of a potential acquisition do not reflect the long-term value of St. Mary, the Board of Directors could allow the holder of each outstanding share of our common stock other than those held by the potential acquirer to purchase one additional share of our common stock with a market value of twice the exercise price. This prospective dilution to a potential acquirer would make the acquisition impracticable unless the terms were improved to the satisfaction of the Board of Directors. The existence of the plan may impede a takeover not supported by our Board even though such takeover may be desired by a majority of our stockholders or may involve a premium over the prevailing stock price.

Our shares that are eligible for future sale may have an adverse effect on the price of our common stock.

As of February 15, 2006, we had 56,953,893 shares of common stock outstanding, net of 250,000 shares held in treasury. Of the net shares outstanding, 55,595,375 shares were freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. Also as of that date, options to purchase 4,506,090 shares of our common stock were outstanding, of which 3,929,271 were exercisable. These options are exercisable at prices ranging from $4.62 to $20.87 per share. In addition, restricted stock units providing for the issuance of up to a total of 632,809 shares of our common stock were outstanding. Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of options and restricted stock units to issue shares of common stock at prices that may be below the then-current market price of the common stock could adversely affect the market price of the common stock and could impair our ability to raise capital through the sale of our equity securities.

We may not always pay dividends on our common stock.

The payment of future dividends remains in the discretion of the Board of Directors and will continue to depend on our earnings, capital requirements, financial condition and other factors. In addition, the payment of dividends is subject to covenants in our credit facility, including a covenant regarding the level of our current ratio of current assets to current liabilities and a limit on the annual dividend rate that we may pay no more than $0.25 per share. The Board of Directors may determine in the future to reduce the current annual dividend rate of $0.10 per share or discontinue the payment of dividends altogether.

A director and his extended family may be able to exert influence over us.

Thomas E. Congdon, a director and our former Chairman of the Board, and members of his extended family are estimated to own between five and ten percent of the outstanding shares of our common stock as of February 15, 2006. While no formal arrangements exist, these extended family members could be inclined to act in concert with Mr. Congdon on matters related to control of St. Mary, including for example the election of directors or response to an unsolicited proposal to acquire St. Mary. Accordingly, Mr. Congdon and his family may be able to influence matters presented to our Board of Directors and stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS

St. Mary has no unresolved comments from the SEC staff regarding its periodic or current reports under the Securities Act of 1934.

ITEM 2. PROPERTIES

Operations

St. Mary's exploration, development and acquisition activities are focused in five core operating areas: the Rocky Mountain region; the Mid-Continent region; the ArkLaTex region; the Gulf Coast region; and the Permian Basin region. Our Hanging Woman Basin project is within our Rocky Mountain region and is managed by the personnel from our Billings office. Information concerning each of our major areas of operations is shown below in the summary of our estimated proved reserves as of December 31, 2005.

	Estimated Proved Reserves
	Oil		Gas		MMCFE				PV-10 Value
	(MBbl)		(MMcf)		Amount		Percent		(In thousands)		Percent

Rocky Mountain		52,870		85,492		402,712		50.7	$	1,210,496		48.5
Hanging Woman Basin		-		25,219		25,219		3.1		65,638		2.6
Total Rocky Mountain		52,870		110,711		427,931		53.8		1,276,134		51.1
Mid-Continent		1,554		166,041		175,365		22.1		583,188		23.4
ArkLaTex		1,015		105,196		111,286		14.0		313,503		12.6
Gulf Coast		349		27,913		30,007		3.8		182,398		7.3
Permian Basin		7,115		7,214		49,904		6.3		138,946		5.6
Total		62,903		417,075		794,493		100.0	$	2,494,169		100.0

Rocky Mountain Region. Nance Petroleum Corporation, a wholly owned subsidiary of St. Mary, has conducted operations in the Williston Basin in eastern Montana and western North Dakota since 1991. Our office in Billings, Montana has a 95 full-time person staff. We have expanded this area into the Greater Green River, Powder River, Big Horn and Wind River basins of Wyoming over the past three years. The largest growth in the region came in late 2002 and early 2003 with significant property acquisitions from Burlington Resources and Flying J. These transactions brought with them a tremendous acreage position that has precipitated additional growth in this region.

St. Mary spent $196.9 million in 2005 on exploration, development and acquisitions in the Rocky Mountain region, including Hanging Woman Basin, with $134.1 million of this directed towards drilling. The regional growth of reserves in 2005 was the most pronounced from the Bakken development in eastern Montana. Other organic growth has come from continued development of the Red River formation using smaller 3-D seismic surveys. We have successfully used 3-D seismic imaging to delineate structure and porosity development in this formation. The other significant drilling program is at our Hanging Woman Basin coalbed methane development in the northern Powder River Basin. In 2005, we spent $22.6 million drilling 131 wells and building infrastructure. Production from Hanging Woman Basin began in mid-December 2004, was 0.5 Bcf in 2005, and has exceeded our expectations. Because of potential permitting delays, dewatering time and low production rates per well, it will take a number of years to develop the field to the point of having production volumes that are meaningful to our total production.

Other recent transactions were the 2004 acquisition of Goldmark Engineering where we acquired a position in a mature oil field in the Big Horn Basin, and where we will focus on enhancement of wells that produce from the Tensleep formation. Our presence in Wyoming expanded in August 2005 when we acquired oil and gas properties in the Wind River, Powder River, and Greater Green River Basins for $37.1 million in cash. The allocation of the purchase price resulted in recording $43.9 million to proved and unproved oil and gas properties and a $7.0 million asset retirement obligation. This added approximately 32 BCFE of proved reserves as of the acquisition date.

Conventional oil and gas properties in the Rocky Mountain region accounted for 51 percent of our estimated proved reserves as of December 31, 2005, or 402.7 BCFE, 82 percent of which are proved developed and 79 percent of which are oil.

