form10k_123109.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, 2009

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. YesþNoo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yeso Noo

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.

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 in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the 62,106,243 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, for $20.87 per share as reported on the New York Stock Exchange was $1,296,157,291. 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 16, 2010, the registrant had 62,777,688 shares of common stock outstanding, which is net of 126,893 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 2010 annual meeting of stockholders to be filed within 120 days after December 31, 2009.

TABLE OF CONTENTS

ITEM		PAGE
	PART I

ITEMS 1. and 2.	BUSINESS and PROPERTIES	1
	General	1
	Strategy	1
	Significant Developments in 2009	1
	Outlook for 2010	4
	Assets	4
	Reserves	9
	Production	13
	Productive Wells	14
	Drilling Activity	14
	Acreage	15
	Delivery Commitments	15
	Major Customers	16
	Employees and Office Space	16
	Title to Properties	16
	Seasonality	16
	Competition	16
	Government Regulations	17
	Cautionary Information about Forward-Looking Statements	18
	Available Information	20
	Glossary of Oil and Natural Gas Terms	21

ITEM 1A.	RISK FACTORS	26

ITEM 1B.	UNRESOLVED STAFF COMMENTS	39

ITEM 3.	LEGAL PROCEEDINGS	39

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	39

ITEM 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	39

	PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	43

ITEM 6.	SELECTED FINANCIAL DATA	48

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	50
	Overview of the Company	50
	Financial Results of Operations and Additional Comparative Data	58
	Comparison of Financial Results and Trends between 2009 and 2008	62
	Comparison of Financial Results and Trends between 2008 and 2007	66
	Overview of Liquidity and Capital Resources	68
	Critical Accounting Policies and Estimates	79
	Other Liquidity and Capital Resources Information	82
	Accounting Matters	82
	Environmental	82
	Climate Change	83

TABLE OF CONTENTS
(Continued)
ITEM		PAGE

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included with the content of ITEM 7)	85

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	85

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	85

ITEM 9A.	CONTROLS AND PROCEDURES	85

ITEM 9B.	OTHER INFORMATION	88

	PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	88

ITEM 11.	EXECUTIVE COMPENSATION	88

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	88

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	88

ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	89

	PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	89

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 in North America. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stock took place in December 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 mission is to deliver outstanding net asset value per share growth to our investors via attractive oil and gas investments. Historically, a key part of meeting the goal of building stockholder value was the successful execution and integration of niche acquisitions at attractive costs. Recently we shifted the emphasis of our efforts to focus on the exploration for and development of onshore resource plays in North America. This shift was due to the fact that, as we grew, the universe of potential niche acquisition targets became smaller and less impactful to our growth. Additionally, we believe that we will be able to create more long-term value for our stockholders by building an asset base that allows for more predictable growth in production and reserves and does not rely solely on acquisitions. Our strategy is based on the following points:

·	Acquire significant leasehold positions in new and emerging resource plays

·	Leverage our core competencies in drilling and completions, as well as acquisitions

·	Exploit our legacy assets and optimize our asset base through divestitures of non-core assets when appropriate

·	Maintain a strong balance sheet while funding the growth of the enterprise.

Significant Developments in 2009

Broad Economic Downturn. Beginning in the latter part of 2008 and continuing into the first half of 2009 the global economy experienced a significant downturn related primarily to concerns over the U.S. financial system. The impact of the downturn spread quickly and affected a wide range of industries. There were two significant ramifications to the exploration and production industry. The first was that capital markets were essentially frozen at the beginning of 2009. Equity, debt, and credit markets were shut down. We were able to weather this initial shock as a result of our strong liquidity position and relatively limited capital commitments. The second impact to the industry was that fear of global recession and the associated negative impact on energy demand resulted in a significant decline in oil and gas prices. We significantly scaled back our operating activity in response to these price decreases. Our hedging program helped moderate the price fluctuations that we experienced, particularly in the first half of 2009. After the first quarter of 2009, the broader economy began to stabilize. The public markets for debt and equity opened up and banks began to be

less restrictive with credit. We were able to renew our credit facility in April of 2009. The outlook for commodity prices also began to improve. The rapid decrease in activity across the exploration and production industry led many oilfield service companies to cut their prices to the benefit of ourselves and our peers as the year progressed. As industry conditions improved throughout the year, drilling activity increased in many parts of the country.

Advancement of Resource Play Potential. From late 2007 through 2009, we established meaningful positions in several new potential resource plays, principally the Eagle Ford shale, Haynesville shale, and the Marcellus shale. Over the past year we worked to advance our understanding of these plays and move them closer to development mode. The greatest progress was made in our Eagle Ford shale program in South Texas. We successfully tested seven wells across our operated acreage position during the second half of 2009. The early results from this program suggest wells at the southern end of our acreage will produce drier gas while wells drilled further north will produce higher BTU-content gas and condensate. We are currently booking only the parallel offsets to producing wells as proved undeveloped locations. As a result, meaningful potential exists to grow proved reserves on our operated acreage because of our planned drilling activity for 2010. On our joint venture acreage in Dimmitt County, Texas, we believe these wells will produce even higher amounts of condensate and oil compared to our operated position. In the Haynesville shale program in the ArkLaTex region, a number of successful wells were drilled around our acreage position in Shelby and San Augustine counties in East Texas in 2009. The 3D seismic shoot of our acreage was recently received, and we have begun our horizontal drilling in the play. In our Marcellus shale program in north central Pennsylvania, we drilled and completed our first two horizontal wells during 2009. Initial indications from the well tests were encouraging. We are in the process of constructing the gathering system that will connect these two wells, as well as future wells, to the sales pipeline.

Volatility in Commodity Prices. Prices in 2009 were generally more stable than in 2008. However the exploration and production sector still experienced significant volatility in the prices for crude oil and natural gas. Our operations and financial condition are significantly impacted by these prices. The spot price for NYMEX crude oil in 2009 ranged from a high of $81.04 per barrel in October to a low of $33.98 per barrel in February. The average spot price for oil during the year was $61.99 per barrel. The volatility in crude oil prices in early 2009 was driven by concern regarding global demand for oil. A volatile U.S. dollar was also a contributing factor in crude price volatility as the spot price of oil reacted to the relative weakening or strengthening of the U.S. dollar.

The spot price for gas at Henry Hub, a widely used industry measuring point, averaged $3.94 per MMBtu in 2009, with a high of $6.11 per MMBtu in January and a low of $1.88 per MMBtu in September. Natural gas prices came under pressure in 2009 as a result of lower domestic product demand caused by the weakening economy; and concerns over excess supply of natural gas due to the high productivity of several emerging shale plays in the U.S. Some of the regional markets where we sell gas have seen increased downward pressures on price as a result of high levels of activity in the regions, as well as a lack of pipeline takeaway capacity or local demand. This was most pronounced in our Mid-Continent and Rocky Mountain regions. However, local index differentials, in the areas where we sell gas, narrowed towards NYMEX Hub prices in late 2009.

Decrease in Year-End Proved Reserve Estimates. Our estimated proved reserves decreased 11 percent to 772.2 BCFE at December 31, 2009, from 865.5 BCFE at December 31, 2008. We added 109.6 BCFE from our drilling program during the year, with our emerging resource play in the Eagle Ford shale in the Maverick Basin in South Texas contributing a significant portion of those additions. Our programs targeting the Woodford shale in eastern Oklahoma and the Bakken/Three Forks formations in the North Dakota portion of the Williston Basin also added meaningful additions in 2009. We sold 44.2 BCFE of proved reserves during the year, with roughly 90 percent of those relating to the divestiture of our coalbed methane project at Hanging Woman Basin along the border of Montana and Wyoming. The balance of the divested properties sold in 2009 related to non-strategic assets spread across our company.

We had a net downward revision of 49.6 BCFE that consisted of 61.6 BCFE in downward engineering revisions and an upward pricing revision of 12.0 BCFE. The largest portion of the performance revision relates to producing properties in our Wolfberry tight oil program in the Permian Basin in West Texas. Well performance data collected during 2009 at our Sweetie Peck and Halff East programs that target the Wolfberry interval indicate that these assets are underperforming our year-end 2008 decline forecasts. Accordingly, we removed 37 BCFE from proved reserves in the Permian region, primarily related to the Wolfberry tight oil program. We believe a significant portion of these reserves, while not meeting the criteria to be booked as proved reserves at year-end, are likely to eventually be produced. We also had a downward performance revision of approximately 12 BCFE related to certain Cotton Valley assets in our ArkLaTex region. The pricing methodology used to determine proved reserves changed in 2009 in accordance with new rules promulgated by the SEC. Rather than using year-end pricing, companies are now required to use the 12-month average of the first of month prices for oil and gas to estimate proved reserves. This change in methodology from 2008 resulted in a higher oil price and a lower gas price in effect for determining year-end proved reserves for 2009. As a result, we recognized positive pricing revisions in our oil-weighted Rocky Mountain and Permian regions that offset the negative price revisions we recognized in the natural gas weighted Mid-Continent, ArkLaTex, and South Texas & Gulf Coast regions. Under the previous methodology of using year-end pricing for the determination of proved reserves, we would have had a four percent increase in proved reserves to approximately 897 BCFE.

