Edgar Filing: ST MARY LAND & EXPLORATION CO

form10k_123107.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

o 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

(State or other jurisdiction

of incorporation or organization)

41-0518430

(I.R.S. Employer Identification No.)

1776 Lincoln Street, Suite 700, Denver, Colorado

(Address of principal executive offices)

80203

(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 þ No o

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

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

Indicate by check mark 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company 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 þ

The aggregate market value of 62,317,450 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, of $36.62 per share as reported on the New York Stock Exchange was $2,282,065,019. 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, 2008, the registrant had 63,020,524 shares of common stock outstanding, which is net of 1,009,712 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 2008 annual meeting of stockholders to be filed within 120 days after December 31, 2007.

TABLE OF CONTENTS

ITEM		PAGE
PART I

ITEMS 1 and 2.	BUSINESS and PROPERTIES		1
	General		1
	Strategy		1
	Significant Developments in 2007		2
	Assets		4
	Reserves		9
	Production		10
	Productive Wells		11
	Drilling Activity		11
	Acreage		12
	Major Customers		12
	Employees and Office Space		12
	Title to Properties		13
	Seasonality		13
	Competition		13
	Government Regulations		13
	Cautionary Information about Forward-Looking Statements		15
	Available Information		17
	Glossary of Oil and Natural Gas Terms		17

ITEM 1A.	RISK FACTORS		20

ITEM 1B.	UNRESOLVED STAFF COMMENTS		29

ITEM 3.	LEGAL PROCEEDINGS		29

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		29

ITEM 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT		30

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.		32

ITEM 6.	SELECTED FINANCIAL DATA		36

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		38
	Overview of the Company		38
	Overview of Liquidity and Capital Resources		48
	Critical Accounting Policies and Estimates		59
	Additional Comparative Data in Tabular Format		62
	Comparison of Financial Results and Trends between 2007 and 2006		64
	Comparison of Financial Results and Trends between 2006 and 2005		66
	Other Liquidity and Capital Resource Information		68
	Accounting Matters		69
	Environmental		70

TABLE OF CONTENTS
(Continued)

ITEM		PAGE

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included with the content of ITEM 7)		70

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		70

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		70

ITEM 9A.	CONTROLS AND PROCEDURES		70

ITEM 9B.	OTHER INFORMATION		73

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		73

ITEM 11.	EXECUTIVE COMPENSATION		73

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		73

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		73

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		74

PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		74

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 of Oil and Natural Gas Terms”. 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.

ITEMS 1 and 2. BUSINESS and PROPERTIES

General

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 initial public offering of common stock took place in December of 1992. The common stock of the Company trades on the New York Stock Exchange under the ticker “SM”.

Our principal offices are located at 1776 Lincoln Street, Suite 700, Denver, Colorado 80203, and our telephone number is (303) 861-8140.

Strategy

Our objective is to build stockholder value through consistent economic growth in reserves and production that increases net asset value 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.

The majority of our current senior technical managers in each region possess between 20 and 30 years of industry experience and lead fully-staffed regional technical offices that are supported by centralized administration from our corporate office in Denver. We use our comprehensive base of geological, geophysical, land, 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 other reservoir stimulation techniques, horizontal drilling, secondary recovery, and specialized logging tools to enhance the potential of our existing properties. We believe that having fully-staffed technical teams based in each of our operating regions is an advantage in that our regional offices are staffed with personnel that have a deep knowledge of the basins in which they work, participate in the regional deal flow and prefer to live in regional areas, which minimizes personnel attrition.

Acquisitions have been a key element of our business strategy. Historically, we have been most successful in acquiring properties on a negotiated basis, as opposed to participating in widely marketed auctions for properties. In the last two years we have made several large acquisitions. In 2007, we paid $178.9 million for two acquisitions in South Texas for properties targeting the Olmos shallow gas formation. In 2006, we paid $243.1 million to acquire assets that target the Wolfberry section in the Permian Basin.

We divest selected non-core assets when market conditions and prices are attractive. We will continue to evaluate such opportunities in the future when we believe it to be appropriate. During 2007, we sold properties with estimated proved reserves of 1.4 BCFE. We actively marketed and contracted to sell a package of non-core assets in 2007. This sale closed on January 31, 2008, for a total adjusted sales price of $131.1 million before commissions; this sale represented 40.4 BCFE of our year-end 2007 proved reserves. We utilized a 1031 reverse exchange structure to defer the recognition of income tax on the gain from this sale.

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 acquisitions and

other opportunities, particularly 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 40 percent at the end of December 2007. The proceeds from the aforementioned property sale in January 2008 were applied to reducing bank borrowings.

In summary, we believe that our dedication to making investment decisions based on net asset value per share, our long-standing geologic and engineering experience in the regions in which we operate, our appropriate application of technology, our established networks of local industry relationships, and our measured approach to acquisitions and divestitures all provide us with competitive advantages that we can use to continue growing the Company.

Significant Developments in 2007

Increase in 2007 Year-End Reserves. Proved reserves increased 17 percent to 1,086.5 BCFE at December 31, 2007, from 927.6 BCFE at December 31, 2006. We added 132.1 BCFE from our drilling program and 94.8 BCFE from acquisitions. We had a positive revision of 40.9 BCFE which consisted of a 6.4 BCFE upward performance revision and an upward revision of 34.5 BCFE due primarily to increased oil prices at the end of 2007. The 2007 acquisition volumes are lower than the initial estimates previously disclosed as a result of the final year-end reservoir engineering estimation. We sold properties with reserves of 1.4 BCFE in 2007.

Drilling Results. Reserve additions from drilling activities of 132.1 BCFE were driven by results in the Mid-Continent, Rocky Mountain, ArkLaTex, and Permian regions, with those regions contributing 37 percent, 21 percent, 20 percent, and 18 percent, respectively. Additions in the Mid-Continent were driven principally by successful drilling by us and others in the horizontal Woodford shale formation in the Arkoma Basin, as well as positive results in two programs in the Anadarko Basin. In the Rocky Mountain region, the largest contribution came from the Hanging Woman Basin where we added 9.9 BCFE of proved reserves. The ArkLaTex region added 26.2 BCFE from successful drilling operations in the James Lime carbonate program and Elm Grove Field. Successful results in the Wolfberry program in 2007 were the principal driver of drilling additions in the Permian Basin.

New Basin Entry in 2007. In 2007 we spent $182.9 million for acquisitions of proved and unproved oil and gas properties. We entered the greater Maverick Basin with two acquisitions in South Texas totaling $178.9 million that target the Olmos shallow gas formation. The first was the $30.0 million Catarina acquisition that closed in June 2007. The more significant transaction was the $148.9 million Rockford acquisition that closed in October 2007. These properties added a sizeable inventory of lower risk drilling locations to our portfolio. Consistent with prior acquisitions, we hedged several years of the risked production related to these acquisitions at the time of acquisition. The remaining acquisitions in 2007 were small niche transactions throughout the year in the Mid-Continent, ArkLaTex, and Rocky Mountain regions.

Senior and Regional Management Changes. During 2007, the Company underwent or announced personnel changes in the chief executive position and in several regional manager positions. On February 23, 2007, Mark Hellerstein retired as Chief Executive Officer after serving in that role since 1995. Tony Best, President of the Company, was appointed as Chief Executive Officer on that date. Mr. Hellerstein continues to serve as the Chairman of the Board. In June of 2007, Jerry Schuyler, the Senior Vice President responsible for the Gulf Coast and Permian regions, left St. Mary to pursue another professional opportunity. Greg Leyendecker, then Operations Manager for the Gulf Coast region, assumed responsibility for the Gulf Coast and is now Vice President - Regional Manager of the Gulf Coast region. We also made the Midland office a stand-alone regional office headed by Lehman Newton III, Vice President - Regional Manager of our Permian region. Mr. Leyendecker and Mr. Newton joined St. Mary in 2006 and each have over 25 years of management and operational experience in the oil and gas industry. In July 2007, Stephen Pugh joined the Company as Senior Vice President and Regional Manager of the ArkLaTex region. Mr. Pugh succeeded David Hart, who retired from St. Mary after 15 years in various roles at the Company. Mr. Pugh came to St. Mary with over 25

years of engineering, operations, and business development experience in the oil and gas industry. In August of this year, Robert Nance, Senior Vice President - Regional Manager of the Rocky Mountain region, announced his decision to retire in the first quarter of 2008 after more than 40 years in the oil and gas industry. Mark Mueller joined us as Senior Vice President in August and now leads our Rocky Mountain region. Mr. Mueller has over 20 years of management and technical experience in the oil and gas industry. Effective January 1, 2008 Mark Mueller was appointed Senior Vice President - Regional Manager. Subsequent to year end, David Honeyfield, Senior Vice President - Chief Financial Officer, announced that he will resign as an officer of St. Mary on March 21, 2008, in order to pursue an opportunity in an unrelated industry. An external search for his successor is underway at the time of this filing.

2007 Capital Markets Activity. In March of 2007 we called for redemption of the then outstanding $100.0 million 5.75% Senior Convertible Notes. The notes had a conversion price of $13.00 per share. One hundred percent of the holders of the notes elected to convert their notes into shares of common stock. As a result of the conversion, 7.7 million shares of stock were issued to the note holders. This resulted in a decrease to long-term debt of $100.0 million, and an increase to common stock associated with the conversion together with the recognition of the excess tax benefit associated with the contingent interest feature associated with the notes.

In April of 2007, we completed the sale of $287.5 million of 3.50% Senior Convertible Notes. The net proceeds from the 3.50% Senior Convertible Notes were used to repay outstanding borrowings under our revolving credit facility.

Significant Volatility in Commodity Prices. During 2007, the exploration and production sector was impacted by volatility in the prices for crude oil and natural gas. Our operations and financial conditions were significantly impacted by these prices. Our crude oil is sold on contracts that pay us the average of posted prices for the period in which the crude oil is sold. NYMEX crude oil began 2007 with an average January price of $54.67 per barrel and increased steadily throughout the year, reaching an average monthly high for the year of $94.63 per barrel in November. The average NYMEX price for the year was $72.34 per barrel. Geopolitical unrest in various producing regions overseas and concerns domestically related to refinery utilization and petroleum product inventories were the principal drivers of the increase in oil prices in 2007.