Our capital budget for the Rocky Mountain region now represents the largest portion of our drilling budget at approximately $191 million for 2006. This budget is distributed over several key programs, including approximately $50 million in the Hanging Woman Basin where we have approximately 260 wells planned for the year. A risk of development at Hanging Woman Basin for 2006 will be the ability to successfully obtain the necessary regulatory approval of our water development plan on state and fee acreage for approximately 60 wells in Montana. Additionally, we have another 60 wells in Wyoming that the timing of drilling could be affected by considerations relating to the mating season for sage grouse. There are approximately 30 wells planned in the Bakken formation with total capital of $47 million. We are initiating a horizontal drilling program focusing in the Ratcliffe and Mission Canyon formations with $24 million of the budget allocated for the drilling of approximately 26 wells. The planned development of the Tensleep formation results in approximately $9 million of the budget being allocated to the Fourbear, Murphy Dome and Big Sand Draw fields. The remainder is planned for our Red River program and development in the Greater Green River Basin.

On average we have a high working interest in our wells in the Rocky Mountain region. In 425 wells we have a working interest greater than 90 percent. Including the Hanging Woman Basin development, we will be the operator of properties representing approximately 84 percent of our 2006 Rocky Mountain region capital budget.

Our reserves in the Bakken are approximately 69 BCFE, representing nearly nine percent of our total reserve volumes and ten percent of our PV-10 value. The reserves in the Bakken are 83 percent oil. We have 92 wells predominately in Richland County, Montana and 70 wells concentrated in Mackenzie County, North Dakota. The Montana wells are produced from the Bakken dolomite while the North Dakota wells are mostly Bakken shale wells. The working interest in the Montana wells average 49 percent and the North Dakota ownership averages 61 percent.

Mid-Continent Region. St. Mary has been active in the Mid-Continent region since 1973. Operations for the region are managed by our 45 full-time person office in Tulsa, Oklahoma. Our long history of operations and proprietary geologic knowledge enables us to sustain economic development and exploration programs despite periods of adverse industry conditions. We apply current technology in horizontal drilling, hydraulic fracturing and innovative well completion techniques to accelerate production and associated cash flow from the region’s tight gas reservoirs and developing plays. We are currently working to determine the best completion methods in our Wapanucka limestone, Cromwell sandstone and Woodford shale formations, commonly referred to as our Centrahoma area, located in Coal County, Oklahoma. We also attempt to benefit from the continuing consolidation of operators in the basin as we pursue attractive acquisition opportunities.

The Northeast Mayfield area is the largest concentration of our reserves and is located in Beckham County, Oklahoma on the western edge of the Anadarko Basin. This field represents 36.6 BCFE, or nearly five percent, of our total proved reserves and $110.0 million, or approximately four percent, of our total PV-10 value. Our average working interest in this field is 29 percent, and we have an interest in approximately 106 gross wells of which we operate 41 percent.

Other significant fields in the Mid-Continent region are the Centrahoma field in Coal County, Oklahoma and the Constitution field in Jefferson County, Texas. Centrahoma represents five percent of total proved reserves and $82.8 million, or three percent, of total PV-10 value. The Constitution field represents two percent of total proved reserves and $98.7 million of PV-10 value. We operate approximately 85 percent of the wells we have an interest in located in the Centrahoma area. We do not act as operator in the Constitution field. Other significant fields in the Mid-Continent region are the Elk City field and the Southwest Mayfield field, both in Beckham County, Oklahoma, representing a total of two percent of proved reserves and three percent of total PV-10 value. We operate 14 percent of the wells in Elk City and 45 percent of the wells in Southwest Mayfield and have an average working interest of approximately 15 and 42 percent, respectively.

We have ongoing exploration and development programs in the Anadarko and Arkoma basins, principally located in Oklahoma. The Mid-Continent region accounts for 22 percent of our estimated proved reserves as of December 31, 2005, or 175.4 BCFE, 79 percent of which are proved developed and 95 percent of which are natural gas. In 2005 our capital expenditures in the Mid-Continent were $135.6 million. We participated in drilling 91 gross wells in this region, 87 percent of which were completed as producers. We operated 28 of these drilling projects.

St. Mary's development and exploration budget in the Mid-Continent region for 2006 totals $172 million, an increase of $64 million over 2005. The 2006 budget includes $66 million of planned drilling expenditures associated with 46 budgeted Northeast Mayfield Atoka wells. Exploration efforts in 2004 and early 2005 have built a foundation for this viable multi-year play in the Atoka and Granite Wash formations at Northeast Mayfield. The other area of focus in the Mid-Continent Region is the Centrahoma area where we plan to spend $42 million on 19 wells developing the Wapanucka limestone, Cromwell sandstone and Woodford shale formations. We plan to be the operator of properties representing approximately 74 percent of our capital budget in this region during 2006 and to utilize seven drilling rigs that we will operate throughout the year.

We have allocated $21 million of our 2006 drilling budget to low-to-medium-risk development in the Red Fork, Osborne, Cottage Grove and Cleveland formations.

ArkLaTex Region. Our 21 full-time person office in Shreveport, Louisiana manages St. Mary’s operations in the ArkLaTex region. The ArkLaTex region accounts for 14 percent of our estimated proved reserves as of December 31, 2005, or 111.3 BCFE, 56 percent of which are proved developed and 95 percent of which are natural gas. Reserve growth in this region was derived primarily from recognition of the proved reserves from the Elm Grove field acquisition that we completed at the end of 2004. In 2006 we plan to spend $12 million on development at Elm Grove. This amount represents 41 percent of the total $66 million budget for the ArkLaTex region. The budget targets horizontal wells in the James, Glen Rose, Rodessa, and Pettet carbonate formations as well as vertical development in the Cotton Valley and Travis Peak formations at Terryville. Many of the Shreveport office’s successful exploration and development programs have derived from niche acquisitions. These acquisitions have provided access to strategic holdings of undeveloped acreage and proprietary packages of geologic and seismic data resulting in an active program of development and exploration.

Our holdings in the ArkLaTex region are comprised of interests in approximately 714 gross producing wells, including 139 wells we operated. We also hold interests in leases totaling approximately 157,000 gross acres and mineral servitudes totaling approximately 14,700 gross acres. Our capital expenditures in this region in 2005 were $44.0 million, including the effect of asset retirement obligations.