Prior to and subsequent to year-end, we entered into several transactions to divest non-strategic properties across our company. Proved reserves associated with these properties are estimated to be approximately 71 BCFE and primarily relate to the previously announced Rocky Mountain oil property divestiture. Part of this divestiture package closed in mid-February 2010 and we expect the balance to close by the end of the first quarter of 2010.

Impairment of Proved Properties. We recognized pre-tax non-cash impairments of proved properties in the amount of $174.8 million in 2009 compared with $302.2 million of proved property impairments in 2008. A significant decrease in commodity prices, including differentials, during the first quarter of 2009 caused the majority of the non-cash impairment. The largest portion of the impairment in 2009 was $97.3 million related to assets located in the Mid-Continent region which were significantly impacted by both low natural gas prices and wider than normal differentials at the end of the first quarter. The ArkLaTex region was impacted by a $20.4 million impairment related to downward pricing and engineering revisions. We incurred a $14.0 million impairment of proved properties related to the write-down of certain assets located in the Gulf of Mexico for which we are relinquishing our ownership interests to satisfy our abandonment obligations.

Abandonment and Impairment of Unproved Properties. During the year, we abandoned or impaired $45.4 million related to unproved properties. The largest specific components of the 2009 impairment and abandonment related to the Floyd Shale acreage located in Mississippi and acreage in Oklahoma. The remaining write-offs were related to acreage we believe we will not keep based on our current capital allocation plans or related to acreage that we do not believe will be prospective.

Divestiture of Non-Strategic Properties. In 2009 we undertook an effort to sell a number of non-strategic properties in order to optimize our portfolio. The objective of these divestitures is to dispose of properties with limited future drilling potential while generating cash that can be used in the testing and development of our resource plays. During 2009 we sold roughly 44.2 BCFE of reserves, the vast majority of which related to our coalbed methane program in Hanging Woman Basin. We received $39.9 million in proceeds from the sales we closed in 2009. Subsequent to year end, we closed on a portion of our previously disclosed sale of non-strategic oil and gas properties in the Rocky Mountain region. The Wyoming sub-package was sold to Legacy Reserves Operating LP. The cash received at closing was $118.7 million before commission costs. The final sales price is subject to normal post-closing adjustments and is expected to be finalized by the end of second quarter of 2010. Additionally, subsequent to year-end, we also entered into agreements to sell the

remaining non-core properties from our Rocky Mountain divestiture package in North Dakota for $137 million to Sequel Energy Partners LP, as well as some other minor properties for approximately $6 million. We expect these divestitures to close by the end of the first quarter of 2010. In total, these divestitures represent 71 BCFE of proved reserves.

Outlook for 2010

The general economic outlook for the country has improved compared to this time a year ago. We successfully weathered a rough 2009, and in the process advanced a number of potential resource plays and improved our financial condition.

As we enter 2010, our company is well positioned both financially and operationally. Early in 2009, we extended the maturity of our revolving credit facility and subsequently reduced outstanding borrowings on that facility during the year. As of February 16, 2010, we had $467 million available to us under the revolving credit facility. We have no debt maturities until 2012. Additionally, we believe that access to the capital markets has improved significantly since last year and that we could access capital through the public markets, if necessary. From an operational standpoint, we believe 2010 has the potential to be very promising for our company. We will be building upon our successful testing programs from 2009. We have moved the Eagle Ford shale program closer to development mode, and it will receive the largest portion of our capital budget this year. We will also be allocating more capital toward oil and rich natural gas projects, given their higher returns in the current environment. Specifically, we will be drilling more Wolfberry tight oil and Bakken/Three Forks wells in the Permian and Rocky Mountain regions, respectively. In the Haynesville shale, we have begun our horizontal drilling program. We continue to monitor service costs as the recent uptick in industry activity may pressure rates for the drilling and completion of wells higher than the levels we saw in 2009. We intend to fund these projects with our current year operating cash flows and proceeds from our previously announced non-core divestitures.

Assets

As of December 31, 2009, we had estimated proved reserves of 53.8 MMBbl of oil and 449.5 Bcf of natural gas. The 12-month average prices in effect on December 31, 2009, used to estimate proved reserves were $61.18 per barrel of oil and $3.87 per MMBtu of gas, which represent a 37 percent increase and 32 percent decrease, respectively, from prices used to estimate proved reserves as of December 31, 2008. On an equivalent basis, our proved reserves were 772.2 BCFE as of December 31, 2009, a decrease of 11 percent from 865.5 BCFE at the end of the prior year. On an equivalent basis, 82 percent of our proved reserves were classified as proved developed as of year-end. Total proved oil and gas reserves had a PV-10 value of $1.3 billion and a standardized measure value of $1.0 billion including the effect of income taxes. A reconciliation between these two amounts is shown under the Reserves section in Part I, Items 1 and 2 of this report. During 2009 our average daily production was 194.8 MMcf of gas and 17.3 MBbl of oil, for an average equivalent production rate of 298.8 MMCFE per day, which was down slightly compared with 313.1 MMCFE per day for 2008. Adjusting for production from properties sold as part of our active divestiture efforts over the last two years, production from retained properties has remained essentially flat from 285.6 MMCFE per day in 2008 to 284.7 MMCFE per day in 2009.

In 2009 we incurred costs of $419.0 million for drilling and exploration activities and acquisitions. This was 51 percent lower than the $857.7 million incurred in 2008. During 2009 we incurred exploration costs of $154.1 million compared to $92.2 million in 2008. We incurred development costs of $223.1 million in 2009, which was 62 percent lower than the $587.6 million in 2008. The decrease in development dollars and increase in exploration dollars reflects our decision to not invest capital in development projects in a low commodity price environment, particularly while service costs were declining. Moreover we ramped up our exploration efforts to accelerate our understanding of our emerging resource plays, particularly in the Eagle Ford shale, in order to put ourselves in a positive position once industry conditions improved. In 2009 we invested a total of $41.7 million on undeveloped leasehold compared to $83.1 million in 2008. The majority of our 2009 leasing activity targeted emerging resource plays in our South Texas & Gulf Coast and Mid-Continent regions. We spent approximately $126.4 million in 2008 on undeveloped leasehold, including leasehold acquired as part of producing property

acquisitions, targeting the Cotton Valley and Bakken formations in the ArkLaTex and Rocky Mountain regions, respectively. In 2009, we did not make any meaningful acquisitions.

Our operations are currently concentrated in five core operating areas in the United States. The following table summarizes the production, proved reserves, and PV-10 value of our core operating areas as of December 31, 2009.

	ArkLaTex		Mid- Continent			South Texas & Gulf Coast			Permian		Rocky Mountain		Total(1) (2)
2009 Proved Reserves
Oil (MMBbl)		0.4		1.1			1.4			14.2		36.7		53.8
Gas (Bcf)		117.8		216.7			44.9			30.1		40.0		449.5
Equivalents (BCFE)		120.0		223.5			53.2			115.2		260.3		772.2
Relative percentage		15%		29%			7%			15%		34%		100%
Proved Developed %		65%		83%			53%			83%		93%		82%

PV-10 Values (in millions)
Proved Developed	$	92.1	$	266.3		$	50.5		$	295.5	$	548.7	$	1,253.1
Proved Undeveloped (3)		0.1		(7.4	)		(2.0	)		34.9		5.4		31.0
Total Proved	$	92.2	$	258.9		$	48.5		$	330.4	$	554.1	$	1,284.1
Relative percentage		7%		20%			4%			26%		43%		100%

2009 Production
Oil (MMBbl)		0.1		0.3			0.4			1.8		3.7		6.3
Gas (Bcf)		14.2		34.4			7.2			4.1		11.2		71.1
Equivalent (BCFE)		14.9		36.0			9.7			15.2		33.3		109.1

Avg. Daily Equivalents (MMCFE/d)		40.8		98.7			26.6			41.5		91.2		298.8
Relative percentage		14%		33%			9%			14%		30%		100%

(1)	Totals may not add due to rounding.