We sell the majority of our natural gas on contracts which are based on first of the month (also frequently referred to as bid week) index pricing. The Inside FERC bid week price for Henry Hub, a widely used industry measuring point, averaged $6.86 per MMBtu in 2007, which was five percent lower than the average for 2006. High levels of natural gas in storage had an impact on pricing during 2007 as inventory levels exceeded the five year average for all of 2007. Concerns about supply overhang peaked for the year around September of 2007, leading to the lowest Henry Hub price for the year of $5.43 per MMBtu. The impact was more acute in the Rocky Mountain region where bid week prices were driven down to $2.13 per MMBtu and $1.11 per MMBtu for September and October, respectively, on the Colorado Interstate Gas (CIG) index. A significant portion of our production in the Rockies is oil and we had limited exposure to the CIG hub. Additionally, recent acquisitions have added a richer gas stream to our overall production mix. The value received associated with natural gas liquids (NGLs) from this rich gas stream align more closely with crude oil prices. The increase in crude prices has had a similar impact on prices for NGLs, and as a result we have enjoyed higher realized natural gas prices. We hedge a portion of our oil and gas production using swaps and collars. A gain of $58.7 million was realized on our natural gas hedges for the year and a loss of $34.3 million was realized on our oil hedges for the year.

Repurchase of Common Stock. In 2007, we repurchased a total of 792,216 shares of our common stock in the open market for a weighted-average price of $32.76 per share, including commissions, under this program. At the time we repurchased our shares, we entered into hedges for a commensurate amount of our production that was represented by the share repurchase in order to lock in the discounted price at which our shares were trading. As of the date of this filing, we are

authorized by the Board to repurchase 5,207,784 additional shares under this program. The shares may be repurchased from time to time in open market transactions or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our existing credit facility agreement and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, and borrowings under the credit facility.

Assets

As of December 31, 2007, we had estimated proved reserves of 78.8 MMBbl of oil and 613.5 Bcf of natural gas. Prices in effect on December 31, 2007, used to estimate proved reserves were $6.80 per MMBtu of gas and $95.98 per barrel of oil. On an equivalent basis, our proved reserves were 1,086.5 BCFE as of December 31, 2007, an increase of 17 percent from 927.6 BCFE at the end of the prior year. The increase in proved reserves in 2007 was the result of development activities and acquisitions. On an equivalent basis, 77 percent of our proved reserves are classified as proved developed as of year-end. Total proved oil and gas reserves have a before income tax PV-10 value of $3.9 billion and a standardized measure value, which includes the effect of income taxes, of $2.7 billion (a reconciliation between these two amounts is shown under Reserves in Part I, Items 1 and 2). During 2007, our average daily production was 181.0 MMcf of gas and 18.9 MBbl of oil, for an average equivalent production rate of 294.5 MMCFE per day, which is a new annual record for us. We sold certain non-core oil and gas properties subsequent to year end; all production and reserve information presented is before the impact of this sale unless otherwise noted.

Our reserve replacement percentage – including sales for 2007 was 248 percent, which includes 1.4 BCFE of asset sales that occurred during the year. Our reserve replacement percentage – excluding sales was 249 percent. We acquired 94.8 BCFE of proved reserves through acquisitions in 2007, the majority of which relate to the two Olmos shallow gas acquisitions in South Texas. We believe the use of the phrase “reserve replacement percentage” is widely understood by those who make investment decisions related to the oil and gas exploration business. We believe that this measure is useful in evaluating and comparing exploration and production companies and provides a measure of the growth of a company. The Glossary includes a definition of “reserve replacement percentage” and description of how it is calculated.

In 2007, we invested a total of $926.1 million on drilling activities and acquisitions. This was 15 percent higher than the $805.5 million invested in 2006. Drilling investments, including leasing activity, in 2007 of $740.9 million comprised 80 percent of our total capital investment budget for the year and compares to $522.6 million in 2006. The increase in drilling activity was driven primarily by development of the Sweetie Peck asset in the Permian Basin that was acquired in late 2006 as well as increases in activity in our ArkLaTex region. We invested $185.2 million on acquisitions in 2007, the majority of which related to the two acquisitions in South Texas targeting the Olmos shallow gas play.

We have $626 million budgeted for development and exploration investments in 2008, which is a decrease of 16 percent from the $740.9 million invested in drilling activities in 2007. The decrease in investment year over year is a reflection of our goal to improve our capital efficiency and to invest within our cash flow from operations in order to maintain financial flexibility so that we can deploy additional capital where warranted in order to make accretive acquisitions, repurchase stock, or repay debt.

Our operations are currently concentrated in five core operating areas in the United States. The following table summarizes the production and proved reserves and PV-10 value of our core operating areas as of December 31, 2007.

	ArkLaTex		Mid- Continent		Gulf Coast		Permian		Rocky Mountain		Total
2007 Proved Reserves:
Oil (MMBbl)		1.0		1.5		0.9		20.0		55.4		78.8
Gas (Bcf)		163.9		192.4		111.3		34.7		111.2		613.5
Equivalents (BCFE)		170.1		201.3		116.8		154.7		443.6		1,086.5
Relative percentage		15%		19%		11%		14%		41%		100%
Proved Developed %		52%		88%		48%		69%		92%		77%

PV-10 Value (in millions)	$	380.3	$	585.5	$	361.6	$	824.2	$	1,709.6	$	3,861.2
Relative percentage		10%		15%		9%		21%		45%		100%

2007 Production:
Oil (MMBbl)		0.1		0.5		0.2		1.4		4.7		6.9
Gas (Bcf)		13.0		30.9		9.0		2.4		10.8		66.1
Equivalent (BCFE)		13.8		34.0		10.3		10.7		38.7		107.5
Avg. Daily Equivalents (MMCFE/d)		37.8		93.2		28.2		29.3		106.0		294.5
Relative percentage		13%		31%		10%		10%		36%		100%

Note: The table above includes production and proved reserves related to non-core assets that were divested on January 31, 2008. The properties divested were primarily in the Mid-Continent and Rocky Mountain regions. These non-core properties contributed 5.0 BCFE of production during 2007 and represented 40.4 BCFE of proved reserves at December 31, 2007.

ArkLaTex Region. St. Mary’s operations in the ArkLaTex region are managed from our office in Shreveport, Louisiana. The ArkLaTex region was the first operating office for the Company, originating from an acquisition in 1992. For years the activities of this region focused on the tight sandstone Cotton Valley and Travis Peak formations in the region. In recent years, we have utilized horizontal wells in the development of limestone carbonates found in the region, particularly the James Lime formation.

The ArkLaTex region invested $149.8 million in 2007 on exploration, development, and acquisition activities, which is 70 percent higher than the $88.0 million spent in 2006. The primary drivers of this increase in capital were increased activity levels in our James Lime and Cotton Valley programs during the year. In the St. Mary operated horizontal James Lime program, we operated one rig continuously throughout 2007. We continued to see solid results in proven development areas and had two successful wells that extended the play westward by approximately 75 miles. The Cotton Valley programs at Elm Grove and Terryville fields were areas of significant investment in 2007, although these are operated by other companies. At Elm Grove Field, advancements such as 20-acre increased density drilling, commingling of production of the Cotton Valley and Hosston formations, and horizontal drilling have benefited us, particularly as development has moved into areas where we have larger working interests. Even though operations at Terryville Field are more difficult due to the formation being deeper and more highly pressured than the Cotton Valley formation at Elm Grove Field, operations in the field were highly successful in 2007 and allowed for sustained activity during the year. The region’s 2007 production increased 31 percent to 13.8 BCFE. Our proved reserves at year-end 2007 were 170.1 BCFE, a seven percent increase over 2006 year-end proved reserves of 159.5 BCFE. On a forward looking basis, we expect that proved reserves in this area will be booked on 20 acre spacing as the in-fill program at Elm Grove Field continues and additional locations become permitted. We have not however booked these locations as proved reserves at year end due to the Securities and Exchange Commission technical requirement of needing to have an “alternate unit” permitting process completed prior to booking such items as proved reserves.

The Elm Grove Field is the highest value field in the ArkLaTex region at year-end 2007, with proved reserves of 85.3 BCFE and a PV-10 value of $161.3 million. Elm Grove comprises roughly 42 percent of the region’s PV-10 value and approximately four percent of our entire PV-10 value. We own interests in 382 producing wells in the field with many of those wells having uphole recompletion potential in the future. Our working interest in the field is as high as 37 percent; higher working interests are located in the southern portion of the acreage where recent activity has been occurring. Reserves in this field are primarily natural gas.

Our capital budget for the ArkLaTex region in 2008 is $161 million, 51 percent of which will be operated by us. The largest portion of this year’s budget relates to Cotton Valley programs, where 50 percent of the region’s capital will be deployed. Of the capital allocated for Cotton Valley programs, 60 percent will be invested at Elm Grove Field where development continues to be highly successful. Development of the field on 20-acre spacing continues to drive activity levels, and a successful horizontal well completed at the end of 2007 could set the stage for horizontal development at Elm Grove Field. The remaining Cotton Valley allocation for 2008 will be split roughly evenly between the program at Terryville Field and the St. Mary operated program at Carthage. Our operated horizontal James Lime program will represent 34 percent of the region’s 2008 budget. We plan to operate two drilling rigs throughout the year, with plans to drill more than 20 horizontal James Lime wells in 2008.

Mid-Continent Region. St. Mary has been active in the Mid-Continent region since 1973. Operations for the region are managed by our office in Tulsa, Oklahoma. We have been active in the Anadarko Basin of western Oklahoma since our entry into the region and our primary focus in the region is currently on the Atoka and Granite Wash formations. In recent years we have begun operating in the Arkoma Basin in eastern Oklahoma where the current focus is on horizontal development of the Woodford shale, although the Wapanucka limestone and Cromwell sandstone also appear to have commercial potential. The Mid-Continent region oversees our assets in Constitution South Field in Jefferson County, Texas. Our long history of operations and proprietary geologic knowledge in the region enables us to sustain economic development and exploration programs despite periods of adverse industry conditions. We apply current technology through the use of hydraulic fracturing, innovative well completion techniques, and horizontal drilling to accelerate production and associated cash flow from the region’s tight gas reservoirs and developing plays.

In 2007, we invested $185.7 million in the Mid-Continent region on exploration, development, and acquisition activity, which is 13 percent less than the $214.3 million deployed in 2006. Throughout 2007, we maintained a consistent level of activity in the Arkoma Basin working on the Woodford shale program as we continued to refine our understanding of the play. We decreased our activity in the Atoka/Granite Wash development program as we developed more cost efficient completion designs for these wells. Mid-Continent production in 2007 was 34.0 BCFE, an increase of 14 percent from the 29.8 BCFE produced in 2006. Proved reserves at the end of 2007 were 201.3 BCFE, an increase of 18 percent from the 170.7 BCFE report for the prior year.