Our ownership at Elm Grove is six percent of our total proved reserves, representing $101.8 million of PV-10 value. We have an ownership interest in Elm Grove that is represented by 479 well locations, including PUD locations; with a working interest of up to 37 percent. Following our ownership in Elm Grove, the next most significant concentration of properties are the Spider and Box Church fields, which include a combined three percent or 24.1 BCFE of proved reserves and four percent of our total PV-10 value. We have working interests in 21 gross wells in Spider and 38 gross wells in Box Church, all of which we operate.

Gulf Coast Region. St. Mary’s presence in south Louisiana dates to the early 1900’s when our founders acquired a franchise property in St. Mary Parish on the shoreline of the Gulf of Mexico. These 24,914 acres of fee lands yielded $3.4 million of gross oil and gas royalty revenue in 2005. Our Gulf Coast region presence expanded as a result of the acquisition of King Ranch Energy, Inc. in 1999. Including the Louisiana fee lands, the Gulf Coast region accounts for four percent of our estimated proved reserves as of December 31, 2005, or 30.0 BCFE, 87 percent of which are proved developed and 93 percent of which are natural gas. Of this 30.0 BCFE, 72 percent is onshore and 28 percent is offshore in the Gulf of Mexico and coastal Texas and Louisiana. We spent $36.8 million, including the effect of asset retirement obligations, on capital expenditures in 2005.

Our 18 full-time person team based in Houston, Texas, manages St. Mary’s diverse activities in our Gulf Coast and Permian Basin regions. Our exploration and development budget in the Gulf Coast region for 2006 is $67 million, which consists of planned activity both onshore and offshore projects in Texas and Louisiana as well as low to moderate risk direct hydrocarbon indicators in state and federal waters of the Gulf of Mexico. We plan to operate approximately 42 percent of the 2006 forecasted drilling projects.

The most significant field in the Gulf Coast region is the Judge Digby Field, located outside Baton Rouge, Louisiana, in Point Coupee Parish. As of the end of December 2005, this field represented slightly less than three percent of our total PV-10 value, with 11.6 BCFE of proved reserves. Production from the Judge Digby field totaled 3.3 BCFE in 2005.

Permian Basin Region. The Permian Basin area covers a significant portion of eastern New Mexico and western Texas and is one of the major producing basins in the United States. The basin includes hundreds of oil fields undergoing secondary and enhanced oil recovery projects. The use of 3-D seismic imaging of existing fields and advanced secondary recovery programs are substantially increasing oil recoveries. Our holdings in the Permian Basin resulted from a series of property acquisitions beginning in 1996. We believe that our Permian Basin operations provide us with a solid base of long-lived oil reserves and the potential for additional secondary recovery projects. In 2005, we spent $7.7 million on capital expenditures, including the effect of asset retirement obligations, in the Permian Basin region. This region accounted for 49.9 BCFE, or six percent of our proved reserves as of December 31, 2005. The PV-10 value associated with the Permian Basin was $139.0 million at year end. Our Permian reserves are 86 percent proved developed and 86 percent oil.

The Parkway Delaware waterflood project, located in Eddy County, New Mexico, represents 17.9 BCFE or two percent of our proved reserves. The East Shugart Delaware Unit is a pilot waterflood located in Lea and Eddy Counties, New Mexico, that is analogous to the Parkway Delaware Unit and is comprised of 17.5 BCFE of proved reserves. Production from the Permian Basin properties represented 2.9 BCFE or three percent of total production for the Company in 2005.

Our Permian Basin capital expenditures budget for 2006 is $4 million. We plan to drill three infill wells at Parkway Delaware during 2006.

Acquisitions and Divestitures

We spent a total of $87.8 million on acquisitions of proved and unproved oil and gas properties in 2005. The two most significant acquisitions, Agate Petroleum, Inc., and properties from Wold Oil Properties, Inc., accounted for $77.1 million. We also made several smaller acquisitions in 2005. We purchased a total of 49.8 BCFE of proved reserves in 2005.

Significant acquisitions prior to 2005 include the 2004 acquisitions of oil and gas properties from Goldmark Engineering, Inc., in the Rocky Mountain region and from Border Company in the ArkLaTex region. In January 2003 we acquired oil and gas properties in the Rocky Mountain region from Flying J Oil & Gas, Inc.

Reserves

The following table presents summary information with respect to the estimates of our proved oil and gas reserves for each of the years in the three year period ended December 31, 2005. The table includes reserves prepared by independent petroleum engineering firms, Ryder Scott Company and Netherland, Sewell & Associates, Inc., and us. For the periods presented, Ryder Scott Company and Netherland, Sewell & Associates, Inc., evaluated properties representing a minimum of 80 percent of the total PV-10 value of our reserves. The proved oil and gas reserves prepared by Netherland Sewell in 2004 and 2005 consist of the coalbed methane development at Hanging Woman Basin as well as our non-operated interest at Atlantic Rim. The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor costs have been escalated. You should read the following table along with the section entitled “Risk Factors - Risks Related to Our Business - Estimates of oil and gas reserves are not precise.”

	As of December 31,
Proved Reserves Data:	2005		2004		2003
Oil (MBbl)		62,903		56,574		47,787
Gas (MMcf)		417,075		319,196		307,024
MMCFE		794,493		658,638		593,744
PV-10 value (in thousands)	$	2,494,169	$	1,501,123	$	1,278,165
Standardized measure of discounted future net cash flows (in thousands)	$	1,712,298	$	1,033,938	$	859,956
Proved developed reserves		82%		85%		89%
Reserve replacement - including sales		256%		186%		234%
Reserve replacement - excluding sales		256%		190%		293%
Reserve life (years) (1)		9.1		8.7		7.7

________________

(1)

Reserve life represents the estimated proved reserves at the dates indicated divided by actual production for the preceding 12-month period.

Production

The following table summarizes the average volumes and realized prices, including and excluding the effects of hedging, of oil and gas produced from properties in which St. Mary held an interest during the periods indicated. Also presented is a production cost per MCFE summary for the Company.