(2)	Included in the total are approximately 71 BCFE related to non-core properties that we have either divested or entered into agreements to divest subsequent to December 31, 2009.

(3)	St. Mary will record proved undeveloped locations with a negative PV-10 value if we have intent to drill the well provided it generates positive net undiscounted cash flow and meets our economic criteria based on our corporate price call.

ArkLaTex Region. St. Mary’s operations in the ArkLaTex region are managed from our office in Shreveport, Louisiana. The ArkLaTex region was our first operating office, originating from an acquisition in 1992. For years the activities of this region focused on the Cotton Valley, James Lime, and Travis Peak formations in the region. In 2008 the Haynesville shale emerged as the leading potential resource play in East Texas and North Louisiana.

The ArkLaTex region incurred costs of $65.7 million in 2009 for exploration, development, and acquisition activities. This amount is 70 percent lower than the $218.4 million spent in 2008, which included $60.3 million in acquisitions targeting the Cotton Valley formation in East Texas. Significantly less money was spent on development and exploration activity in 2009 compared to 2008. With the emergence of the Haynesville shale late in 2008 and into 2009, our operating partner activity targeting the Cotton Valley and James Lime formations declined significantly as they focused on testing and developing their Haynesville shale properties. We participated in a number of partner-operated wells that focused on the Haynesville shale. Additionally, we elected to defer most of our operated horizontal Haynesville drilling until we could acquire seismic data that would help mitigate risk for larger parts of our acreage. Our 2009 operated activity in the ArkLaTex region was primarily focused on drilling wells that preserve acreage. The region’s 2009 production decreased 19 percent to 14.9 BCFE as a result of the lower levels of activity described above. Our 2009 year-end proved reserves were 120.0 BCFE, which is 29 percent lower than the 2008 year-end proved reserves of 170.0 BCFE. The decrease in

proved reserves is primarily the result of 14.9 BCFE of production and 48.0 BCFE of negative pricing and engineering revisions. At year-end 2009 we have no proved reserves booked for our Haynesville potential related to our acreage in Shelby and San Augustine Counties in East Texas.

The Elm Grove Field is the highest value field in the ArkLaTex region at year-end 2009. We own interests in approximately 500 producing wells in the field and believe many of those wells have future uphole recompletion potential. Our working interest in the field is as high as 36 percent, although it varies greatly across the field. Generally, our working interest increases as one moves south in the field. The primary zones of interest in this field have historically been the Cotton Valley and Hosston. The vast majority of the value and proved reserves in this field relate to those zones. Over the past year, our operating partner has focused its drilling efforts almost exclusively in the Haynesville shale on acreage in the field where we have no working interest. As a result, we have very little PV-10 value or proved reserve volumes attributable to the Haynesville shale at the end of 2009 at Elm Grove field.

Our plans for 2010 in the ArkLaTex region are based almost entirely on testing and developing the Haynesville shale on our operated acreage. We have approximately 41,000 net acres across the region with potential for the Haynesville shale, of which 31,000 is located in Shelby and San Augustine Counties in East Texas. Roughly 70 percent of our Haynesville spending will be operated by us and will be focused on our acreage in these counties. We plan to drill seven horizontal wells targeting the Haynesville shale in 2010. We will also participate in a number of wells with operating partners in both northern Louisiana and East Texas that target the Haynesville interval. We expect that we will invest a minimal amount of capital this year on the drilling of James Lime and Cotton Valley wells, although we will have some leasehold and seismic expenditures related to those programs in 2010. In recent months, the industry has begun to test the Bossier shale, which is above the Haynesville shale. As information emerges about this interval, we could choose to test this formation in 2010. We believe a large portion of our acreage position in East Texas is also prospective for the Bossier shale.

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. 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. The Mid-Continent region also oversees our Marcellus shale activity in north central Pennsylvania.

In 2009 we incurred costs of $106.8 million in the Mid-Continent region for exploration, development, and acquisition activity, which is 34 percent less than the $162.0 million deployed in 2008. Approximately $97 million was deployed in exploration and development activities in 2009, with the remainder being spent on leasing activities. The 2009 activity for the region focused on the continued development of our horizontal Woodford shale program in the Arkoma Basin and included the successful completion of two pilot programs to test the effect of near simultaneous fracture stimulation on increased density drilling. In the Anadarko Basin, we maintained a consistent level of operated activity targeting the Deep Springer formation throughout the year. We also participated in a largely non-operated program targeting the stacked washes in western Oklahoma. Lastly, we drilled and completed our first initial tests in our Marcellus shale program during the second half of 2009. Mid-Continent production in 2009 was 36.0 BCFE, an increase of 9 percent from the 33.0 BCFE produced in 2008. Proved reserves at the end of 2009 were 223.5 BCFE, a decrease of five percent from the 234.4 BCFE report for the prior year. The decrease in proved reserves was due in large part to the low gas price in effect at year end which resulted in downward pricing revisions of roughly 17 BCFE for some previously booked proved reserves. The low gas price also resulted in no new proved undeveloped reserves being added in the region at December 31, 2009.

The Centrahoma Field in the Arkoma Basin is the highest value field in the Mid-Continent region. At year-end, we have nearly 160 producing wells in the field. Over half of those wells were completed in the Woodford shale and the majority of those were drilled horizontally. The Woodford shale is the primary contributor to proved reserve volumes and PV-10 value at the Centrahoma Field. We believe there is additional drilling potential in the Woodford shale as well as uphole development in the Cromwell and Wapanucka formations.

The largest operated portion of the Mid-Continent region’s budget for 2010 relates to our emerging program targeting the Marcellus shale in north central Pennsylvania. We currently have roughly 42,000 net acres leased or optioned in the Marcellus shale. Four operated horizontal wells are planned for the year and we expect to begin drilling late in the second quarter of 2010. Additionally, we are currently in the process of constructing a gathering system through a large portion of our acreage position that will connect the first two wells we drilled in 2009 to sales as well as service future development. Our Marcellus program for 2010 also includes amounts for leasehold, facilities, and seismic costs. In the horizontal Woodford, our program for 2010 is primarily designed to preserve core acreage. Six operated horizontal wells are currently planned, and we will participate in a handful of wells that will be operated by others. In the Anadarko Basin, we have four wells planned in the successful Deep Springer program our regional team has run for the past several years. Four operated horizontal wells are planned for the horizontal Granite Wash play that is emerging in western Oklahoma. Our first horizontal Granite Wash well in this part of the play commenced drilling in December of 2009 and is still drilling as of the date of this report.

South Texas & 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 land yielded $3.6 million of oil and gas royalty revenue in 2009. Our presence expanded along the Gulf Coast as a result of the acquisition of King Ranch Energy, Inc. in 1999. In 2007, we made two acquisitions in the Maverick Basin in South Texas that targeted Olmos shallow gas assets in South Texas and provided an entry into this multi-pay basin. During 2009, one of the other zones of interest, the Eagle Ford shale, was successfully tested by St. Mary and a competitor. Today, the Eagle Ford shale is one of the most promising shale plays in North America. The focus of our Houston office has steadily shifted over the last couple of years away from projects along the Gulf Coast and in the Gulf of Mexico toward programs onshore that allow for multiple years of drilling inventory.

Our capital expenditures for exploration, development, and acquisition activity in the South Texas & Gulf Coast region decreased slightly from $120.9 million in 2008 to $115.1 million in 2009. Nearly all of the capital deployed in the South Texas & Gulf Coast region in 2009 targeted formations in south western Texas, namely the Eagle Ford and Pearsall shales. We worked early in the year to increase our leasehold position in the area. Additionally, we continued to participate in a joint venture that allowed us to earn acreage by carrying a partner through completion in a series of wells. In mid-2009, we began operating on acreage where we had very high working interests, in many cases a 100 percent. The encouraging results from our earlier tests led to an increase in the number of wells drilled for 2009. To date, the results on our operated acreage have been very encouraging. On large parts of our acreage, we have seen rich-gas and condensate in the production stream which enhances the economics of these gas wells. We did not make any meaningful investments in properties along the Gulf Coast or in the Gulf of Mexico during the year. Our last operated platform in the Gulf of Mexico was largely remediated and abandoned in 2009 after being damaged by Hurricane Ike in 2008.