The Constitution South Field is the highest value field in the Mid-Continent region with reserves of 15.2 BCFE and a PV-10 value of $115.1 million. This field also contributed 8.6 BCFE of production in 2007, which represents approximately eight percent of our total production. Three wells, the Paggi Broussard #1, the Paggi Broussard # 2, and the Loretta B. Casey #1, comprise the majority of reserves, PV-10 value, and production in the Constitution South Field. These wells historically have performed better than anticipated and we have a history, including at year-end 2007, of recognizing upward performance revisions in our proved reserves at this field.

The 2008 capital expenditure budget for the Mid-Continent region is $135.0 million, 69 percent of which we will operate. The largest component of the budget is our program targeting the Woodford shale using horizontal wells in the Arkoma basin, where roughly 30 percent of the region’s budget will be invested. After mixed results in the horizontal Woodford shale program in the first half of 2007, we had a series of successful wells in the latter part of the year which we believe validates our understanding of the well and completion design being used currently in this program. Our budget anticipates that we will drill ten horizontal Woodford wells with two operated rigs in the first half of 2008, and continue to participate with our partners in outside operated wells. With continued success in the play, we have the ability to increase activity and our capital investment in the program in the latter part of 2008. In 2008, we plan to continue with an exploration program in the Anadarko

Basin that yielded encouraging results in 2007. This exploration program targets deeper formations of the basin. We also plan to deploy approximately 27 percent of the region’s 2008 capital budget to drill six exploratory test wells in this program. In the Western Oklahoma Washes program in the Anadarko Basin, which we have referred to previously as the Mayfield development area, we plan to invest roughly 17 percent of the year’s budget in this program that targets the Atoka and Granite Wash formations. The area is a known hydrocarbon province, and efforts in 2008 will be directed toward improving the geotechnical effort applied to the program and revising drilling and completion techniques.

Gulf Coast Region. St. Mary’s presence in south Louisiana dates to the early 1900s when our founders acquired our namesake property in St. Mary Parish, Louisiana abutting the Gulf of Mexico. These 24,914 acres of fee lands yielded $3.7 million of gross oil and gas royalty revenue in 2007. Our Gulf Coast regional presence expanded as a result of the acquisition of King Ranch Energy, Inc. in 1999. During 2007 we reached a significant inflection point in this region as it shifted from an office centered on geotechnically driven exploration to one focused on repeatable development and exploitation with our acquisition of two Olmos shallow gas assets in South Texas. The Gulf Coast region is run from our office in Houston, Texas.

Our capital expenditures for exploration, development, and acquisition activity in the Gulf Coast region grew significantly from $65.5 million in 2006 to $278.5 million in 2007, primarily driven by two significant acquisitions.

The majority of our 94.8 BCFE of acquisitions, classified as purchases of minerals in place, were in the Gulf Coast region. These were the $150.3 million Rockford acquisition that closed in October 2007 and the $30.4 million Catarina acquisition which closed in April 2007, both of which target the Olmos shallow gas formation and are located in the greater Maverick Basin in Southwestern Texas. Final year-end reserve estimates related to these acquisitions are lower than the initial estimates we previously disclosed, partly due to the fact that our presentation of reserves at the time of the acquisition was on a dry gas basis whereas our annual report on Form 10-K disclosures utilize a wet gas presentation. This accounted for approximately ten BCFE of the difference in volumes, without any impact to value. The remaining difference was based on our final year-end assessment of proved non-producing reserves and our proved undeveloped reserves, which were each lower than the amounts estimated at the time of acquisition. Our emphasis in 2007 was on the successful integration of our newly acquired properties. While the core focus of the region shifted toward onshore projects, we continued to be active offshore in 2007. A previously discovered intermediate deepwater project, Zloty, began production late in 2007 and we continue to work to advance other intermediate deepwater projects in which we are a partner. We were also active closer to shore with a mixed program that included the successful Reno, Clement, and Amber Jack wells. Gulf Coast production in 2007 was 10.3 BCFE, an increase of six percent from the 9.7 BCFE produced in 2006. Proved reserves at the end of 2007 were 116.8 BCFE, an increase of 263 percent from the 32.2 BCFE reported for the prior year. The disparity between the production growth and reserve growth for the Gulf Coast region in 2007 is attributable to the acquisitions previously discussed.

The most significant asset in the Gulf Coast region is the Gold River project area that was acquired in October of 2007 as part of the Rockford acquisition. The Gold River project area has 104 producing wells as of year end. At December 31, 2007, this project area had a PV-10 value of $136.9 million with 53.6 BCFE of proved reserves and accounts for approximately four percent of our entire PV-10 value. The acquisition of these assets, together with the Catarina assets, represents the most recent resource play entry for the Company.

Our development and exploration budget in the Gulf Coast region for 2008 is $80 million and is focused primarily on the development of the Olmos assets acquired in 2007. St. Mary will operate 75 percent of the planned capital investment next year. Roughly $38 million, or 47 percent, of the budget will be dedicated to grass roots Olmos wells and approximately $10 million, or 12 percent, of the budget will be spent on Olmos recompletions.

Permian Basin Region. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is one of the major producing basins in the United States. Our holdings in the Permian Basin began with a series of property acquisitions in 1996. In December 2006, we made a $240.6 million acquisition of predominately oil properties in the Sweetie Peck project area. To manage the significant increase in operated properties associated with the Sweetie Peck acquisition, we opened a regional office in Midland, Texas in early February 2007.

In 2007, we spent $135.1 million in the region. The majority of this capital was deployed to develop projects that target the Wolfberry tight oil play, which targets the stacked carbonate Wolfcamp and Spraberry formations found in the basin. We participated in two substantial Wolfberry programs during 2007 – the operated Sweetie Peck program and the outside operated program at Halff East. We operated between two and five drilling rigs at Sweetie Peck throughout 2007. At Halff East, our operating partner had two drilling rigs running throughout the year. We also invested capital in the Parkway and East Shugart Delaware waterflood projects. Production in the region increased 234 percent over the prior year, from 3.2 BCFE in 2006 to 10.7 BCFE in 2007. Proved reserves as of the end of 2007 were 154.7 BCFE, which is an increase of nine percent from 2006 year-end reserves of 142.2 BCFE.

As of the end of December 2007, the Sweetie Peck assets in the Permian Basin represented a PV-10 value of $438.0 million with 77.7 BCFE of proved reserves. This accounts for approximately 11 percent of our entire PV-10 value. The Sweetie Peck assets had 106 producing wells and 47 proved undeveloped reserve locations as of the end of 2007.

The capital budget for 2008 in the region is $120 million, of which 74 percent will be operated by us. Of this amount, roughly $103 million, or 86 percent, will be invested in Wolfberry projects. At Sweetie Peck, we plan to spend approximately $77 million operating three drilling rigs continuously throughout the year. Included in this amount are investment dollars to test several 40-acre pilot areas, which if successful could add meaningful proved reserves. At Halff East, we will invest approximately $25 million with our operating partner. We will also invest a small amount of capital in several smaller programs, including our Delaware waterfloods.

Rocky Mountain Region. St. Mary has conducted operations in the Williston Basin in eastern Montana and western North Dakota since 1991. The region is managed by our office in Billings, Montana. In recent years, we have expanded our operations into the Greater Green River, Powder River, Big Horn, and Wind River basins of Wyoming through a series of acquisitions. The largest growth in the region came in late 2002 and early 2003 with significant property acquisitions from Choctaw, Burlington Resources, and Flying J. These transactions brought with them a tremendous acreage position that has precipitated additional growth in this region.

Including the Hanging Woman Basin coalbed methane project, we invested $178.3 million in 2007 on exploration, development, and acquisitions in the Rocky Mountain region, compared to $161.3 million in 2006. The 2007 program was focused on a horizontal development in the Mississippian formations of the Williston Basin, and the drilling of Bakken formation infill locations in Montana and Red River locations. Additionally, 2007 saw an acceleration of drilling at Hanging Woman Basin. Proved reserves for the Rocky Mountain region were 443.6 BCFE at year-end, up five percent from 422.9 BCFE as of year end 2006. Production in the Rocky Mountain region for 2007 was 38.7 BCFE. Total regional production was down two percent from 39.5 BCFE in 2006.

Included in the Rocky Mountain region is the coalbed methane project at Hanging Woman Basin. This program is of particular interest because of the large resource potential on our leasehold. In 2007, we invested $35.7 million at Hanging Woman Basin compared to $30.4 million in 2006. Proved reserves in this project grew 20 percent in 2007 to 40.2 BCFE, 75 percent of which were proved developed. Hanging Woman Basin had 33.4 BCFE in proved reserves at December 31, 2006, 91 percent of which were proved developed. Production was 3.0 BCFE for the year ended 2007, up 49 percent from production in 2006.

The Elm Coulee Field is the highest value field in the region at year-end 2007, with 92 producing wells and proved reserves of 42.4 BCFE and a PV-10 value of $236.5 million. The reserves in this field are predominately oil and the Bakken is the formation of primary interest. This field comprises approximately six percent of our entire PV-10 value.

Our capital budget for the Rocky Mountain region is $130 million for 2008, with roughly $24 million budgeted for activities for Hanging Woman Basin coalbed methane. We will operate roughly 65 percent of our planned regional investment in 2008. In the conventional Rockies program, several vertical wells and two recompletions in the Red River are planned for the year. We also plan to drill a small number of horizontal Bakken wells in and around our historic Bakken development areas in Montana. Workover and recompletion

operations are planned in our Wind River Basin and Big Horn Basin oil properties. At the outside operated Atlantic Rim coalbed methane play in the Green River Basin, we expect to see activity ramp up since regulatory and environmental delays appear to have been resolved. At Hanging Woman Basin, we plan to moderate our drilling activity in 2008 and monitor and evaluate the results of the shallow and intermediate pods and deep horizontal programs from previous year’s drilling efforts.

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, 2007. For all years presented Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the reserve information for the Company’s coalbed natural gas projects at Hanging Woman Basin in the northern Powder River Basin and St. Mary’s non-operated coalbed methane interest in the Green River Basin. We engaged Ryder Scott Company, L.P. to review internal engineering estimates for 80 percent of the PV-10 value of our proven conventional oil and gas reserves in 2007 and 2006. In 2005, Ryder Scott Company, L.P. prepared the reserve estimates for at least 80 percent of the PV-10 value of our conventional oil and gas assets. St. Mary personnel prepared the reserve estimates for the remainder of all properties. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. 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 – The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.” No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission, since the beginning of the last fiscal year.