	Years Ended December 31,
	2005		2004		2003
Operating data:
Net production:
Oil (MBbl)		5,927		4,799		4,541
Gas (MMcf)		51,801		46,598		49,663
MMCFE		87,363		75,393		76,909
Average net daily production:
Oil (Bbl)		16,238		13,113		12,441
Gas (Mcf)		141,922		127,316		136,062
MCFE		239,352		205,992		210,709
Average realized sales price, excluding the effects of hedging:
Oil (per Bbl)	$	53.18	$	39.77	$	29.40
Gas (per Mcf)	$	8.08	$	5.85	$	5.12
Per MCFE	$	8.40	$	6.15	$	5.04
Average realized sales price, including the effects of hedging:
Oil (per Bbl)	$	50.93	$	32.53	$	26.96
Gas (per Mcf)	$	7.90	$	5.52	$	4.89
Per MCFE	$	8.14	$	5.48	$	4.75
Production costs per MCFE:
Lease operating expense	$	0.99	$	0.81	$	0.77
Transportation expense	$	0.09	$	0.10	$	0.09
Production taxes	$	0.56	$	0.36	$	0.29

Productive Wells

As of December 31, 2005, we had working interests in 1,722 gross (843 net) productive oil wells and 2,750 gross (679 net) productive gas wells. Productive wells are either producing wells or wells capable of commercial production although currently shut in. One or more completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

Drilling Activity

All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not own any drilling equipment. The following table sets forth the wells drilled and recompleted in which St. Mary participated during each of the three years indicated:

	Years Ended December 31,
	2005				2004				2003
	Gross		Net		Gross		Net		Gross		Net
Development:
Oil		83		38.09		50		18.08		36		14.88
Gas		379		152.69		180		53.23		140		43.79
Non-productive		29		9.12		36		14.29		37		15.98
		491		199.90		266		85.60		213		74.65
Exploratory:
Oil		8		1.91		11		9.71		7		3.03
Gas		5		0.86		83		43.65		14		7.20
Non-productive		5		2.32		8		2.84		7		4.40
		18		5.09		102		56.20		28		14.63

Farmout or non-consent		18		-		5		-		10		-
Total (1)		527		204.99		373		141.80		251		89.28

________________

(1)

Does not include nine, seven, and 15 gross wells completed on St. Mary's fee lands during 2005, 2004 and 2003, respectively, in which we have only a royalty interest.

Acreage

The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases, fee properties, mineral servitudes and lease options held by St. Mary as of December 31, 2005. Undeveloped acreage includes leasehold interests that may already have been classified as containing proved undeveloped reserves.

	Developed Acres (1)				Undeveloped Acres (2)				Total
	Gross		Net		Gross		Net		Gross		Net

Arkansas		3,365		420		207		68		3,572		488
Colorado		2,885		2,470		24,832		13,914		27,717		16,384
Louisiana		127,636		44,875		32,199		13,232		159,835		58,107
Mississippi		3,335		467		2,610		1,361		5,945		1,828
Montana		58,062		36,668		446,549		297,671		504,611		334,339
New Mexico		5,600		2,658		1,320		1,187		6,920		3,845
North Dakota		174,333		94,791		172,955		103,896		347,288		198,687
Oklahoma		281,996		81,336		44,270		26,338		326,266		107,674
Texas		128,265		34,429		48,417		24,689		176,682		59,118
Utah (3)		480		115		11,472		4,091		11,952		4,206
Wyoming		139,801		92,424		389,870		224,611		529,671		317,035
Other (4)		2,281		985		4,144		1,265		6,425		2,250
		928,039		391,638		1,178,845		712,323		2,106,884		1,103,961

Louisiana Fee Properties		9,944		9,944		14,970		14,970		24,914		24,914
Louisiana Mineral Servitudes		10,173		5,740		4,490		4,128		14,663		9,868
		20,117		15,684		19,460		19,098		39,577		34,782
Total		948,156		407,322		1,198,305		731,421		2,146,461		1,138,743

________________

	(1)	Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of St. Mary's properties that include multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above.
	(2)	Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated proved reserves.
	(3)	St. Mary holds an overriding royalty interest in an additional 40,100 gross acres in Utah.
	(4)	Includes interests in Alabama, Kansas, Nebraska, Nevada and South Dakota.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a material adverse effect upon our financial condition or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of our security holders during the fourth quarter of 2005.

Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names, ages and positions held by St. Mary’s executive officers. The ages of the executive officers are as of February 15, 2006.

Name	Age	Position

Mark A. Hellerstein	53	Chairman of the Board, President and Chief Executive Officer
Douglas W. York	44	Executive Vice President and Chief Operating Officer
Robert L. Nance	69	Senior Vice President and President and Chief Executive Officer of Nance Petroleum Corporation, a wholly-owned subsidiary of St. Mary
Jerry R. Schuyler	50	Senior Vice President and Regional Manager
Kevin E. Willson	49	Senior Vice President and Regional Manager
Robert T. Hanley	59	Vice President - Investor Relations and Management Reporting
David W. Honeyfield	39	Vice President - Chief Financial Officer, Treasurer and Secretary
Milam Randolph Pharo	53	Vice President - Land and Legal
Paul M. Veatch	39	Vice President - General Manager, ArkLaTex
Garry A. Wilkening	55	Vice President - Administration and Controller

Each executive officer has held his respective position during the past five years, except as follows:

Mark A. Hellerstein was appointed Chairman of the Board in September 2002.

Douglas W. York was appointed Executive Vice President and Chief Operating Officer in September 2003. Mr. York served as Vice President - Acquisitions and Reservoir Engineering from 1996 to September 2003. On December 15, 2005, Mr. York notified St. Mary that it is his intention to resign from the offices of Executive Vice President and Chief Operating Officer during the first quarter of 2006.

Robert L. Nance was appointed Senior Vice President in March 2001.