Production for the South Texas & Gulf Coast region in 2009 was 9.7 BCFE, a decrease of 32 percent from the 14.3 BCFE produced in 2008. The largest contributor to the decline year over year was the result of our sale of our interest in the Judge Digby Field in southern Louisiana at the end of 2008. Excluding the impact of this divestiture, production declined approximately one percent year over year. Proved reserves at the end of 2009 were 53.2 BCFE, an increase of 21 percent from the 43.8 BCFE reported in the prior year. The increase in proved reserves reflects drilling additions of 39.0 BCFE related entirely to our program in the Eagle Ford shale and were offset by downward price revisions related to our Olmos gas program. On our operated acreage targeting the Eagle Ford shale, we had seven proved developed wells which were producing at year-end. This program is at an early stage of its development and accordingly at December 31, 2009, we are booking only parallel offset locations to our producing wells as proved undeveloped locations. The result is a total of 14 proved undeveloped locations being booked as of year-end at a total of 24.6 BCFE. Our operated Eagle Ford program is the most significant asset in the South Texas & Gulf Coast region.

Our plans for 2010 in the South Texas & Gulf Coast region are focused exclusively on the Eagle Ford shale. As of year-end, we have 250,000 net acres leased or optioned, which is an increase from our previously reported total of 225,000 net acres. We operate roughly 168,000 of those net acres, most of which is at 100 percent working interest, with the balance of the acreage being located on joint venture acreage with an industry

partner. We plan to drill 34 horizontal wells on our operated acreage in 2010. Part of our drilling program will be aimed at further delineating the play in order to make infrastructure commitments later this year. We currently are able to market all of our production and expect to do so in the future by working with midstream partners to ensure we have adequate takeaway and processing capacity to meet our needs. We will also be conducting a series of tests to help determine the ultimate spacing for the reservoir. Our operating partner plans to operate two to three rigs during 2010 on our joint venture acreage where we have a net working interest of 25 percent.

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 major acquisition of oil properties that targeted the Wolfberry tight oil play. To manage the significant increase in operated properties associated with the Sweetie Peck acquisition, we opened a regional office in Midland, Texas in February 2007.

We incurred costs of $76.5 million in the region in 2009 compared to $163.2 million in 2008. This decrease in capital investment reflects the significant slowdown in our drilling activity during the first half of the year in response to the low oil prices being realized late in 2008 and early in 2009. The majority of this capital was deployed to develop projects in the Wolfberry tight oil play, which targets the stacked carbonate Wolfcamp and Spraberry formations found in the basin. We also tested other exploration concepts in the Permian during the year. Production in the region increased 9 percent over the prior year, from 13.8 BCFE in 2008 to 15.2 BCFE in 2009. Proved reserves as of the end of 2009 were 115.2 BCFE, which is a decrease of 26 percent from 2008 year-end reserves of 155.9 BCFE. The decrease in our estimate of proved reserves relate to engineering revisions on proved producing properties in our Wolfberry tight oil program. Well performance data collected during 2009 from our Sweetie Peck and Halff East assets which target the Wolfberry indicate that these assets are underperforming our year-end 2008 decline forecasts. Accordingly, we have removed 37 BCFE from proved reserves in the Permian region, primarily related to the Wolfberry tight oil program. We believe that a significant portion of these reserves, while not meeting the criteria to be booked as proved reserves at year-end, are likely to eventually be produced.

As of the end of December 2009, the Sweetie Peck assets in the Permian Basin collectively were the highest value entity in the region. Sweetie Peck field had 182 producing wells at year-end. We have slightly over 20 proved undeveloped locations booked at Sweetie Peck at year-end. We also believe there are a meaningful number of unbooked future drilling locations that we will be able to pursue in future years.

The largest drilling program planned for the Permian region in 2010 is in our Sweetie Peck tight oil assets where we plan to drill 32 operated wells this year. Most of the development will take place on 80- and 40-acre spaced locations. Despite the downward Wolfberry engineering revisions in our proved reserve estimates referred to above, these projects continue to meet our economic standards for drilling, albeit at lower proved reserve volumes. We will also continue to work on an exploratory program that began in 2009 and we plan to conduct a modest drilling program in 2010, primarily using vertical wells.

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 2001 and early 2003 with significant property acquisitions from Choctaw, Burlington Resources, and Flying J. In recent years, we have been divesting of non-core properties in the Rocky Mountain region in an effort to focus our human and investment capital on the most impactful plays in that region.

We incurred costs of $51.2 million in 2009 for exploration, development, and acquisitions in the Rocky Mountain region, compared to $190.3 million in 2008. Our 2009 budget in the Rocky Mountain region reflected the low oil prices and the wide price differentials we experienced at the end of 2008. For much of 2009, we did not have any operated rigs running in the region. Our capital investments were primarily focused on the Bakken and Three Forks formations and were heavily weighted toward the back half of the year. Proved reserves for the Rocky Mountain region were 260.3 BCFE at year-end compared with 261.4 BCFE as of the end of 2008. The slight decrease in proved reserves is the result of selling 40.3 BCFE of proved reserves in the region during the

year, most of which related to the sale of non-strategic coalbed methane project at Hanging Woman Basin, offset by net positive price and engineering revisions of 50.0 BCFE. Production in the Rocky Mountain region for 2009 was 33.3 BCFE. Total regional production was down five percent from 34.9 BCFE in 2008. Adjusting for the effect of the divestitures, production in the region would have declined 1.3 BCFE, or four percent, year over year.

The Elm Coulee Field is the highest value field in the region at year-end 2009. The reserves in this field are predominately oil, and the Bakken is the formation of primary interest. The field is largely developed with only a handful of remaining drilling locations identified as proved undeveloped.

The Bakken and Three Forks formations in the Williston Basin will be our primary focus in 2010. We plan to drill 17 horizontal wells targeting these formations in 2010. The majority will be located in our Bear Den asset program in McKenzie and Williams counties in North Dakota where we have roughly 16,000 net acres. Additionally, we have built a 70,000 net acre position with potential for the Bakken and Three Forks in McKenzie, Williams, and Divide counties that we will test during 2010. We are currently drilling a test well in Wyoming targeting the Niobrara formation as part of our ongoing exploration effort. We plan to evaluate our results, as well as those of nearby competitors, during 2010.

Reserves

In December 2008, the SEC announced that it had approved revisions designed to modernize oil and gas reporting requirements. A key revision to the rules pertains to commodity prices. The economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price as opposed to a year-end price in estimating reserves. The prices used in the calculation of proved reserve estimates as of December 31, 2009, were $61.18 per Bbl and $3.87 per MMBTU for oil and natural gas, respectively. These prices were 37 percent higher and 32 percent lower, respectively, than the year-end prices used to estimate 2008 proved reserves, and 23 percent and 33 percent lower, respectively, than prices that would have been used the SEC’s previous methodology. If the SEC’s prior methodology had been used for year-end 2009 proved reserves, the prices used would have been $79.36 per Bbl and $5.79 per MMBTU.

Additional revisions to the SEC rules provide for the use of new technology to estimate proved reserves. Additionally, the definition of proved oil and gas reserves has been expanded to include non-traditional resources, which focuses on the marketable product rather than the method of extraction. In addition to these regulatory changes, in 2009 we began recording estimates of proved reserve volumes for properties that we believe are reasonably certain to generate positive net cash flows on an undiscounted basis, that we have the intent to drill, and which meet our internal economic criteria for drilling. Previously, we booked proved reserve volumes if the properties showed a positive PV-10 value, we had the intent to drill, and the wells met our economic criteria.

The table below 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, 2009. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to review internal engineering estimates for at least 80 percent of the PV-10 value of our proved reserves in 2009, 2008, and 2007, excluding our coalbed methane properties. For 2008 and 2007, Netherland, Sewell and Associates, Inc. (“NSAI”) prepared the reserve information for our coalbed methane 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 divested of all Hanging Woman Basin properties in the fourth quarter of 2009.

We emphasize that reserve estimates are inherently imprecise and that estimates of all 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 new information becomes available in the future. 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. The following table should be read 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 SEC, since the beginning of the last fiscal year.

The ability to replace produced reserves is important to the sustainability of all exploration and production companies. Our 2009 corporate ratio of reserves replaced through drilling activity was 100 percent. There were no material acquisitions made in 2009. Four out of our five regions did not replace their respective regional production for the year. The one exception, our South Texas & Gulf Coast region, replaced 400 percent of its production for 2009 due to the strong results in the Eagle Ford shale. This metric is calculated using information from the Oil and Gas Reserve Quantities section of Note 16 – Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report. The numerator consists of the sum of discoveries and extensions and infill reserves in an existing proved field, which is then divided by production. We believe the concept of reserve replacement as described above, as well as permutations which may include other captions of the Oil and Gas Reserve Quantities section of Note 16 – Disclosures about Oil and Gas Producing Activities of Part IV, Item 15 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration business. For additional information about reserve replacement metrics, see the reserve replacement terms in the Glossary section of this report.