	As of December 31,
Proved Reserves Data:	2007		2006		2005
Oil (MMBbl)		78.8		74.2		62.9
Gas (Bcf)		613.5		482.5		417.1
BCFE		1,086.5		927.6		794.5
Standardized measure of discounted future net cash flows (in thousands)	$	2,706,914	$	1,576,437	$	1,712,298
PV-10 value (in thousands)	$	3,861,187	$	2,157,449	$	2,494,169
Proved developed reserves		77%		78%		82%
Reserve replacement – including sales of reserves		248%		244%		256%
Reserve replacement – excluding sales of reserves		249%		247%		256%
Reserve life (years) (1)		10.1		10.0		9.1

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

The following table reconciles the standardized measure of discounted future net cash flows to the PV-10 value. The difference has to do with the PV-10 value measure excluding the impact of income taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary.

	As of December 31,
	2007			2006			2005
	(In thousands)
Standardized measure of discounted future net cash flows	$	2,706,914		$	1,576,437		$	1,712,298
Add: 10 percent annual discount, net of income taxes		2,321,983			1,238,308			1,286,568
Add: Future income taxes		2,316,637			1,125,955			1,448,444

Undiscounted future net cash flows	$	7,345,534		$	3,940,700		$	4,447,310
Less: 10 percent annual discount without tax effect		(3,484,347	)		(1,783,251	)		(1,953,141	)

PV-10 value	$	3,861,187		$	2,157,449		$	2,494,169

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,
	2007		2006		2005

Net production:
Oil (MMBbl)		6.9		6.1		5.9
Gas (Bcf)		66.1		56.4		51.8
BCFE		107.5		92.8		87.4
Average net daily production:
Oil (MBbl)		18.9		16.6		16.2
Gas (MMcf)		181.0		154.7		141.9
MMCFE		294.5		254.2		239.4
Average realized sales price, excluding the effects of hedging:
Oil (per Bbl)	$	67.56	$	59.33	$	53.18
Gas (per Mcf)	$	6.74	$	6.58	$	8.08
Per MCFE	$	8.48	$	7.88	$	8.40
Average realized sales price, including the effects of hedging:
Oil (per Bbl)	$	62.60	$	56.60	$	50.93
Gas (per Mcf)	$	7.63	$	7.37	$	7.90
Per MCFE	$	8.71	$	8.18	$	8.14
Production costs per MCFE:
Lease operating expense	$	1.31	$	1.25	$	0.99
Transportation expense	$	0.14	$	0.12	$	0.09
Production taxes	$	0.58	$	0.54	$	0.56

Productive Wells

As of December 31, 2007, St. Mary had working interests in 2,365 gross (1,125 net) productive oil wells and 4,199 gross (1,405 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,
	2007				2006				2005
	Gross		Net		Gross		Net		Gross		Net
Development:
Oil		164		77.91		81		35.32		83		38.09
Gas		518		204.62		446		178.97		379		152.69
Non-productive		30		13.18		31		10.65		29		9.12
		712		295.71		558		224.94		491		199.90
Exploratory:
Oil		3		1.92		10		5.53		8		1.91
Gas		9		4.01		15		3.68		5		0.86
Non-productive		5		2.58		8		1.81		5		2.32
		17		8.51		33		11.02		18		5.09

Farmout or non-consent		1		-		2		-		18		-
Total (1)		730		304.22		593		235.96		527		204.99

(1) Does not include three and nine gross wells completed on St. Mary's fee lands during 2006 and 2005, 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, 2007. 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		2,917		408		207		68		3,124		476
Colorado		3,098		2,496		20,269		12,530		23,367		15,026
Louisiana		136,606		45,913		52,349		15,081		188,955		60,994
Mississippi		6,646		727		59,907		21,435		66,553		22,162
Montana		70,462		45,523		426,161		286,841		496,623		332,364
New Mexico		5,440		2,608		1,480		1,187		6,920		3,795
North Dakota		150,968		97,691		198,104		110,786		349,072		208,477
Oklahoma		302,820		91,523		107,018		56,735		409,838		148,258
Texas		215,056		78,310		163,849		97,019		378,905		175,329
Utah (3)		480		115		3,574		831		4,054		946
Wyoming		152,209		97,129		395,083		226,410		547,292		323,539
Other (4)		2,201		873		3,836		1,090		6,037		1,963
		1,048,903		463,316		1,431,837		830,013		2,480,740		1,293,329

Louisiana Fee Properties		10,818		10,818		14,096		14,096		24,914		24,914
Louisiana Mineral Servitudes		10,173		5,740		4,411		4,048		14,584		9,788
		20,991		16,558		18,507		18,144		39,498		34,702
Total (5)		1,069,894		479,874		1,450,344		848,157		2,520,238		1,328,031

(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 36,021 gross acres in Utah.

(4) Includes interests in Alabama, Kansas, Nebraska and South Dakota.

(5) Subsequent to December 31, 2007, St. Mary divested certain non-core properties, which included leases covering approximately 155,400 and 53,900 developed gross and net acres, respectively, and 67,100 and 38,400 undeveloped gross and net acres, respectively. Additionally, St. Mary also divested its overriding royalty interest in 36,000 gross acres in Utah.

Major Customers

During 2007 and 2006, no customer individually accounted for ten percent or more of the Company’s total oil and gas production revenue. During 2005, sales to Tesoro Refining and Marketing individually accounted for 13 percent of the Company’s total oil and gas production revenue.

Employees and Office Space

As of February 15, 2008, we had 438 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 77,000 square feet of office space in Denver, Colorado for our executive and

administrative offices, of which approximately 10,000 square feet is subleased. We lease approximately 22,000 square feet of office space in Tulsa, Oklahoma; approximately 21,000 square feet in Shreveport, Louisiana; approximately 20,000 square feet in Houston, Texas; approximately 12,000 square feet in Midland, Texas; approximately 36,000 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. We have obtained title opinions or have 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. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity is beginning to place an increasing demand on storage volumes. Crude oil and the demand for heating oil are also impacted by generally higher prices in the winter – although oil is much more driven by global supply and demand. Seasonal anomalies such as mild winters sometimes lessen these fluctuations. The impact of seasonality has somewhat been exacerbated 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 competition for acquisitions of prospective oil and natural gas properties and oil and gas reserves. We believe that our leasehold position provides a sound foundation for a solid 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, own drilling rigs, 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 drilling capital budget for 2008. We are seeing signs of loosening rig availability, although it is quite specific by region. Finally, we also compete for people. Throughout the industry, the need for talented people has grown at a time when the number of people available is constrained. We are not insulated from this resource constraint and we have to be willing to compete in this market in order to be successful.

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 sale of natural gas is 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. While the rules and regulations of the Federal Energy Regulatory Commission (FERC) have in the past greatly affected the production and sale of natural gas, the direct impact on the upstream exploration and production segment of the energy industry has changed to allow market forces to set the price paid for natural gas. FERC regulations continue to affect the midstream and transportation segments of the industry and thus can have an indirect impact of the sales price we receive for natural gas production. 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 or Congress than other natural gas producers and marketers with whom we compete.

Certain operations we conduct involve federal minerals administered by the Minerals Management Service (MMS). 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 (OCS) wells

Calculation of royalty payments and the valuation of production for this purpose

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, pooling of interests in natural gas and oil properties, and establishment of maximum rates of production from natural gas and oil wells. States generally have the ability to prorate production to the market demand for oil and natural gas; however, this is not currently occurring.

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 for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects. 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 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 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 underground rock formations.

A portion of our acreage at the Hanging Woman Basin coalbed methane project is on federal 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 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 with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” 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 activities, 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 implied by those reserve estimates

·	Future oil and natural gas production estimates

·	Our outlook on future oil and natural 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

·	Other similar matters such as those discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 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 and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the “Risk Factors” in Item 1A of this Form 10-K, and include such factors as:

·	The volatility and level of realized oil and natural gas prices

·	Our ability to replace reserves and sustain production

·	Unexpected drilling conditions and results

·	Unsuccessful exploration and development drilling

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

·	The risks of hedging strategies

·	Lower prices realized on oil and natural gas sales resulting from our commodity price risk management activities

·	The uncertain nature of the expected benefits from acquisitions and divestitures of oil and natural gas properties, including uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities

·	The imprecise nature of oil and natural gas reserve estimates

·	Uncertainties inherent in projecting future rates of production from drilling activities and acquisitions

·	Drilling and operating service availability

·	Uncertainties in cash flow

·	The financial strength of hedge contract counterparties

·	The negative impact that lower oil and natural gas prices could have on our ability to borrow

·	The potential effects of increased levels of debt financing

·	Our ability to compete effectively against other independent and major oil and natural gas companies

·	Litigation, environmental matters, the potential impact of government regulations, and the use of management estimates.

We caution you that forward-looking statements are not guarantees of future performance and that actual results or developments may be materially different 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. Within 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 materials with or furnish such materials 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

http://www.stmaryland.com

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

Glossary of Oil and Natural Gas Terms

The oil and natural gas 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 natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil.

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

Development well. A well drilled within the proved area of an oil or natural 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 natural gas in sufficient commercial quantities.

Exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural 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 conditioned 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 natural 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 natural gas activities, including the effect of asset retirement obligations, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates during the same period. The information for this calculation is included in Note 13 of Part IV, Item 15 of this Form 10-K.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

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

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

Horizontal wells. Wells which are drilled at angles greater than 70 degrees from vertical.

Hydraulic fracturing. A procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This increases the permeability and porosity of the targeted formation.

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

MMBOE. One million barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of oil.

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

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

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

MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas (including natural 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.

OCS. Outer Continental Shelf in the Gulf of Mexico.

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 ten 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 natural gas or that is capable of commercial 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, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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 in 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 of reserves. 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 of reserves. 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 amount or fee paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural 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 natural gas property entitling the owner to shares of oil and natural gas production free of costs of exploration, development, and production operations.

Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on year-end prices, costs, and statutory tax rates, and a ten percent annual discount rate. 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.

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 natural 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, cash flows, access to capital, and ability to grow.

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

Historically, the markets for oil and natural gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural 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 refining capacity constraints in a regional or localized area may impact the realized price for oil or natural gas

·	Political instability or armed conflict in oil or natural gas producing regions

·	The price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas

·	Worldwide and domestic economic conditions

·	The level of consumer demand for hydrocarbons

·	Productive capacity of the industry as a whole

·	The availability of transportation facilities

·	Weather conditions

·	The price and availability of alternative fuels

·	Governmental regulations and taxes.