Jerry R. Schuyler joined St. Mary in December 2003 as Senior Vice President and Regional Manager of the Gulf Coast region. From November 2001 to July 2002, Mr. Schuyler was Senior Vice President and General Manager - Eastern Onshore Division for Dominion Exploration & Production, Inc., where he managed all operations and exploration for Dominion’s Gulf Coast and eastern onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler was Senior Vice President and General Manager of Dominion’s Onshore U.S. Division, where he managed all operations and exploration for all of Dominion’s onshore U.S. regions.

Kevin E. Willson was appointed Senior Vice President and Regional Manager in November 2003. Mr. Willson served as Vice President - Mid-Continent Exploration/Production from October 1998 to November 2003.

Robert T. Hanley was appointed Vice President - Investor Relations and Management Reporting in April 2003. Mr. Hanley served as Vice President - Business Development from July 2000 to April 2003.

David W. Honeyfield was appointed Chief Financial Officer in May 2005. Mr. Honeyfield joined St. Mary in May 2003 as Vice President - Finance, Treasurer and Secretary. Prior to joining St. Mary, Mr. Honeyfield was Controller and Chief Accounting Officer of Cimarex Energy Co. from September 2002 to May 2003 and Controller and Chief Accounting Officer of Key Production Company, Inc., which was acquired by Cimarex in September 2002. Prior to joining Key Production Company in April 2002, Mr. Honeyfield was a senior audit manager with Arthur Andersen LLP in Denver.

Paul M. Veatch was determined by the Board of Directors to be an executive officer of the Company in February 2006. Mr. Veatch was appointed Vice President and General Manager of the ArkLaTex Region in September 2004. Mr. Veatch joined St. Mary in April 2001 and has served as Regional Acquisition Engineer & Manager of Engineering. Prior to joining St. Mary, Mr. Veatch had been with Burlington Resources in Denver, Colorado, and Midland, Texas.

Executive officers generally are elected at the regular meeting of the Board immediately following the annual stockholders meeting, to serve for the ensuing year or until their successors are duly qualified and elected. The executive officers of St. Mary do not have fixed terms and choose to serve at the discretion of the Board of Directors. Any officer elected or appointed by the Board may be removed by the Board with or without cause, subject to any contractual rights of the person so removed.

Mr. Hellerstein has an employment agreement with St. Mary. The agreement is in effect until June 30, 2007. Upon any termination of the employment of Mr. Hellerstein by St. Mary before June 30, 2007, for any reason other than death, disability or misconduct by Mr. Hellerstein, St. Mary is generally obligated to continue to pay his base salary, additional bonus and incentive compensation, and other fringe benefits until June 30, 2007.

There are no family relationships between any executive officer and any other executive officer or director. There are no arrangements or understandings between any officer and any other person pursuant to which that officer was elected.

PART II

ITEM 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information. St. Mary's common stock is currently traded on the New York Stock Exchange under the symbol SM. The range of high and low sales prices for the quarterly periods in 2005 and 2004, as reported by the New York Stock Exchange and adjusted for the two-for-one stock split effected in the form of a stock dividend which was distributed on March 31, 2005 to shareholders of record as of March 21, 2005, is set forth below:

Quarter Ended	High		Low
December 31, 2005	$	41.14	$	30.52
September 30, 2005		37.80		28.89
June 30, 2005		30.45		21.46
March 31, 2005		26.73		19.45

December 31, 2004	$	21.50	$	18.56
September 30, 2004		20.07		15.88
June 30, 2004		18.60		15.90
March 31, 2004		17.07		13.87

Holders. As of February 15, 2006, the number of record holders of St. Mary's common stock was 135. Management believes, after inquiry, that the number of beneficial owners of our common stock is in excess of 7,100.

Dividends. St. Mary has paid cash dividends to stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. An annual dividend of $0.10 per share was paid in 2005. We expect that our practice of paying dividends on our common stock will continue, although the payment of future dividends will continue to depend on our earnings, capital requirements, financial condition and other factors. In addition, the payment of dividends is subject to covenants in our credit facility, including the requirement that we maintain certain levels of stockholders’ equity and the limitation of our annual dividend rate to no more than $0.25 per share. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $5.7 million in 2005 and $2.8 million in 2004.

Restricted Shares. Aside from Rule 144 restrictions on shares for insiders, shares subject to transfer restrictions under the provisions of the Employee Stock Purchase Plan and restricted shares issued under the Non-Employee Director Stock Compensation Plan, St. Mary has no restricted shares outstanding as of December 31, 2005.

Issuer Purchases of Equity Securities. St. Mary repurchased a total of 1,175,282 shares of its common stock during 2005.

Equity Compensation Plans. St. Mary has a stock option plan, a restricted stock plan, an incentive stock option plan, an employee stock purchase plan, and a non-employee director stock compensation plan under which options and shares of St. Mary common stock are authorized for grant or issuance as compensation to eligible employees, consultants and members of the Board of Directors. Our stockholders have approved each of these plans. See Note 7 - Compensation Plans in the Notes to Consolidated Financial Statements included in Part IV, Item 15 of this report for further information about the material terms of these plans. The following table is a summary of the shares of common stock authorized for issuance under our equity compensation plans as of December 31, 2005:

	( a )		( b )	( c )
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)

Stock Option Plan and Incentive Stock Option Plan	4,698,243	$	12.21	-	(2	)
Restricted Stock Plan	632,809		N/A	1,063,617	(2	)
Employee Stock Purchase Plan	-		-	1,655,391	(1	)
Non-Employee Director Stock Compensation Plan	-		N/A	20,874

Equity compensation plans not approved by security holders	-		-	-

Total	5,331,052	$	12.21	2,739,882

______________

(1)

Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP are restricted for a period of 18 months from the date issued. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code.

(2)

There is a common pool of shares available for the Stock Option, Incentive Stock Option, and Restricted Stock plans.

The following table provides information about purchases by the Company during the quarter and year ended December 31, 2005, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act.