	As of December 31,
Reserves data:	2009		2008		2007
Proved developed
Oil (MMBbl)		48.1		47.1		68.3
Gas (Bcf)		342.0		433.2		426.6
BCFE		630.3		715.8		836.3

Proved undeveloped
Oil (MMBbl)		5.7		4.3		10.5
Gas (Bcf)		107.5		124.2		186.9
BCFE		141.9		149.7		250.2

Total Proved
Oil (MMBbl)		53.8		51.4		78.8
Gas (Bcf)		449.5		557.4		613.5
BCFE		772.2		865.5		1,086.5

Proved developed reserves %		82%		83%		77%
Proved undeveloped reserves %		18%		17%		23%

Reserve Value info (in thousands)
Proved developed PV-10	$	1,253,056	$	1,214,380	$	3,300,213
Proved undeveloped PV-10		31,029		51,005		560,974
Total proved PV-10 value	$	1,284,085	$	1,265,385	$	3,861,187
Standardized measure of discounted future cash flows		1,015,967		1,059,069		2,706,914

Reserve replacement – drilling and acquisitions, excluding revisions		100%		174%		211%
All in – including sales of reserves		14%		(93)%		248%
All in – excluding sales of reserves		55%		(39)%		249%
Reserve life (years) (1)		7.1		7.6		10.1

(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 (GAAP) to the PV-10 value (Non-GAAP). 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,
	2009			2008			2007
	(In thousands)
Standardized measure of discounted future net cash flows	$	1,015,967		$	1,059,069		$	2,706,914
Add: 10 percent annual discount, net of income taxes		732,997			724,840			2,321,983
Add: future income taxes		515,953			419,544			2,316,637

Undiscounted future net cash flows	$	2,264,917		$	2,203,453		$	7,345,534
Less: 10 percent annual discount without tax effect		(980,832	)		(938,068	)		(3,484,347	)

PV-10 value	$	1,284,085		$	1,265,385		$	3,861,187

Proved Undeveloped Reserves

As of December 31, 2009, we had 141.9 BCFE of proved undeveloped reserves, which is a decrease of 7.8 BCFE or five percent compared with 149.7 of proved undeveloped reserves at December 31, 2008. A negative revision of 19.1 BCFE was due to lower pricing in the gas weighted regions, particularly in the ArkLaTex region where 16.4 BCFE of mostly Cotton Valley proved undeveloped reserves became uneconomic using the new 12-month average pricing. We added 43.6 BCFE of proved undeveloped reserves through our drilling program, 34.3 BCFE of which were extensions and discoveries, primarily in the Eagle Ford shale, as well as an additional 9.3 BCFE of infill proved undeveloped reserves that were mostly concentrated in the Cotton Valley and Bakken. During the year, 7.0 BCFE were sold in divestitures, primarily in our Rocky Mountain region. We invested approximately $57 million to convert 18.6 BCFE of proved undeveloped reserves in 2009, which amounted to approximately $57 million in capital expenditures, mainly in the Wolfberry properties in the Permian region and the Woodford shale in the Mid-Continent region. We had a negative revision of 6.7 BCFE due to downward performance revisions in our Wolfberry properties in the Permian region and 3.6 BCFE of proved undeveloped reserves were removed as a result of the five year limitation on the number of years that a proved undeveloped reserve may remain on the books without being developed. As of December 31, 2009, we have no material proved undeveloped reserves that have been on the books in excess of five years. As of December 31, 2009, estimated future development costs relating to proved undeveloped reserves are projected to be approximately $49 million, $129 million, and $56 million in 2010, 2011, and 2012, respectively.

Alternate Pricing Scenario

The following table presents our December 31, 2009, reserves data and PV-10 value based on prices that would have been used under the SEC’s previous methodology of estimating reserves using year-end pricing. If the SEC’s prior methodology had been used for year-end 2009 proved reserves, the prices used would have been $79.36 per barrel and $5.79 per MMBTU. All cost assumptions remain the same.

	As of December 31, 2009
Reserves data:
Proved developed
Oil (MMBbl)		53.0
Gas (Bcf)		382.9
BCFE		700.8
Proved undeveloped
Oil (MMBbl)		8.8
Gas (Bcf)		143.9
BCFE		196.4
Total Proved
Oil (MMBbl)		61.8
Gas (Bcf)		526.8
BCFE		897.2

Proved developed reserves		78%
Proved undeveloped reserves		22%

Reserve Value info (in thousands)
Proved developed PV-10	$	2,207,906
Proved undeveloped PV-10		235,805
Total proved PV-10 value	$	2,443,711

Internal Controls Over Reserves Estimate

St. Mary’s policies regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and values in compliance with the SEC’s regulations. Responsibility for compliance in reserves bookings is delegated to our reservoir engineering group, which is led by our Vice President of Engineering and Evaluation.

Technical reviews are performed throughout the year by regional engineering and geologic staff who evaluate all available geological and engineering data. This data in conjunction with economic data and ownership information is used in making a determination of proved reserve quantities. The reserve process is overseen by Dennis A. Zubieta, Vice President - Engineering and Evaluation for St. Mary. Mr. Zubieta joined St. Mary in June 2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company (formerly known as Meridian Oil, Inc) from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana Tech in May 1988. The regional technical staff does not report directly to Mr. Zubieta; they report to either regional technical managers or directly to the regional manager in their respective region. This is intended to promote objective and independent analysis within the reserves process.

Third-party Reserves Audit

An independent audit is performed by Ryder Scott using their own engineering assumptions and economic data provided by St. Mary. A minimum of 80 percent of the total calculated proved reserve PV-10 value is audited by Ryder Scott. In aggregate, the reserve values of the audited properties are required to be within 10 percent of St. Mary’s valuations on both a corporate and regional level. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing the reserves audit is a Senior Vice President and holds a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and is a registered Professional Engineer in the States of Colorado and Utah. He is also a member of the Society of Petroleum Engineers. The Ryder Scott report is included as Exhibit 99.1.

In addition to a third party audit, our reserves are reviewed by senior management and the Audit Committee of St. Mary’s Board of Directors. Senior management, which includes the President and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, and the Executive Vice President and Chief Financial Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with Ryder Scott’s audit letter. They may also meet with the key representative from Ryder Scott to discuss their process and findings.

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,
	2009		2008		2007

Net production
Oil (MMBbl)		6.3		6.6		6.9
Gas (Bcf)		71.1		74.9		66.1
BCFE		109.1		114.6		107.5
Average net daily production
Oil (MBbl)		17.3		18.1		18.9
Gas (MMcf)		194.8		204.7		181.0
MMCFE		298.8		313.1		294.5
Average realized sales price, excluding the effects of hedging
Oil (per Bbl)	$	54.40	$	92.99	$	67.56
Gas (per Mcf)	$	3.82	$	8.60	$	6.74
Per MCFE	$	5.65	$	10.99	$	8.48
Average realized sales price, including the effects of hedging
Oil (per Bbl)	$	56.74	$	75.59	$	62.60
Gas (per Mcf)	$	5.59	$	8.79	$	7.63
Per MCFE	$	6.94	$	10.11	$	8.71
Production costs per MCFE
Lease operating expense	$	1.33	$	1.46	$	1.31
Transportation expense	$	0.19	$	0.19	$	0.14
Production taxes	$	0.37	$	0.71	$	0.58

Productive Wells

As of December 31, 2009, St. Mary had working interests in 2,046 gross (1,000 net) productive oil wells and 3,154 gross (1,042 net) productive gas wells. Productive wells are either producing wells or wells capable of commercial production although currently shut-in. Multiple 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 on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

Subsequent to year end, we have closed or plan to close on several divestitures of non-core properties, primarily in the Rocky Mountain region. Upon closing of these transactions, we will have divested 425 gross (302 net) productive oil wells and 305 gross (93 net) productive gas wells.