These factors and the volatility of oil and natural gas markets make it very difficult to predict future oil and natural gas price movements with any certainty. Declines in oil or natural gas prices would reduce our revenues and could also reduce the amount of oil and natural gas that we can produce economically, which 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 natural gas reserves that are economically recoverable. Our properties produce oil and natural gas at a declining rate over time. In order to maintain current production rates we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. In addition, competition for the acquisition of producing oil and natural gas properties is intense and many of our competitors have financial and other resources needed to evaluate and integrate acquisitions that are substantially greater than those available to us. Therefore, we may not be able to acquire oil and natural 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 over time.

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

We face intense competition from major oil companies, independent oil and natural gas exploration and production companies, financial buyers, and institutional and individual investors who are actively seeking oil and natural gas properties throughout the world, as well as the equipment, expertise, labor, and materials required to operate oil and natural gas properties. Many of our competitors have financial and technical resources vastly exceeding those available to us, and many oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able or willing to pay more for development prospects and productive properties or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. 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 also compete for people. The need for talented people across all disciplines in the industry has grown at a time when the number of people available is constrained.

The actual quantities and present values of our proved oil and natural 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 natural 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 natural gas prices, drilling and operating expenses, capital expenditures, taxes, timing of operations, 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. Therefore, these estimates are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, production taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of and present values related to 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 activity, prevailing oil and natural gas prices, costs to develop and operate properties, 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, 2007, approximately 23 percent, or 250.2 BCFE, of our estimated proved reserves were proved undeveloped and approximately 11 percent or 116.0 BCFE, were proved developed non-producing. 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. In order to recover our proved undeveloped reserves, an estimated $234 million of capital expenditures will be spent during 2008. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. In order to bring production on-line for our proved developed non-producing reserves, we estimate capital expenditures of $12 million for 2008. 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. The balance of our capital expenditure budget for 2008 is directed towards projects that are not yet classified within the construct of proved reserves as defined by Regulation S-X of the Securities and Exchange Commission.

You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this Form 10-K represent the current market value of our estimated proved 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, 2007, were estimated using a calculated sales price of $6.80 per MMBtu of natural gas (NYMEX Henry Hub spot price) and $95.98 per Bbl of oil (NYMEX West Texas Intermediate spot price). We then adjust this base price to ensure we consider the appropriate basis and location differentials as of that date in estimating our proved reserves. During 2007, our monthly average realized natural gas prices, excluding the effect of hedging, were as high as $7.83 per Mcf and as low as $5.42 per Mcf. For the same period our monthly average realized oil prices before hedging were as high as $91.53 per Bbl and as low as $48.88 per Bbl. Many other factors will affect actual future net cash flows, including:

·	Amount and timing of actual production

·	Supply and demand for oil and natural gas

·	Curtailments or increases in consumption by oil purchasers and natural gas pipelines

·	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 natural 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 potential deficiencies 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.

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 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 natural 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 natural 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 geologic irregularities in formations

·	Equipment failures or accidents

·	Hurricanes and other 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 crews, fracture stimulation crews and equipment, chemicals, and supplies.

The prevailing prices of oil and natural gas 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 materially 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 we use do not allow us to know conclusively prior to drilling a well if oil or natural gas is present, or whether it can 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 holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling and completion costs.

Our future drilling activities may not be successful. 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 natural 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 periodically 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 natural 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

·	There is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement

·	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 could impact 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 natural 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 natural 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 natural gas properties, on a field basis, cannot exceed the estimated undiscounted 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 its fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or natural 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 write-down of oil and natural gas properties cannot be reversed at a later date even if oil or natural 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 acquiring new reserves, and prices paid for oil and natural gas. If oil or natural 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 or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms. The proceeds offered to us for potential divestitures may not always be of acceptable value to us.

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

The markets for raising public debt are quite constrained at the current time, given the overall liquidity concerns arising from the widely reported difficulties in the sub-prime and leveraged loan markets. While we continue to believe that our secured revolving credit facility will be sufficient for the foreseeable future, we must continually monitor the overall condition of the markets as a whole and remain cognizant that an overall pressure on the credit markets has the risk of increasing the cost of borrowings or decreasing the availability of new capital or the capacity of existing debt instruments.

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

Our revolving credit facility currently has a maximum commitment amount of $500 million, subject to a borrowing base of $1.25 billion that the lenders periodically redetermine based on the bank groups’ assessment of the value of our oil and natural gas properties, which in turn is based in part on oil and natural gas prices. Lower oil or natural gas prices in the future could limit our borrowing base and reduce our ability to borrow under the credit facility.

Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.

As of December 31, 2007, we had $287.5 million of total long-term senior unsecured debt outstanding under our 3.50 % Senior Convertible Notes due 2027 and $285.0 million of secured debt outstanding under our revolving credit facility. As of February 15, 2008, we had an outstanding balance of $180.0 million drawn against our revolving credit facility resulting in $320.0 million of available debt capacity under our revolving credit facility, assuming the borrowing conditions of this facility were met. Our long-term debt represented 40 percent of our total book capitalization as of December 31, 2007. The decrease in the borrowings subsequent to year end is a result of using the net proceeds from the sale of non-core properties on January 31, 2008. Our revolving credit facility has a maximum loan amount of $500 million, a current borrowing base of $1.25 billion, and we have elected a current commitment amount of $500 million.

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

·	Making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements

·	Requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest associated with our debt rather than to productive investments.

·	Limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, creating liens on our properties, making acquisitions, and paying dividends

·	Placing us at a competitive disadvantage compared to our competitors that have less debt

·	Making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our

revolving credit facility or from other sources we might not be able to service our debt or to fund our other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, sell equity securities, sell assets, or restructure or refinance our debt. We might not be able to sell our equity securities, sell our assets or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives.

Our debt instruments, including our revolving credit agreement, also permit us to incur additional debt in the future. In addition, the entities we may acquire in the future could have significant amounts of debt outstanding which we could be required to assume in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition.

In addition, our revolving 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 base 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 natural 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, freezing conditions, 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.

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.

Following the severe Atlantic hurricanes in 2004 and 2005, the insurance markets 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, and such coverage has become substantially more expensive.

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 natural 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 natural 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 natural gas drilling and production, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of interests in oil and natural gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment standards, 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 ongoing or planned operations on federal leases to be delayed, suspended or terminated. Any such delay, suspension or termination could have a material adverse effect on our operations. Our coalbed methane development at Hanging Woman Basin is particularly affected, as a portion of our acreage is on federal lands in Montana which have been subject to delays in permitting.

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. Under existing or future environmental laws and regulations, we could face significant liability to governmental authorities and third parties, including joint and several as well as strict liability, for discharges of oil, natural gas, or other pollutants into the air, soil, or water, and we could be required 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 materially adverse effect on us.

In addition, recent studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. In response to these studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West have separately taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts et al. v. Environmental Protection Agency et al., the U.S. Environmental Protection Agency must reconsider whether it is required to regulate greenhouse gas emissions from motor vehicles even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the Federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Passage of climate change legislation or other regulatory initiatives by Congress or various states or the adoption of regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases, including methane or carbon dioxide, in areas in which we conduct business could adversely affect our operations and the demand for our products.

We depend on transportation facilities owned by others.

The marketability of our oil and natural 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 natural 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.

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, 2007 to February 15, 2008, the closing daily sales price of our common stock as reported by the New York Stock Exchange ranged from a low of $31.80 per share to a high of $44.07 per share. 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

·	Future sales of our common stock

·	Changes in the national and global economic outlook.

We may fail to meet expectations of our stockholders and/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.

Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well.

The potential for sales of substantial amounts of our common stock in the public market may have a material adverse effect on our stock price. As of February 15, 2008, 62,915,531 shares of our common stock 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 2,367,914 shares of our common stock were outstanding, of which 2,360,414 were exercisable. These options are exercisable at prices ranging from $4.63 to $20.87 per share. In addition, restricted stock units providing for the issuance of up to a total of 682,446 shares of our common stock were outstanding. As of February 15, 2008, there were 63,020,524 shares of common stock outstanding, which is net of 1,009,712 treasury shares.

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 to no more than $0.25 per share. The Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share or discontinue the payment of dividends altogether.

ITEM 1B. UNRESOLVED STAFF COMMENTS

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

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 materially adverse effect upon our financial condition, results of operations or cash flows.

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 2007.

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 age of the executive officers is as of February 15, 2008.

Name	Age	Position

Anthony J. Best	58	Chief Executive Officer and President
Javan D. Ottoson	49	Executive Vice President and Chief Operating Officer
David W. Honeyfield*	41	Senior Vice President - Chief Financial Officer and Secretary
Mark D. Mueller	43	Senior Vice President and Regional Manager
Stephen C. Pugh	49	Senior Vice President and Regional Manager
Paul M. Veatch	41	Senior Vice President and Regional Manager
Jerold M. Hertzler	50	Vice President - Business Development
Gregory T. Leyendecker	50	Vice President - Regional Manager
Lehman E. Newton, III	52	Vice President - Regional Manager
Milam Randolph Pharo	55	Vice President - Land and Legal and Assistant Secretary
Garry A. Wilkening	57	Vice President - Human Resources and Administration
Mark T. Solomon	39	Controller

*Mr. Honeyfield has announced that he will resign from his position of Senior Vice President - Chief Financial Officer and Secretary effective March 21, 2008, in order to pursue an opportunity in an unrelated industry.

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

Anthony J. Best joined St. Mary in June 2006 as President and Chief Operating Officer. In December 2006, Mr. Best relinquished his position as Chief Operating Officer when Javan D. Ottoson was elected to that office. Mr. Best was elected Chief Executive Officer of St. Mary in February 2007. From November 2005 to

June 2006, Mr. Best was developing a business plan and attempting to raise capital for a start-up exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., a subsidiary of Unocal Corporation, where he managed all of Unocal’s onshore U.S. assets. From 2000 to 2002, Mr. Best had an oil and gas consulting practice working with public, private, and small startup exploration and production firms. From 1979 to 2000, Mr. Best was with ARCO in a variety of positions, including a period as President - ARCO Permian, President - ARCO Latin America, Field Manager for Prudhoe Bay, and VP - External Affairs for ARCO Alaska.

Javan D. Ottoson joined St. Mary in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson has been in the oil and gas industry for over 20 years. From April 2006 until he joined St. Mary in December 2006, Mr. Ottoson was Senior Vice President – Drilling and Engineering at Energy Partners, Ltd. Mr. Ottoson managed the Permian Basin assets for Pure Resources, Inc., a subsidiary of Unocal Corporation, and its successor owner, Chevron, from July 2003 to April 2006. From April 2000 to July 2003, Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his family farm. Prior to 2000, Mr. Ottoson worked for ARCO in management and operational roles. These roles included President - ARCO China, Commercial Director of ARCO British, and Vice President of Operations and Development - ARCO Permian.