ISSUER PURCHASES OF EQUITY SECURITIES

	Total Number of Shares Purchased in 2005		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program⁽¹⁾		Maximum Number of Shares that May Yet be Purchased Under the Program⁽¹⁾

January 1, 2005 - March 31, 2005		-	$	-		-		5,021,400

April 1, 2005 - June 30, 2005		1,157,810	$	24.48		1,157,810		3,863,590

July 1, 2005 - September 30, 2005		-	$	-		-		3,863,590

October 1, 2005 - October 31, 2005		17,472	$	31.72		17,472		3,846,118

November 1, 2005 - November 30, 2005		-	$	-		-		3,846,118

December 1, 2005 - December 31, 2005		-	$	-		-		3,846,118

Total October 1, 2005 - December 31, 2005		17,472	$	31.72		17,472		3,846,118

Total		1,175,282	$	24.51		1,175,282		3,846,118

⁽¹⁾

In August 2004 the Company announced that its Board of Directors authorized the re-initiation of the Company’s stock repurchase program and approved an increase in the number of shares that may be repurchased under the original authorization approved in August 1998 to 6,000,000 as of the effective date of the resolution and as adjusted for the March 2005 two-for-one stock split. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of St. Mary’s existing bank credit facility agreement and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow and borrowings under St. Mary’s bank credit facility. The stock repurchase program may be suspended or discontinued at any time.

The payment of dividends and repurchases of stock are subject to covenants in our bank credit facility, including the requirement that we maintain certain levels of stockholders’ equity and we limit our annual dividend rate to no more than $0.25 per share.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth supplemental selected financial and operating data for St. Mary as of the dates and for the periods indicated. The financial data for each of the five years presented were derived from the consolidated financial statements of St. Mary. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with St. Mary's consolidated financial statements included in this report.

		Years Ended December 31,
		2005		2004		2003		2002		2001
		(In thousands, except per share data)

Total operating revenues	$	739,590	$	433,099	$	393,708	$	196,305	$	207,469

Income before cumulative effect of change in accounting principle	$	151,936	$	92,479	$	90,140	$	27,560	$	40,459

Net income per share:
Basic	$	2.67	$	1.60	$	1.53	$	0.49	$	0.72
Diluted	$	2.33	$	1.44	$	1.40	$	0.49	$	0.71

Total Assets at year end	$	1,268,747	$	945,460	$	735,854	$	537,139	$	436,989

Long-term obligations:
Line of credit	$	-	$	37,000	$	11,000	$	14,000	$	64,000
Convertible Notes	$	99,885	$	99,791	$	99,696	$	99,601		-

Cash dividends declared and paid per common share	$	0.10	$	0.05	$	0.05	$	0.05	$	0.05

Supplemental Selected Financial and Operational Data:

	Years Ended December 31,
	2005			2004			2003			2002			2001
	(In thousands, except per volume data)
Balance Sheet Data:
Total working capital	$	4,937		$	12,035		$	3,101		$	2,050		$	34,000
Total stockholders’ equity	$	569,320		$	484,455		$	390,653		$	299,513		$	286,117

Weighted-average shares outstanding:
Basic		56,907			57,702			62,467			55,713			55,946
Diluted		66,894			66,894			71,069			56,782			57,110

Reserves:
Oil (Bbls)		62,903			56,574			47,787			36,119			23,669
Gas (Mcf)		417,075			319,196			307,024			274,172			241,231
MCFE		794,493			658,638			593,744			490,887			383,247

Production and Operational:
Oil and gas production revenues, including hedging	$	711,005		$	413,318		$	365,114		$	185,670		$	203,973
LOE and production taxes	$	142,873		$	95,518		$	88,509		$	50,839		$	55,000
DD&A	$	132,758		$	92,223		$	81,960		$	54,432		$	51,346
General and administrative	$	32,756		$	22,004		$	21,197		$	13,683		$	11,762

Production Volumes:
Oil (Bbls)		5,927			4,799			4,541			2,815			2,434
Gas (Mcf)		51,801			46,598			49,663			38,164			39,491
MCFE		87,363			75,393			76,909			55,055			54,093

Realized Price - pre hedging:
Per Bbl	$	53.18		$	39.77		$	29.40		$	24.67		$	24.08
Per Mcf	$	8.08		$	5.85		$	5.12		$	3.10		$	4.22

Realized Price - net of hedging:
Per Bbl	$	50.93		$	32.53		$	26.96		$	25.34		$	23.29
Per Mcf	$	7.90		$	5.52		$	4.89		$	3.00		$	3.73

Expense per MCFE:
LOE	$	0.99		$	0.81		$	0.77		$	0.66		$	0.75
Transportation	$	0.09		$	0.10		$	0.09		$	0.06		$	0.04
Production taxes	$	0.56		$	0.36		$	0.29		$	0.20		$	0.23
DD&A	$	1.52		$	1.22		$	1.07		$	0.99		$	0.95
General and administrative	$	0.37		$	0.29		$	0.28		$	0.25		$	0.22

Cash Flow:
From operations	$	409,379		$	237,162		$	204,319		$	141,709		$	127,492
For investing	$	(339,779	)	$	(247,006	)	$	(196,939	)	$	(180,931	)	$	(159,075	)
From (for) financing	$	(61,093	)	$	1,435		$	(3,707	)	$	46,260		$	29,080

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This discussion includes forward-looking statements. Please refer to “Cautionary Information about Forward-Looking Statements” in Part I, Item 1 of this Form 10-K for important information about these types of statements.

Overview of the Company

General Overview

We are an independent energy company focused on the exploration, exploitation, acquisition and production of natural gas and crude oil in the United States. We earn greater than 95 percent of our revenues and generate our cash flows from operations primarily from the sale of produced natural gas and crude oil. Our oil and gas reserves and operations are concentrated primarily in various Rocky Mountain Basins, including the Williston, Big Horn, Wind River, Powder River and Greater Green River Basins; the Mid-Continent Anadarko and Arkoma Basins; the Permian Basin, the tight sandstone reservoirs of East Texas and North Louisiana; and onshore Gulf Coast and offshore Gulf of Mexico. We have developed a balanced portfolio of proved reserves, development drilling opportunities and non-conventional gas prospects.