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,
	2009		2008		2007
	Gross	Net	Gross	Net	Gross	Net
Development:
Oil	103	29.64	221	81.46	164	77.91
Gas	74	18.15	559	205.18	518	204.62
Non-productive	3	1.29	25	13.70	30	13.18
	180	49.08	805	300.34	712	295.71
Exploratory:
Oil	2	0.42	2	0.40	3	1.92
Gas	18	9.05	10	2.75	9	4.01
Non-productive	5	2.88	1	0.76	5	2.58
	25	12.35	13	3.91	17	8.51

Farmout or non-consent	3	-	7	-	1	-
Total(1)	208	61.43	825	304.25	730	304.22

(1)	Does not include one and two gross wells completed on St. Mary’s fee lands during 2009 and 2008, respectively, in which we only have royalty interests.

A productive well is an exploratory, development or extension well that is not a dry well. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

As defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is part of a development project, which is defined as the means by which petroleum resources are brought to the status of economically producible. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

In addition to the wells drilled and completed in 2009 included in the table above, as of February 16, 2010, St. Mary is currently participating in the drilling of 25 gross wells, all of which are located in the continental United States. We operate nine of these wells with the remaining 16 wells being operated by our partners. On a net basis, we are drilling 7.6 net operated wells and are participating in 2.0 net non-operated

wells. With respect to completion activity, there are currently 19 wells in which we have an interest that are being completed. We operate 13 of those on a gross basis (10.2 net) and is participating with industry partners in 6 gross (0.3 net) completion activities. The vast majority, if not all, of these operations relate to the drilling of wells for primary production.

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, 2009. 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	1,394	163	147	60	1,541	223
Colorado	-	-	940	614	940	614
Kansas	-	-	2,240	560	2,240	560
Louisiana	101,516	37,483	25,120	4,905	126,636	42,388
Mississippi	2,360	429	100,963	42,265	103,323	42,694
Montana	59,806	40,389	343,612	236,463	403,418	276,852
Nevada	-	-	197,945	197,945	197,945	197,945
New Mexico	2,507	1,815	1,240	1,022	3,747	2,837
North Dakota	127,497	87,654	216,779	121,214	344,276	208,868
Oklahoma	256,577	81,184	70,483	32,917	327,060	114,101
Pennsylvania	-	-	30,462	27,440	30,462	27,440
Texas	221,795	106,072	544,683	260,955	766,478	367,027
Utah	-	-	2,568	561	2,568	561
Wyoming	88,761	52,814	285,700	143,183	374,461	195,997
	862,213	408,003	1,822,882	1,070,104	2,685,095	1,478,107

Louisiana Fee Properties	10,499	10,499	14,415	14,415	24,914	24,914
Louisiana Mineral Servitudes	7,426	4,217	4,769	4,407	12,195	8,624
	17,925	14,716	19,184	18,822	37,109	33,538
Total (3)	880,138	422,719	1,842,066	1,088,926	2,722,204	1,511,645

(1)

Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage 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 reserves.

(3)

Subsequent to December 31, 2009, St. Mary divested certain non-core properties, which included leases covering approximately 26,100 and 25,100 developed gross and net acres, respectively, and 18,600 and 15,000 undeveloped gross and net acres, respectively. Additionally, we entered into agreements to divest certain non-core properties, which included leases covering approximately 80,200 and 44,500 developed gross and net acres, respectively, and 63,700 and 31,000 undeveloped gross and net acres, respectively.

Delivery Commitments

As of December 31, 2009, there were no material delivery commitments. Subsequent to year end we are subject to a certain gathering through-put contract that requires a minimum volume delivery of 15 Bcf by January 1, 2013. We will be required to pay $0.18 Mcf for any shortfall in delivering the minimum volume of 15 Bcf. At the current time, the company does not have proved developed reserves to offset this contractual liability, but fully intends to develop proved undeveloped reserves that will exceed the through-put commitment.

Major Customers

During 2009, sales to Teppco Crude Oil LLC individually accounted for 12 percent of our total oil and gas production revenue. During 2008 and 2007, no customer individually accounted for ten percent or more of our total oil and gas production revenue.

Employees and Office Space

As of February 16, 2010, we had 550 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. As of December 31, 2009, we lease approximately 79,000 square feet of office space in Denver, Colorado for our executive and administrative offices, of which approximately 9,000 square feet is subleased. We lease approximately 22,000 square feet of office space in Tulsa, Oklahoma; approximately 22,000 square feet in Shreveport, Louisiana; approximately 26,000 square feet in Houston, Texas; approximately 17,000 square feet in Midland, Texas; approximately 36,000 square feet in Billings, Montana; approximately 6,000 square feet in Williston, North Dakota; 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, increasing summertime demand for electricity is beginning to place increased demand on storage volumes. Crude oil and the demand for heating oil are also impacted by generally higher prices in the winter and the summer driving season – 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, particularly with respect to capturing prospective oil and natural gas properties and oil and gas reserves. We believe 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 the location of our leasehold acreage, our exploration, drilling, and production expertise and available technologies, and the experience and knowledge of our management and industry partners enable us to compete effectively in our core operating and resource play areas. Notwithstanding our talents and assets, we still face stiff competition from a substantial number of major and independent oil and gas companies who 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 and services necessary for the drilling and completion of wells. Consequently, we may face shortages

or delays in securing these services from time to time. We are seeing signs of tightening rig availability, although it is quite specific by region. The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. Finally, we also compete for people. Throughout the industry, the need to attract and retain 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 must compete effectively in this market in order to be successful.

Government Regulations

Our business is extensively regulated by numerous federal, state, and local laws and government regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations increase our cost of doing business and, consequently, affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for and production of crude oil and natural gas, including laws and regulations requiring permits for the drilling of wells, imposing bonding requirements in order to drill or operate wells, and governing the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, the spacing of wells, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (BLM) or the Minerals Management Service (MMS). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM or MMS before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM or the MMS, as applicable, may require our operations on federal leases to be suspended or terminated.

In January 2010, the BLM announced that it will be issuing a new draft oil and gas leasing policy that will require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. As the policy has not yet been released, we are not able to determine the impact these potential leasing policy changes may have on our business.

Our sales of natural gas are affected by the availability, terms, and cost of natural gas pipeline transportation. The Federal Energy Regulatory Commission (FERC) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce. The FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for natural gas production. In addition, the less stringent regulatory approach recently pursued by the FERC and the U.S. Congress may not continue indefinitely.

Environmental, Health and Safety Regulations. Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety. Environmental 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, govern the handling and disposal of waste material, 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 these laws and regulations. Further, possible regulations related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas. See “Risk Factors – Risks Related to Our Business - Possible regulations related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas.”

Hydraulic fracturing is a common process in our industry of creating artificial cracks, or fractures, in deep underground rock formations through the pressurized injection of water, sand and other additives to enable oil or natural gas to move more easily through the rock pores to a production well. This process is often necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale rock formations. We routinely utilize hydraulic fracturing techniques in many of our reservoirs, and our shale resource programs utilize or contemplate the utilization of hydraulic fracturing. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. Legislative and regulatory efforts at the federal level and in some states have been made which could result in additional regulations and permitting requirements. Those additional regulations and permitting requirements, as well as other regulatory developments, could lead to significant operational delays and increased operating costs, and make it more difficult to perform hydraulic fracturing.

Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting framework set forth in the federal workplace standards.

To date we have not experienced any materially adverse effect on our operations from obligations under environmental, health, and safety laws and regulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements would not have a materially 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 liquidity and capital resources to fund capital expenditures

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

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

·	Future oil and natural gas production estimates

·	Our outlook on future oil and natural gas prices and service costs

·	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 or to defer capital investment, and our outlook on our 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” section 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” section in Item 1A of this Form 10-K, and include such factors as:

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

·	A contraction in demand for oil and natural gas as a result of adverse general economic conditions or climate change initiatives

·	The availability of economically attractive exploration, development, and property acquisition opportunities and any necessary financing, including any constraints on the availability of opportunities and financing due to distressed capital and credit market conditions

·	Our ability to replace reserves and sustain production

·	Unexpected drilling conditions and results

·	Unsuccessful exploration and development drilling

·	The risks of hedging strategies, including the possibility of realizing lower prices on oil and natural gas sales as a result of commodity price risk management activities

·	The pending nature of reported divestiture plans for certain non-core oil and gas properties as well as the ability to complete divestiture transactions

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, and uncertainties with respect to the amount of proceeds that may be received from divestitures

·	The imprecise nature of oil and natural gas reserve estimates

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

·	Declines in the values of our oil and natural gas properties resulting in impairment charges and write-downs

·	The ability of purchasers of production to pay for amounts purchased

·	Drilling and operating service availability

·	Uncertainties in cash flow

·	The financial strength of hedge contract counterparties and credit facility participants, and the risk that one or more of these parties may not satisfy their contractual commitments

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

·	The potential effects of increased levels of debt financing

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

·	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 performance 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. We routinely post important information for investors on our website. Within our website’s investor relations 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.