David W. Honeyfield was appointed as Chief Financial Officer in May 2005 and Senior Vice President in March 2007. 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 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. Mr. Honeyfield had been with Arthur Andersen since January 1991.

Mark D. Mueller joined St. Mary in September 2007 as Senior Vice President. Mr. Mueller was appointed as the Regional Manager of the Rocky Mountain region effective January 1, 2008. Mr. Mueller has been in the energy industry for 21 years and was Vice President and General Manager at Samson Exploration Ltd. in Calgary, Canada from September 2006 to September 2007. Mr. Mueller was Vice President and General Manager for Samson Canada Ltd. from April 2005 until its sale in August 2006. Mr. Mueller joined Samson Canada Ltd. as Project Manager in May 2003 to build a new basin-centered gas business unit and was Vice President from December 2003 to August 2006. Prior to joining Samson, Mr. Mueller was West Central Alberta Engineering Manager for Northrock Resources Ltd. (a wholly-owned subsidiary of Unocal Corporation) in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing responsibility in engineering and management for Unocal throughout North America and Southeast Asia.

Stephen C. Pugh joined St. Mary as Senior Vice President and Regional Manager of the ArkLaTex region in July 2007. Stephen Pugh has over 26 years of experience in the oil and gas industry. He was a Managing Director for Scotia Waterous in the Houston office from July 2006 to July 2007. Prior to joining Scotia Waterous, Mr. Pugh had over 17 years of experience in acquisition and divestiture, operations and engineering with Burlington Resources (subsequently ConocoPhillips). His most recent title there was General Manager, Engineering and Operations – Gulf Coast, a position he held from May 2004 to June 2006. Prior to that, he was Vice President - Acquisitions and Divestitures for Burlington Resources Canada. He held that position from May 2000 to May 2004. Mr. Pugh began his career with Superior Oil (subsequently Mobil Oil) in Lafayette, Louisiana, where he worked in production, drilling, and reservoir engineering.

Paul M. Veatch was appointed Senior Vice President and Regional Manager of the Mid-Continent region in March 2006. Mr. Veatch joined St. Mary in April 2001 as Regional Acquisition and Divestiture Engineer of the ArkLaTex region. He was Manager of Engineering from April 2003 to August 2004 and Vice President – General Manager, ArkLaTex from August 2004 to March 2006. Prior to joining St. Mary, Mr. Veatch worked in various engineering and supervisory roles at Burlington Resources from November 1994 to April 2001. Prior to joining Burlington Resources, Mr. Veatch held various engineering and operations positions for Arco Oil & Gas Company (subsequently Vastar Resources) in Louisiana and Texas from July 1989 until November 1994.

Jerold M. Hertzler was appointed Vice President - Business Development in March 2007. Mr. Hertzler joined St. Mary in October 1998 as Manager of Reservoir Engineering. He assumed the role of Acquisitions Manager in July 2003 and was promoted to Director and Business Development in March 2005. Mr. Hertzler entered the petroleum industry in December of 1979 and has served in various operations and reservoir engineering roles since then, including nine years with Tenneco Oil Company and seven years with Meridian Oil Company.

Gregory T. Leyendecker was appointed Vice President - Regional Manager of the Gulf Coast region in July 2007. Mr. Leyendecker joined St. Mary in December 2006 as Operations Manager for the Gulf Coast region in Houston. Mr. Leyendecker has worked for 27 years in the energy industry and held various positions with the Unocal Corporation from 1980 until its acquisition in 2005. During this time he was the Asset Manager for Unocal Gulf Region USA from 2003 to June 2004 and Production and Reservoir Engineering Technology Manager for Unocal from June 2004 to August 2005. He was appointed Drilling and Workover Manager for Chevron’s San Joaquin Valley business unit in Bakersfield, California in August 2005 and held this position until January 2006. Immediately prior to joining St. Mary, Mr. Leyendecker was Vice President of Drilling Management Services for Enventure Global Technology, a position he held from February 2006 to November 2006.

Lehman E. Newton III joined St. Mary in December 2006 as General Manager for the Midland office and was appointed Vice President - Regional Manager of the Permian region in June 2007. Mr. Newton has over 27 years of exploration and production experience in engineering, operations and business development. From November 2005 to November 2006 Mr. Newton served as Project Manager for one of Chevron’s largest projects in the continental United States. Mr. Newton joined Pure Resources in February 2003 as the Business Development Manager and worked in that capacity until October 2005. Mr. Newton was a founding partner in Westwin Energy, an independent exploration and production company in the Permian Basin, from June 2000 to January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering, operations and management roles. These assignments included Asset Manager, ARCO’s East Texas operations, Vice President, Business Development, ARCO Permian, and Vice President of Operations and Development, ARCO Permian.

Garry A. Wilkening was appointed Vice President - Human Resources and Administration in November 2007 and served as Vice President of Administration from January 2007 to November 2007. Mr. Wilkening relinquished his position as Controller in January 2007 when Mark T. Solomon was elected to that office. Mr. Wilkening was Vice President - Administration and Controller from 1999 to 2007.

Mark T. Solomon was appointed Controller in January 2007. Mr. Solomon joined St. Mary in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President of Financial Reporting from September 2002 to May 2006 and Assistant Vice President and Assistant Controller from May 2006 to January 2007. Prior to joining St. Mary, Mr. Solomon was an auditor with Ernst & Young.

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 serve at the discretion of the Board of Directors. Any officer elected by the Board may be removed by the Board with or without cause, subject to any contractual rights of the person so removed.

Mr. Best has an employment agreement with St. Mary. Upon any termination of the employment of Mr. Best by St. Mary for any reason other than death, disability, or misconduct by Mr. Best, St. Mary is generally obligated to continue to pay his base salary and insurance benefits for a period of two years after termination. In addition, upon commencement of employment, Mr. Best received a cash bonus and a special restricted stock award of 20,000 shares that are vested immediately and not subject to forfeiture. Over the next two years Mr. Best is also eligible to earn additional restricted shares in varying amounts, a portion of which are based on the Company’s net asset value growth.

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 2007 and 2006, as reported by the New York Stock Exchange.

Quarter Ended	High		Low
December 31, 2007	$	44.50	$	35.40
September 30, 2007		37.15		31.20
June 30, 2007		40.19		34.91
March 31, 2007		38.20		33.55

December 31, 2006	$	40.85	$	33.43
September 30, 2006		43.92		34.77
June 30, 2006		45.59		34.38
March 31, 2006		44.69		34.70

PERFORMANCE GRAPH

The following performance graph compares the cumulative total stockholder return on St. Mary’s common stock for the period December 31, 2002, to December 31, 2007, with the cumulative total return of the Dow Jones U.S. Exploration and Production Broad Index, and the Standard & Poor’s 500 Stock Index.

COMPARE 5-YEAR CUMULATIVE TOTAL RETURN

AMONG ST. MARY LAND & EXPLORATION COMPANY

The preceding information under the caption “Performance Graph” shall be deemed to be “furnished” but not “filed” with the Securities and Exchange Commission.

Holders. As of February 15, 2008, the number of record holders of St. Mary's common stock was 116. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 21,700.

Dividends. St. Mary has paid cash dividends to stockholders every year since 1940. Semi-annual dividends of $0.025 per share were paid in each of the years 1998 through 2004. Semi-annual dividends of $0.05 per share were paid in 2005, 2006 and 2007. 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 per year. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.3 million in 2007.

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, restricted shares issued to directors under the Non-Employee Director Stock Compensation Plan, and restricted shares issued to directors under the 2006 Equity Incentive Compensation Plan (the “2006 Equity Plan”), St. Mary has no restricted shares outstanding as of December 31, 2007.

Equity Compensation Plans. St. Mary has the 2006 Equity 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 this plan. 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, 2007:

	( 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))
2006 Equity Incentive Compensation Plan
Stock Options and Incentive Stock Options		2,385,500	$	12.62		-	(1	)
Restricted Stock Plan		684,264		N/A		2,560,224	(1	)
Employee Stock Purchase Plan		-		-		1,599,811	(2	)

Equity compensation plans not approved by security holders		-		-		-

Total		3,069,764	$	12.62		4,160,035

______________

(1) In May 2006 the stockholders approved the 2006 Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, and stock-based awards to key employees, consultants, and members of the Board of Directors of St. Mary or any affiliate of St. Mary. The 2006 Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land & Exploration Company Non-Employee Director Stock Compensation Plan (collectively, the “Predecessor Plans”). All grants of equity are now made out of the 2006 Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the 2006 Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Awards granted in 2007, 2006, and 2005 under the 2006 Equity Plan and the Predecessor Plans were 135,138, 527,678, and 209,238, respectively.

(2) Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan, 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 Employee Stock Purchase Plan are restricted for a period of 18 months from the date issued. The Employee Stock Purchase Plan is intended to qualify under Section 423 of the Internal Revenue Code. There have been 29,534, 26,046, and 28,447 shares issued under this plan in 2007, 2006, and 2005, respectively.

The following table provides information about purchases by the Company or “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the quarters and year ended December 31, 2007, 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.

PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS

	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program		Maximum Number of Shares that May Yet be Purchased Under the Program(2)

January 1, 2007 – March 31, 2007		-		$	-		-		6,000,000

April 1, 2007 - June 30, 2007		-		$	-		-		6,000,000

July 1, 2007 - September 30, 2007		791,816	(1)	$	32.76		790,816		5,209,184

October 1, 2007 - October 31, 2007		-		$	-		-		5,209,184

November 1, 2007 - November 30, 2007		-		$	-		-		5,209,184

December 1, 2007 - December 31, 2007		1,400		$	37.52		1,400		5,207,784

Total October 1, 2007 - December 31, 2007		1,400		$	37.52		1,400		5,207,784

Total		793,216		$	32.76		792,216		5,207,784

(1) Includes a total of 1,000 shares purchased by Anthony J. Best, St. Mary’s President and Chief Executive Officer, in open market transactions that were not made pursuant to our stock repurchase program. The table does not include the 678 shares purchased by Mr. Best under the Company’s employee stock purchase plan.

(2) In July 2006 the Company’s Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, the Company has Board authorization to repurchase 5,207,784 shares of common stock on a prospective basis. 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 stock repurchases are subject to covenants in our bank credit facility, including the requirement that we maintain certain levels of stockholders’ equity.

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. In March 2005 the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend whereby one additional share of common 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 herein have been reclassified to reflect this stock split.