As of December 31, 2005, we had estimated proved reserves of 794.5 BCFE, with PV-10 value of $2.5 billion. An after income tax value of $1.7 billion is represented by the standardized measure calculation in Note 12 of Part IV, Item 15 of this report. Our reserves are 82 percent proved developed and 53 percent natural gas. The $2.5 billion PV-10 value for proved reserves is a 66 percent increase over the prior year. This amount reflects a 21 percent increase in proved reserves, a 41 percent increase in the adjusted oil reserve pricing to $61.04 per Bbl, and a 63 percent increase in the adjusted gas reserve pricing to $10.08 per Mcf as used in the calculation. Total production of oil and natural gas increased in 2005 by 16 percent to 87.4 BCFE. Approximately 59 percent of our total production volumes are derived from sales of natural gas.

Reserve Replacement and Growth

Like all oil and gas exploration and production companies, we face the challenge of natural production declines of oil and natural gas resources. An oil and gas exploration and production company depletes part of its asset base with each unit of oil and gas it produces. Historically, we have been able to grow our production despite this natural decline by adding more reserves through acquisitions and drilling than we produce. Future growth will depend on our ability to continue to add reserves in excess of production.

We believe growth in net asset value per share drives appreciation in our stock price. Our challenge is to grow net asset value per share. Our goal is to replace 200 percent of annual production with new reserves and grow production by ten to 15 percent per year. Please see the additional discussion of oil and gas reserve quantities in our critical accounting policies and estimates section. In 2005 we replaced 256 percent of our reserves at a finding cost of $1.88 per MCFE. Finding cost and reserve replacement percentage are defined in the glossary at the end of Part I, Item 1 of this report. We believe annual reserve replacement and finding cost amounts are important analytical measures that are widely used by investors and industry peers in evaluating the performance of oil and gas companies. While single year measurements have some meaning in terms of a trend, we believe that evaluating these items over an extended period of time is a better indication of performance. You should note that aberrations, causing both relatively good and bad results, will occur over short intervals of time. Our three-year reserve replacement percentage, excluding sales, is 247 percent and our three-year average finding cost is $1.64 per MCFE. Our average finding cost was lower in 2005 than in 2004 despite an overall increase in the cost associated with drilling and an overall increase in the price of acquiring developed reserves. The relative finding cost decrease in 2005 as compared to 2004 was the result of a shift in activity in the Mid-Continent region from exploratory activities in the deeper Morrow and Springer formations of the Northeast Mayfield area to development of the shallower, lower-cost, Atoka and Granite Wash formations. Also, our finding cost per MCFE decreased because we recorded a relative increase in proved undeveloped reserves. Our overall percentage of PUD reserves increased from 15 percent at the end of 2004 to 18 percent at the end of 2005. Of the 47.2 BCFE increase in the PUD reserves, 37.8 BCFE came from the ArkLaTex region. We also saw an increase in PUD reserves of 21.1 BCFE in the Mid-Continent region related to the activity at Northeast Mayfield. PUD reserves decreased as a result of being converted to proved developed reserves or decreased because remaining PUD reserves were not supported by newly proven developed reserves. PUD reserves decreased 10.8 BCFE in the Permian region because of these factors. We expect future finding costs per MCFE to increase as the overall cost of drilling a well in our core areas has approximately doubled in the last three years. Finding costs are comparison measures used to evaluate the effectiveness of an oil and gas company’s reserve replacement program and a snapshot in time of its expected future profitability.

Sustainability in our business is dependent on the ability to create new ideas and new value year after year. The challenges we face are becoming increasingly difficult as North American oil and gas production continues to decline and other exploration and production companies compete for available reserves. We believe we have a formula for meeting these challenges. We have placed talented geoscientists, engineers and landmen in each of our regional offices where their experience and knowledge of the local areas can be fully utilized. They are supported by a strong balance sheet and fiscal and operating discipline. Even so, we are subject to similar constraints as other companies in the exploration and production industry. Limitations to future growth will be based on overall availability of additional qualified personnel and the availability of drilling rigs to grow our drilling programs. We believe that we have sufficient staff levels and capital resources and that we will have appropriate access to drilling rigs to execute our $500 million drilling budget for 2006.

Stock Split

In March 2005 the Board of Directors approved a two-for-one stock split in the form of a stock dividend whereby one additional common share of stock was distributed for each common share outstanding. The stock dividend was distributed on March 31, 2005, to shareholders of record as of the close of business on March 21, 2005. All share and per share amounts for all prior periods presented within this report have been restated to reflect this stock split.

Effects of Hurricanes Katrina and Rita

Certain properties in our Gulf Coast region were affected by Hurricanes Katrina and Rita. These two events did not have a material adverse effect on our financial position or results of operations. We did not sustain any direct damage from Hurricane Katrina, but we did sustain damage from Hurricane Rita. Approximately 1 BCFE of production was shut in during 2005 and our operated production platform at Vermilion Block 273 was sheared off its base. We believe our insurance coverage for property damage resulting from Hurricane Rita is sufficient to cover the property damage losses we incurred. Our 2005 results of operations include the cost of applicable insurance deductibles related to our insurance coverage. Approximately 41 MCFED of production remained shut in as of February 15, 2006. Restoration of the remaining shut-in production is largely dependent on repairs to transportation and processing facilities which are owned and operated by other operators and facility owners.

Potential revenue impacts caused by shut-in production from the hurricanes were offset by a sudden and significant increase in oil and gas prices caused by hurricane-related supply disruptions for both crude oil and natural gas. We benefited from higher commodity prices in all of our production areas during the month of September and October. The operations analysis later in this discussion reflects the result of higher prices for the year ended December 31, 2005.

Oil and Gas Prices

Results of our operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. In 2005, oil and gas producers benefited from high oil and gas commodity prices. Increased prices of natural gas were caused by numerous conditions. Finite storage capacity in North America, a limited import market and fluctuations in domestic demand created by weather have a significant effect on natural gas prices. Oil price fluctuations are more closely related to global events as opposed to domestic events, although the inability to increase supply domestically continues to be a factor. The global conditions that affect the price of oil include a continuing increase in demand from the global economy, political instability in the Middle East, and a decrease in excess worldwide production capacity. News sources reported that the second and third largest producing fields in the world went on decline in 2005.