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. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X promulgated by the SEC. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov.

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 volumetric ratio of six Mcf of natural gas to one Bbl of oil.

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

Developed reserves. With respect to reserves as of December 31, 2009, and dates thereafter, the applicable SEC definition of developed reserves is reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. With respect to reserves as of dates prior to December 31, 2009, the applicable SEC definition of proved developed reserves was proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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 commercial quantities.

Exploratory well. With respect to wells as of December 31, 2009, and dates thereafter, the applicable SEC definition of exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. With respect to wells as of dates prior to December 31, 2009, the applicable SEC definition of exploratory well was 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.

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 and/or stratigraphic condition.

Finding cost. Expressed in dollars per MCFE. Finding cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors. The information used to calculate these metrics is included in Note 15 – Oil and Gas Activities and Note 16 – Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated Financial Statements included in this report. It should be noted that finding cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years.

As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves. The calculations of various finding cost metrics are explained below.

Finding cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same period.

Finding cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, and revisions of previous estimates during the same period.

Finding cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred for development, exploration and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling and acquisitions during the same period.

Finding cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred for development, exploration and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, revisions of previous estimates, and acquisitions during the same period.

Finding cost –All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves during the same period.

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.

Lease operating expenses. The expenses incurred in the lifting of oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.

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 volumetric ratio of six Mcf of natural gas to one Bbl of oil.

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

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

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

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

NYMEX. New York Mercantile Exchange.

PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such 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, future income tax expenses, or 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 of discounted future net cash flows 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 reserves. With respect to reserves as of December 31, 2009, and dates thereafter, the applicable SEC definition of proved reserves is those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. With respect to reserves as of dates prior to December 31, 2009, the applicable SEC definition of proved reserves was the estimated quantities of crude 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, meaning prices and costs as of the date the estimate is made.

Recompletion. A 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. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized

within the exploration and production industry, as well as by investors. They are easily calculable metrics, and the information used to calculate these metrics is included in Note 16 – Disclosures about Oil and Gas Producing Activities of the Notes to Consolidated Financial Statements included in this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, since the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation. The calculations of various reserve replacement metrics are explained below.

Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity.

Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, and infill reserves, and revisions and previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity.

Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities.

Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and revisions and previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities.

Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period.

Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling, 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.

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

Resource play. A term used to describe an accumulation of oil and/or natural gas resources known to exist over a large area expanse, which when compared to a conventional play typically has a lower expected geological and/or commercial development risk.

Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction 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.

Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end 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 or natural gas, regardless of whether such acreage contains estimated net proved reserves.

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. With respect to reserves as of December 31, 2009, and dates thereafter, the applicable SEC definition of undeveloped reserves provides that undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

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 declines in prices adversely affect 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 available for capital expenditures and other items, our borrowing capacity, and the amount and value of our oil and natural gas reserves. For example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on oil and natural gas prices specified by our bank group at the time of redetermination. In addition, we may have oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly.

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:

·	Global and domestic supplies of oil and natural gas, and the productive capacity of the industry as a whole

·	The level of consumer demand for oil and natural gas

·	Overall global and domestic economic conditions

·	Weather conditions

·	The availability and capacity of transportation or refining facilities in regional or localized areas that may affect the realized price for oil or natural gas

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

·	The price and availability of alternative fuels

·	Technological advances affecting energy consumption

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

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

·	Strengthening and weakening of the U.S dollar relative to other currencies

·	Governmental regulations and taxes.

These factors and the volatility of oil and natural gas markets make it extremely 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 materially adverse effect on us.

Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

U.S. and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the U.S. federal government and other governments. Although some portions of the economy appear to have stabilized and there have been signs of the beginning of recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Continued weakness in the U.S. or global economies could materially adversely affect our business and financial condition. For example:

·	the demand for oil and natural gas in the U.S. has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition

·	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables

·	our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves

·	our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

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

Our future operations depend on our ability to find, develop, or acquire oil and natural gas reserves that are economically producible. 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 producible 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.

Substantial capital is required to replace our reserves.

We must 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, prices received for oil and natural gas sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. When oil or natural gas prices decrease or if we encounter operating difficulties that result in our cash flows from operations being less than expected, we must 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, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us.

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

The debt and equity financing markets have recently been constrained due to the global and domestic economic and financial downturn, and it is possible that circumstances may arise where one or more of the twelve participating banks in our credit facility, at some point, may not be able to fulfill their portion of the lending commitments to us under the facility. Adverse conditions in the credit markets may increase the cost of borrowings and decrease our ability to access new sources of capital.

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 seek oil and natural gas property investments 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, technical, and other 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 and 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 human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of people available has been 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. These 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 oil and natural gas reserves is complex. The process involves 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 producible 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 on adjacent properties.

As of December 31, 2009, approximately 18 percent, or 142 BCFE, of our estimated proved reserves were proved undeveloped, and approximately 9 percent, or 73 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 develop our proved undeveloped reserves, we estimate approximately $296 million of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to bring production on-line for our proved developed non-producing reserves, we estimate capital expenditures of approximately $44 million will be deployed in future years. 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 currently anticipated capital

expenditures for 2010 is directed towards projects that are not yet classified within the construct of proved reserves as defined by Regulation S-X promulgated by the SEC.

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 price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2009, were estimated using a calculated 12-month average sales price of $3.87 per MMBtu of natural gas (NYMEX Henry Hub spot price) and $61.18 per Bbl of oil (NYMEX West Texas Intermediate spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During 2009, our monthly average realized natural gas prices, excluding the effect of hedging, were as high as $5.48 per Mcf and as low as $2.96 per Mcf. For the same period, our monthly average realized oil prices before hedging were as high as $70.31 per Bbl and as low as $30.37 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 government 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, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject.

Reserve estimates as of December 31, 2009, have been prepared under the SEC’s new rules for oil and gas reporting that are effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their reserve estimates using, among other things, revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing, instead of the prior requirement to use pricing at the end of the period. The SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules in the near future. The interpretation of these rules and their applicability in different situations remains unclear in many respects. Changing interpretations of the rules or disagreements with our interpretations could result in revisions to our reserve estimates or write-downs in our reserves.

Our 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 producible reserves.

Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible 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 or 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. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. 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. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas.

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.

Drilling results in our newer shale plays, such as the Eagle Ford, Haynesville, and Marcellus shales, may be more uncertain than in shale plays that are more developed and have longer established production histories. For example, our experience with horizontal drilling in these shales, as well as the industry’s drilling and production history, is more limited than in the Woodford shale play, and we have less information with respect to the ultimate recoverable reserves and the production decline rates in these shales than we have in other areas in which we operate. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early development of these new shales; however, we can provide no assurance of the ultimate success of these drilling and completion techniques. Moreover, the recent growth in exploration in the Marcellus shale has drawn intense scrutiny from environmental interest groups, regulatory agencies, and other governmental entities. As a result, we may face significant opposition to our operations in that area that may make it difficult to obtain permits and other needed authorizations to operate or otherwise make operating more costly or difficult than operating elsewhere.

In addition, a significant part of our strategy involves increasing our drilling location inventories for multi-year programs scheduled out over several years. Such multi-year drilling inventories can be more susceptible to long-term horizon uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able to produce oil or natural gas from these or any other potential drilling locations.

Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate 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 activities may result in financial losses or may limit the prices that we receive for oil and natural gas sales.

To manage our exposure to price risks in the sale of our oil and natural gas production, 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. As of December 31, 2009, we were in a net accrued liability position of approximately $81 million with respect to our oil and natural gas hedging activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

·	Our production is less than expected

·	One or more counterparties to our hedge contracts default on their contractual obligations

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

The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to hedge transactions, which could reduce our revenues and cash flows from realized hedge settlements. As a result, our financial condition, results of operations, and cash flows could be materially adversely affected if our counterparties default on their contractual obligations under our hedge contracts.

In addition, 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. Some of our hedging transactions use derivative instruments that may involve basis risk. Basis risk in a hedging contract can occur when the change in the index upon which the hedge is based does not correlate well to the change in the index upon which the hedged production is valued, thereby making the hedge less effective. For example, a change in

the NYMEX price used for hedging certain volumes of production may not correlate exactly to the change in the regional price used for the sale of that production.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn.