	Years Ended December 31,
	2007		2006		2005		2004		2003
	(In thousands, except per share data)

Total operating revenues	$	990,094	$	787,701	$	739,590	$	433,099	$	393,708

Income before cumulative effect of change in accounting principle	$	189,712	$	190,015	$	151,936	$	92,479	$	90,140

Net income per share:
Basic	$	3.07	$	3.38	$	2.67	$	1.60	$	1.53
Diluted	$	2.94	$	2.94	$	2.33	$	1.44	$	1.40

Total assets at year end	$	2,571,680	$	1,899,097	$	1,268,747	$	945,460	$	735,854

Long-term obligations:
Line of credit	$	285,000	$	334,000	$	-	$	37,000	$	11,000
Senior convertible notes	$	287,500	$	99,980	$	99,885	$	99,791	$	99,696

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

Supplemental Selected Financial and Operational Data:

	Years Ended December 31,
	2007			2006			2005			2004			2003
	(In thousands, except per share data)
Balance Sheet Data:
Total working capital (deficit)	$	(92,604	)	$	22,870		$	4,937		$	12,035		$	3,101
Total stockholders’ equity	$	863,345		$	743,374		$	569,320		$	484,455		$	390,653

Weighted-average shares outstanding:
Basic		61,852			56,291			56,907			57,702			62,467
Diluted		64,850			65,962			66,894			66,894			71,069

Reserves:
Oil (MMBbl)		78.8			74.2			62.9			56.6			47.8
Gas (Mcf)		613.5			482.5			417.1			319.2			307.0
MCFE		1,086.5			927.6			794.5			658.6			593.7

Production and Operational:
Oil and gas production revenues, including hedging	$	936,577		$	758,913		$	711,005		$	413,318		$	365,114
Oil and gas production expenses	$	218,208		$	176,590		$	142,873		$	95,518		$	88,509
DD&A	$	227,596		$	154,522		$	132,758		$	92,223		$	81,960
General and administrative	$	60,149		$	38,873		$	32,756		$	22,004		$	21,197

Production Volumes:
Oil (MMBbl)		6.9			6.1			5.9			4.8			4.5
Gas (Bcf)		66.1			56.4			51.8			46.6			49.7
BCFE		107.5			92.8			87.4			75.4			76.9

Realized Price – pre hedging:
Per Bbl	$	67.56		$	59.33		$	53.18		$	39.77		$	29.40
Per Mcf	$	6.74		$	6.58		$	8.08		$	5.85		$	5.12

Realized Price – net of hedging:
Per Bbl	$	62.60		$	56.60		$	50.93		$	32.53		$	26.96
Per Mcf	$	7.63		$	7.37		$	7.90		$	5.52		$	4.89

Expense per MCFE:
LOE	$	1.31		$	1.25		$	0.99		$	0.81		$	0.77
Transportation	$	0.14		$	0.12		$	0.09		$	0.10		$	0.09
Production taxes	$	0.58		$	0.54		$	0.56		$	0.36		$	0.29
DD&A	$	2.12		$	1.67		$	1.52		$	1.22		$	1.07
General and administrative	$	0.56		$	0.42		$	0.37		$	0.29		$	0.28

Cash Flow:
From operations	$	630,792		$	467,700		$	409,379		$	237,162		$	204,319
Used in investing	$	(803,872	)	$	(724,719	)	$	(339,779	)	$	(247,006	)	$	(196,939	)
From (used in) financing	$	215,126		$	243,558		$	(61,093	)	$	1,435		$	(3,707	)

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, Items 1 and 2 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 development, exploration, exploitation, acquisition, and production of natural gas and crude oil in the United States. We earn 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; South Texas assets targeting the Olmos shallow gas formation; and the onshore Gulf Coast and offshore Gulf of Mexico. We have developed a balanced and diverse portfolio of proved reserves, development drilling opportunities, and unconventional resource prospects.

In 2007, we achieved the following financial and operational results:

·	Average daily gas production of 181.0 MMcf per day, up 17 percent from 2006. Average daily oil production of 18.9 MBbl per day, up 14 percent from 2006. Average total equivalent daily production was 294.5 MMCFE which was an annual record for the Company.

·	Estimated proved reserves of 78.8 MMBbls of oil and 613.5 Bcf of natural gas, or 1,086.5 BCFE, as of December 31, 2007. This was an increase of 17 percent from year-end 2006 proved reserves of 927.6 BCFE.

·	Diluted earnings per share for 2007 were $2.94 on net income of $189.7 million. This reflects a slight decrease in net income when compared to 2006. The earnings per share benefited from the 0.8 million shares acquired by the Company during 2007.

·	Cash flow from operating activities of $630.8 million, an increase of 35 percent from 2006.

·	Debt to capitalization ratio is 40 percent. The 2007 amount does not consider proceeds from our divestiture of non-core assets that closed on January 31, 2008, described in Note 3 of Part IV, Item 15 of this report, which were used to pay down outstanding bank borrowings.

Our business objective is to economically grow our production and proved reserves through development, exploitation, and exploration activities, as well as through acquisitions of developed and undeveloped properties. Our operations are generally funded first through cash flows from operating activities, and then borrowings under our existing credit facility. Acquisitions may be funded with proceeds from sales of public or private debt and equity, borrowings under our existing credit facility, and cash flow from operating activities. In 2007, we deployed $740.9 million for development and exploration and invested $185.2 million for acquisitions of oil and gas properties.

A major determinant of the value of our Company is the value of our proved reserves. At year-end 2007, we had proved reserves of 1,086.5 BCFE of which 56 percent were natural gas and 77 percent were characterized as proved developed. Based on our year-end oil and gas reserve estimation process, we determined that we added 94.8 BCFE of proved reserves through acquisitions in 2007, 96 percent of which was natural gas and 42 percent of which was proved developed. Upward price revisions resulted in an increase of 34.5 BCFE which were driven primarily by higher oil prices at December 31, 2007, compared to the prior year. We experienced positive

performance revisions of 6.4 BCFE and divested 1.4 BCFE of proved reserves. The before income tax PV-10 value of our proved reserves was $3.9 billion as of December 31, 2007. The after tax value of $2.7 billion as represented by the standardized measure calculation is presented in Note 13 of Part IV, Item 15 of this report. A reconciliation between these two amounts is shown under Reserves in Part I, Items 1 and 2 of this report. This value is based on adjusted year-end pricing of $7.56 per Mcf and $88.71 per Bbl, which are up 36 percent and 65 percent, respectively, from the prior year.

Chief Executive Officer, Chief Financial Officer and Senior and Regional Management Transitions

During 2007, the Company underwent or announced personnel changes in the chief executive position and several regional manager positions. On February 23, 2007, Mark Hellerstein, retired as Chief Executive Officer after serving in that role since 1995. Tony Best, President of the Company, was appointed as Chief Executive Officer on that date. Mr. Hellerstein continues to serve as the Chairman of the Board. In June 2007, Jerry Schuyler, the Senior Vice President responsible for the Gulf Coast and Permian regions, left St. Mary to pursue other professional opportunities. Greg Leyendecker, then Operations Manager for the Gulf Coast region, assumed responsibility for the Gulf Coast and is now Vice President - Regional Manager of the Gulf Coast region. We also made the Midland office a stand-alone regional office which is headed by Lehman Newton III, as Vce President - Regional Manager of the Permian region. Mr. Leyendecker and Mr. Newton both joined St. Mary in 2006 and each have over 25 years of management and operational experience in the oil and gas industry. In July 2007, Stephen Pugh joined the Company as Senior Vice President - Regional Manager of the ArkLaTex region. Mr. Pugh succeeded David Hart, who retired from St. Mary after 15 years in various roles at the Company. Mr. Pugh came to St. Mary with over 25 years of engineering, operations, and business development experience in the oil and gas industry. In August of this year, Robert Nance, Senior Vice President - Regional Manager of the Rocky Mountain region announced his decision to retire in the first quarter of 2008 after more than 40 years in the oil and gas industry. Mark Mueller joined the Company as Senior Vice President in September and is now responsible for the Rocky Mountain region. Mr. Mueller has 20 years of management and technical experience in the oil and gas industry. Effective January 1, 2008, Mark Mueller became the Senior Vice President and Regional Manager. Subsequent to year end, David Honeyfield, Senior Vice President - Chief Financial Officer, announced he will resign effective March 21, 2008, to accept an executive position in an unrelated industry.

2007 Acquisition of South Texas Oil and Natural Gas Assets

We entered the greater Maverick Basin with two acquisitions in South Texas that target the Olmos shallow gas formation. These two acquisitions comprised the majority of the 94.8 BCFE of reserves classified as purchases of minerals in place. These properties added a sizable inventory of lower risk drilling locations to our portfolio. The first was the $30.0 million Catarina acquisition that closed in June 2007, in which we acquired 14.0 BCFE of proved reserves that were 99 percent gas and 65 percent proved developed. The average working interest in these assets is 30 percent; however we are the operator of the project area. The more significant transaction was the $148.9 million Rockford acquisition that closed in October 2007, where we have a nearly 100 percent working interest and are the operator. As mentioned elsewhere in this report, the final year-end reserve estimates we recorded were lower than the initial estimates we previously disclosed at the time of acquisition. We initially estimated reserves on a dry gas basis in our previous disclosure at the time of the acquisition whereas our annual report on Form 10-K disclosures utilize a wet gas presentation convention. This accounted for approximately ten BCFE of the difference in volumes, without any impact on value. The remaining difference was a result of our final year end assessment of proved non-producing reserves and our proved undeveloped reserves which were each lower than the amounts preliminarily estimated at the time of acquisition. The Rockford properties are adjacent to the Catarina assets. Consistent with prior acquisitions, we hedged several years of risked production related to these assets at the time of acquisition. These assets will be managed by our Gulf Coast region based in Houston, Texas.

2007 Capital Markets Activity

In March of 2007 we called for redemption of the then outstanding $100.0 million 5.75% Senior Convertible Notes. The notes had a conversion price of $13.00 per share. One hundred percent of the holders of the notes elected to convert their notes into shares of common stock. As a result of the conversion, 7.7 million shares of stock were issued to the note holders. This resulted in a decrease to long-term debt of $100.0 million, and an increase to common stock associated with the conversion together with the recognition of the excess tax benefit

associated with the contingent interest feature associated with the notes. In April of 2007, we completed the private placement of $287.5 million of 3.50% Senior Convertible Notes. The net proceeds from the 3.50% Senior Convertible Notes were used to repay outstanding borrowings under our revolving credit facility.

Reserve Replacement, Finding Costs 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 activities than we produce. Future growth will depend on our ability to economically continue adding reserves in excess of production.