Hedging Activities

We have an active hedging program in which we hedge the first two to three years of an acquisition’s equivalent production as well as a portion of our existing forecasted production on a discretionary basis. Beginning in October 2005, we hedged a significant portion of anticipated future production from our currently producing properties using zero-cost collars. These contracts supplement our previous swap and collar contracts. We also hedged a portion of specific forecasted natural gas production for 2006 and 2007 using swap contracts. Taking into account all oil and gas production hedge contracts in place through February 15, 2006, we have hedged approximately 13.0 million Bbls and 73.7 million MMBTU of our anticipated production through the year 2011. We believe we have established an economic base for our future operations, and the spread between the price floor and ceiling on our collars allows us to continue to participate in a higher oil and gas price environment. Please see Note 10 of Part IV, Item 15 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section.

Net Profits Plan

Increases in oil and gas prices in the second half of 2005 resulted in a significant increase in the estimated future liability associated with our Net Profits Plan. The expense associated with the change in this estimated liability increased substantially in 2005. We recorded expense of $106.3 million for 2005 compared to $24.4 million for 2004 and $5.3 million for 2003. The expense associated with the change in the liability correlates closely with oil and gas prices and how quickly we recover our costs before we begin making payments, as required by the Net Profits Plan. Based on our valuation calculations as described in our accounting policies footnote, we believe the expense for this liability will be significantly less in 2006 as compared to 2005.

The calculation of this liability requires management to prepare its best estimate of future amounts payable from the Net Profits Plan. On a monthly basis, we calculate estimates of the payments to be made for each individual pool under the plan. The underlying basis for our calculations are forecasted oil and gas production from the properties that comprise each individual pool, price assumptions and discount rate. In most cases, the cash flow streams used in these calculations will span more than 20 years. We generally use a 15 percent discount rate to calculate the present value of these future payments, and the resulting amount is recorded as a liability. Commodity prices impact the calculated cash flows during periods after payout and can dramatically affect the timing of the estimated date of payout of the individual pools. Our commodity price assumptions are currently determined from a rolling average of actual prices received for the preceding 24 months combined with adjusted NYMEX strip prices for the next 12 months. This average is supplemented by including the effect of hedge prices for the percentage of forecasted production hedged in the relevant period. The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions. For example, if we changed the prices in our calculation by ten percent, the liability recorded at December 31, 2005, would differ by approximately $26 million, and a one percent change in the discount rate would result in a change of approximately $5 million. We frequently evaluate the assumptions used in our calculations to evaluate the possible impacts stemming from the current market environment. This review considers current oil and gas prices, discount rates and overall market conditions. The calculation of this liability will not correlate precisely to the standardized measure of discounted future net cash flows presented in Note 12 of Part IV, Item 15 of this report due to different pricing and discount assumptions.

As a result of higher prices over the last 12 months and the rate at which we have recovered costs associated with the designated properties in each pool, actual cash payments for amounts earned under the Net Profits Plan for 2005 were $20.8 million. Because of the life cycles of these pools and the existing commodity prices, we have budgeted approximately $40 million for cash payments in 2006. The actual cash payments to be made in future periods are dependent on actual production, realized prices and operating and capital costs associated with the individual pools. Actual cash payments will be inherently different from the estimated liability amount. Additional discussion is included in the analysis in the Comparison of Financial Results and Trends sections below.

2005 Highlights

In 2005 we experienced record production and earnings. Record production is the culmination of investment decisions made in prior years and in the current period. Significant increases in commodity prices for oil and natural gas and increased production resulted in the highest net revenues in our history. In 2006, we anticipate production to be greater than in 2005. If oil and gas prices remain high, it is reasonable to assume that revenue growth will continue. Our margins remained very strong in 2005 as a result of price increases in spite of the upward pressure from rig and service companies. In 2005, lease operating and transportation expense on a per MCFE basis increased from $0.91 per MCFE to $1.08 per MCFE. This was partially a result of a greater percentage of our production coming from oil properties which generally have higher operating costs. Other drivers for this increase include upward pressure on service costs, chemicals and labor and an increase in workover expense from $6.9 million in 2004 to $12.0 million in 2005. Increased workover costs will continue to impact us as nearly 40 percent of our production is from oil properties that require a higher amount of maintenance than required by flowing gas wells.

Highlights for 2005 also include the repurchase of 1,175,282 shares of our common stock under our stock repurchase program at an average price of $24.51 per share. We also closed on $87.8 million of oil and gas property acquisitions for a total of $73.9 million in cash. Our cash outflows were funded entirely by existing cash, operating cash inflows and short-term investments on hand. We repaid the $37.0 million of outstanding borrowings under this credit facility as of December 31, 2004, and we have no borrowings currently outstanding under our credit facility.

In 2005 oil prices rose to record levels as excess OPEC capacity shrank to its lowest level in recent time. Demand for oil was impacted by the growing economies of China and India as well as from a recovering U.S. economy. Spot market prices reflected worldwide concerns about producer ability to ensure sufficient supply to meet increasing demand amid a host of uncertainties caused by weather-related destruction, political instability, a weaker US dollar, foreign oil rig worker strikes and crude oil refining constraints. Average natural gas prices for the year were at an all-time high due to supply and transportation constraints, weather-related lost production, and continuing strong demand for natural gas in domestic markets resulting from an improving economy and the effect high oil prices have on natural gas demand. NYMEX prices for the year averaged $8.55 per MMBtu and $56.56 per Bbl, translating into a 49 percent increase to our per MCFE realized price over 2004. At December 31, 2005, the 12-month NYMEX strip was $63.18 per Bbl for oil and $10.78 per MMBtu for gas. As of February 15, 2006, pricing for the same period, including settled prices, was $60.46 per Bbl for oil and $8.36 per MMBtu for gas. As a result, the overall draws from gas storage have been lower than both the prior year and the prior five-year av