We believe growth in net asset value per share drives appreciation in our stock price over the long term. Our challenge is to grow net asset value per share. To accomplish this, our goal is to economically replace at least 200 percent of annual production with new reserves and to grow production by ten to 15 percent per year. In 2007, we replaced 248 percent of our production at a finding cost of $3.48 per MCFE. The reserve replacement percentages and finding cost terms are defined in the glossary at the end of Part I, Items 1 and 2 of this report. Excluding acquisitions, we replaced 161 percent of our production at a cost of $4.42 per MCFE. Through acquisition activities we replaced 88 percent of production at an acquisition cost of $1.71 per MCFE. We sold reserves representing 1.4 BCFE of our proved reserves during 2007. We believe annual reserve replacement percentage and finding cost amounts are important analytical measures that are widely used by investors and industry peers in evaluating and comparing 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. We note that aberrations, causing both relatively good and bad results, will occur over short intervals of time. Our three-year average reserve replacement ratio – including sales is 249 percent and our three-year average all-in finding cost is $3.01 per MCFE. Our finding cost numbers, particularly those related to drilling activities, have been notably higher in recent years. Part of this is explained by increases in completed well costs that have occurred in recent years which have affected all exploration and production companies. A significant part has related to the performance of our capital investments being less than anticipated. We will need to see an improvement in the types of projects we are pursuing and/or see an improvement in our operating abilities to meaningfully bring our finding cost numbers down. We believe that we have taken steps through recent acquisitions and portfolio screenings to improve the projects in which we are investing. Our operating teams are also performing technological reviews to see where we can improve our operations.

Sustainability in our business is dependent on the ability to create new ideas and new value year-after-year. The challenges we face are increasingly more difficult each year 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 area can be fully utilized. We provide a compensation package that aligns their goals with those of the Company and in turn with those of our stockholders. We support our personnel with 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 generation of new ideas and the utilization of appropriate technology to improve the economics of our operations. We believe that we have sufficient capital resources for the foreseeable future, that we have the ability to grow our workforce, and that we have the necessary access to drilling rigs and services to execute our drilling budget for 2008 in a successful and profitable manner.

Oil and Gas Prices

Results of our operations and financial condition are significantly affected by oil and natural gas commodity prices, which fluctuate dramatically. In 2007, we saw a net increase in oil prices throughout the year. Geopolitical unrest in various producing regions overseas and concerns domestically related to refinery utilization and petroleum product inventories were the principal drivers of the increase in oil prices in 2007. Natural gas

prices were moderated throughout 2007 by high levels of natural gas in storage and a lack of significant disruptive hurricane activity during year.

Repurchase of Common Stock

We evaluate the market price of our common stock relative to our internal assessment of net asset value per share. To the extent that the market price per share is below what we believe to be the net asset value per share and when the trading window for the Company and executive management is open, we may repurchase shares under the program. In 2007, we repurchased 792,216 shares of our common stock in the open market for a weighted-average price of $32.76 per share, including commissions. These shares were purchased under a share repurchase program approved by the Board. At the time we repurchased our shares, we entered into hedges for a commensurate amount of our production that was represented by the share repurchase in order to lock in the discounted price at which our shares were trading. As of the date of this filing, we are authorized to repurchase an additional 5,207,784 million shares under this program.

Hedging Activities

We have an active hedging program in which we hedge the first two to five years of an acquisition’s risked production. We will also on occasion enter into derivative transactions to hedge a portion of our existing forecasted production. In October 2005, we hedged a significant portion of anticipated future production from our current producing properties using zero-cost collars. We also hedged a portion of specific forecasted natural gas production for 2006, 2007, and 2008 using swap contracts. Taking into account all oil and gas production hedge contracts in place through February 15, 2008, we have hedged anticipated future production of approximately 11 million Bbls of oil, 70 million MMBtu of natural gas, and 1 million Bbls of natural gas liquids through the year 2011. We believe we have established an economic base for our future operations, and the spread between the price floors and ceilings 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

Payments made for distributions from the Net Profits Plan have been expensed as compensation costs in the amounts of $31.9 million, $26.1 million, and $20.8 million for the years ended December 31, 2007, 2006, and 2005, respectively. Although increasing each year, these payments for 2007 were lower than originally budgeted due to the effects of increased oil and gas production expense and additional capital expenditures, both of which decreased the current impact of and delayed the timing of payout for the 2004 pool. The actual cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool. Actual cash payments will be inherently different from the estimated liability amounts. More detailed discussion is included in the analysis in the Comparison of Financial Results and Trends sections below. An increasing percentage of the costs associated with the payments for the Net Profits Plan are attributable to general and administrative expense as compared to exploration expense. This is a function of the normal departure of employees who previously contributed to our past exploration efforts. We have determined that because of the change in circumstances, a greater percentage of the payments should be recorded as general and administrative expense beginning in 2007.

With respect to the accounting estimate of the liability associated with future estimated payments from our Net Profits Plan, we have recorded $50.8 million of net expense for the year ended December 31, 2007, thereby increasing the long-term liability associated with this item. This increase is related to an increase in the estimated future prices used to calculate the liability driven by overall commodity price increases, the accretion of the discount used for the calculation, and the addition of the 2007 pool. Additionally, we adjusted our discount rate used to calculate the present value of future payments during the fourth quarter of 2007 from a base rate of 15 percent to 12 percent. The single largest item was the impact from the change in discount rate, which drove an increase in the liability of $29 million as of December 31, 2007. As a result of these factors the liability increased to $211.4 million at December 31, 2007. While we have forecast that this liability will again increase in 2008, it

is not possible to predict this with certainty due to the impact of commodity prices and reserve estimates on the valuation of this estimated liability. The Company will not be adding new Net Profits Plan pools prospectively as this benefit has been replaced with a different program, which is described in Footnote 7 of Part IV, Item 15 of this Form 10-K. The Company will continue to make payments from the established Net Profits Plan pools, as well as make prospective adjustments to the long-term liability, as necessary for current conditions. We expect general and administrative expense to increase due to changes in our incentive compensation program. Beginning in 2008, grants from the restricted stock units program and the Net Profits Plan are being replaced with grants of market-based performance shares under our 2006 Equity Plan. Although the total value of the compensation package to employees is essentially unchanged, we do expect general and administrative expense to increase as the cost of the grants of performance shares under the 2006 Equity Plan will be amortized over a much shorter time than the functional expense recorded under the Net Profits Plan.

The calculation of the estimated liability associated with the Net Profits Plan requires management to prepare an 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. The underlying principal factors for our estimates are forecasted oil and gas production from the properties that comprise each individual pool, price assumptions, cost assumptions, and discount rate. In most cases, the cash flow streams used in these calculations will span more than 20 years. The decrease in the discount rate to 12 percent was a result of the ever increasing competitive environment for proven oil and gas properties and our assessment of the overall market for proved oil and gas reserves. 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 an average of actual prices realized over the prior 24 months together with adjusted NYMEX strip prices for the ensuing 12 months for a total of 36 months of data. This average is supplemented by including the effect of realized and anticipated hedge prices for the percentage of forecasted hedged production 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 commodity prices in our calculation by five percent, the liability recorded on the balance sheet at December 31, 2007, would differ by approximately $19 million. A one percentage point decrease in the discount rate would result in an increase to the liability of approximately $12 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of appoximately $10 million. We frequently re-evaluate the assumptions used in our calculations and consider the possible impacts stemming from the current market environment including current and future oil and gas prices, discount rates, and overall market conditions.

The table below provides information regarding selected production and financial information for the quarter ended December 31, 2007, and the immediately preceding three quarters. Additional details of per MCFE costs are contained later in this section.

	For the Three Months Ended
	December 31,		September 30,		June 30,		March 31,
	2007		2007		2007		2007
	(In millions, except production sales data)
Production (BCFE)		28.5		27.5		26.0		25.5
Oil and gas production revenue, excluding the effects of hedging	$	273.7	$	228.5	$	216.2	$	193.7
Lease operating expense	$	37.8	$	36.9	$	31.6	$	34.1
Transportation costs	$	3.8	$	3.2	$	4.2	$	4.4
Production taxes	$	19.1	$	14.9	$	14.5	$	13.7
DD&A	$	64.8	$	59.1	$	54.7	$	49.0
Exploration*	$	16.0	$	12.6	$	11.1	$	19.0
General and administrative expense*	$	15.1	$	15.8	$	16.3	$	12.9
Net income	$	32.8	$	57.7	$	59.2	$	40.0

Percentage change from previous quarter:
Production (BCFE)		4%		6%		2%		2%
Oil and gas production revenues, excluding the effects of hedging		20%		6%		12%		7%
Lease operating expense		2%		17%		(7)%		9%
Transportation costs		19%		(24)%		(5)%		47%
Production taxes		28%		3%		6%		6%
DD&A		10%		8%		12%		10%
Exploration*		27%		14%		(42)%		19%
General and administrative expense*		(4)%		(3)%		26%		63%
Net income		(43)%		(3)%		48%		(8)%

*As a result of a change in circumstances in 2007, we have begun classifying payments made under the Net Profits Plan to exploration overhead only for those individuals who are currently employed by us and who continue to be involved in our exploration efforts. Therefore, the quarterly financial information presented in the above table reflects that Net Profits Plan payments associated with the distributions under the Net Profits Plan for ex-employees were recorded to general and administrative expense since there is no longer any functional link to exploration expense as there is by definition no periodic costs associated with geologic and geophysical, exploration related work by those ex-employees. The impact to any prior comparative quarter was not material.

2007 Financial Highlights

In 2007, we experienced record production and strong earnings. Our record production is the realization of operational and investment decisions made in prior years as well as the current period. Our solid earnings reflect our balanced production profile and high oil prices throughout the year. Our hedging program contributed to our earnings as we received meaningful cash flows from the realization of in-the-money natural gas hedges. Our operating margins remained strong in 2007 despite increasing operating costs. Our 2007 operating margin was $6.68 per MCFE compared to $6.27 per MCFE in 2006.

Net income for 2007 was $189.7 million or $2.94 per diluted share compared to $190.0 million or $2.94 per diluted share for the prior year. Net cash provided by operating activities was $630.8 million, up 35 percent from 2006. Average daily production for the year increased 16 percent to a record 294.5 MMCFE. Our average net realized price increased $0.53 to $8.71 per MCFE. Unit costs increased for the period as lease operating expenses increased $0.06 to $1.31 per MCFE. While general industry costs associated with drilling and completing wells are flat or declining year over year, costs related to the ongoing operation of oil and gas