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 undiscounted future net revenues, we generally must write down the costs of each such field to the estimated discounted future net cash flows of that field. Unproved properties are evaluated at the lower of cost or fair market value. As a result of significant oil and natural gas price declines in the second half of 2008, we incurred impairment of proved property write-downs, impairment of unproved properties, and goodwill impairment totaling $302.2 million, $39.0 million, and $9.5 million, respectively, during 2008. In addition, we incurred impairment of proved property write-downs and impairment of unproved properties totaling $174.8 million and $45.4 million, respectively, during 2009. Significant further declines in oil or natural gas prices in the future or unsuccessful exploration efforts could cause further impairment write-downs of capitalized costs.

We review the carrying value of our properties quarterly based on prices in effect as of the end of each quarter. 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.

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

Our revolving credit facility has a maximum commitment amount of $678 million, subject to a borrowing base that the lenders periodically redetermine based on the bank group’s assessment of the value of our oil and natural gas properties, which in turn is based in part on oil and natural gas prices. The current borrowing base under our credit facility is $900 million, which was determined as of September 29, 2009. Declines in oil or natural gas prices in the future could limit our borrowing base and reduce our ability to borrow under the credit facility. Additionally, the pending divestitures of non-core properties could result in a reduction of our borrowing base.

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, 2009, we had $267 million, net of debt discount, of total long-term senior unsecured debt outstanding under our 3.50% Senior Convertible Notes due 2027, and $188 million of secured debt outstanding under our revolving credit facility. As of February 16, 2010, we had an outstanding balance of $211.0 million drawn against our revolving credit facility, resulting in $467.0 million of available debt capacity under our revolving credit facility assuming the borrowing conditions of this facility were met. Our long-term debt represented 32 percent of our total book capitalization as of December 31, 2009.

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 costs 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, 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 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, defer capital expenditures, 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. The indenture for our 3.50% Senior Convertible Notes due 2027 provides that under certain circumstances we have the option to settle our obligations under these notes through the issuance of shares of our common stock if we so elect.

Our debt instruments, including our revolving credit facility 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.

As discussed above, 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 South Texas & 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, 2005, and 2008, the insurance markets suffered significant losses. As a result, insurance coverage for wind storms has become substantially more expensive, and future availability and costs of coverage are uncertain.

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. Under certain 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 materially adverse effect on our operations.

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.

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

The U.S. Congress is currently considering legislation that would amend the Safe Drinking Water Act to eliminate an existing exemption from federal regulation of hydraulic fracturing activities and require the disclosure of chemical additives used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing is a common process in our industry of creating artificial cracks, or fractures, in deep underground rock formations through the pressurized injection of water, sand and other additives to enable oil or natural gas to move more easily through the rock pores to a production well. This process is often necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale rock formations. We routinely utilize hydraulic fracturing techniques in many of our reservoirs, and our Eagle Ford, Haynesville, Marcellus, and Woodford shale programs utilize or contemplate the utilization of hydraulic fracturing. Currently,

regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. If adopted, the proposed amendment to the Safe Drinking Water Act could result in additional regulations and permitting requirements at the federal level. In addition, various states are also studying or considering various additional regulatory measures related to hydraulic fracturing. Additional regulations and permitting requirements could lead to significant operational delays and increased operating costs, and make it more difficult to perform hydraulic fracturing.

Proposed legislation to eliminate or reduce certain federal income tax incentives and deductions available to oil and gas exploration and production companies could, if enacted into law, have a material adverse effect on our results of operations and cash flows.

In 2009, the “Oil Industry Tax Break Repeal Act of 2009” was introduced in the U.S. Senate. This bill proposes amendments to the Internal Revenue Code of 1986 to eliminate or reduce certain federal income tax incentives and deductions currently available to oil and gas exploration and production companies. The proposed amendments include the elimination or reduction of current deductions for intangible drilling and development costs, percentage depletion allowances, and the manufacturing deduction for oil and gas properties. President Obama’s proposed Fiscal Year 2011 Budget also contemplates these proposed tax law amendments. If some or all of these provisions are enacted into law, our effective tax rate and current income tax expense will increase, potentially significantly, which would increase cash requirements to pay income tax thereby reducing cash flows from operating activities, which in turn will reduce cash available for drilling and other exploration and development activities.

Enactment of a Pennsylvania severance tax on natural gas could adversely impact the economic viability of exploiting natural gas drilling and production opportunities in our Marcellus Shale resource play.

The Governor of the Commonwealth of Pennsylvania has proposed to its legislature the adoption of a severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is five percent of the value of the natural gas at the wellhead, plus $0.047 per Mcf of natural gas severed. Our Marcellus Shale acreage is located in Pennsylvania. If Pennsylvania adopts such a severance tax, it could impact the economic viability of exploiting natural gas drilling and production opportunities in the Marcellus Shale.

Possible legislation and regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

On December 15, 2009, the U.S. Environmental Protection Agency (EPA) officially published its findings that emissions of carbon dioxide, which is a byproduct of the burning of refined oil products and natural gas, methane, which is a primary component of natural gas, and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur increased costs to reduce emissions of greenhouse gases associated with our operations and could adversely affect demand for the oil and natural gas that we produce.

In addition, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” (ACESA), which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in

greenhouse gas emissions from 2005 levels by 2020, and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. The cost of these allowances would be expected to escalate significantly over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Obama administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system. In addition, several states have considered initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. Although it is not possible at this time to predict when the U.S. Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal or state laws or regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect the demand for the oil and natural gas that we produce.

The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress is currently considering legislation to increase the regulatory oversight of the over-the-counter derivatives markets in order to promote more transparency in those markets, and impose restrictions on certain derivatives transactions, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission (CFTC) to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any new laws or regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to swings in oil and gas commodity prices, may impose additional restrictions on our trading and commodity positions, and could have an adverse effect on our ability to hedge risks associated with our business and on the cost of our hedging activity.

Our ability to sell oil and natural gas and/or receive market prices for our oil and natural gas production may be adversely affected by constraints on pipelines and gathering systems owned by others and various transportation interruptions.

The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipeline transportation and gathering 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.

In particular, if drilling in the Eagle Ford, Haynesville, and Marcellus shales continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are being considered for these areas may not be developed due to lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells to wait for a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX, which would adversely affect our results of operations and cash flows.

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

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, 2009 to February 16, 2010, the closing daily sales price of our common stock as reported by the New York Stock Exchange ranged from a low of $11.58 per share to a high of $37.89 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 by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment.

Our certificate of incorporation and by-laws 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 members 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 materially adverse effect on our stock price. As of February 16, 2010, 62,590,571 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 1,271,292 shares of our common stock were outstanding, of which all were exercisable. These options are exercisable at prices ranging from $7.97 to $20.87 per share. In addition, restricted stock units providing for the issuance of up to a total of 403,968 shares of our common stock and 1,141,113 performance share awards (“PSAs”) were outstanding. The PSAs represent the right to receive, upon settlement of the PSAs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSAs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSAs have vested. As of February 16, 2010, there were 62,777,688 shares of common stock outstanding, which is net of 126,893 treasury shares.

We may not always pay dividends on our common stock.

The payment of future dividends remains at 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 2009.

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 16, 2010.

Name	Age	Position

Anthony J. Best	60	Chief Executive Officer and President
Javan D. Ottoson	51	Executive Vice President and Chief Operating Officer
A. Wade Pursell	44	Executive Vice President and Chief Financial Officer
Mark D. Mueller	45	Senior Vice President and Regional Manager
Milam Randolph Pharo	57	Senior Vice President and General Counsel
Paul M. Veatch	43	Senior Vice President and Regional Manager
Stephen C. Pugh	51	Senior Vice President and Regional Manager
Kenneth J. Knott	45	Vice President – Business Development and Land and Assistant Secretary
Gregory T. Leyendecker	52	Vice President and Regional Manager
John R. Monark	57	Vice President – Human Resources
Lehman E. Newton, III	54	Vice President and Regional Manager
David J. Whitcomb	47	Vice President – Marketing
Dennis A. Zubieta	43	Vice President – Engineering and Evaluation
Mark T. Solomon	41	Controller

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 securing capital commitments for a new exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., an independent oil and natural gas exploration and production company that was a subsidiary of Unocal, 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 various energy 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 25 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., an independent oil and natural gas exploration and production company, where his responsibilities included overseeing all aspects of its drilling and engineering functions. Mr. Ottoson managed Permian Basin assets for Pure Resources, Inc., a Unocal subsidiary, 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 of ARCO China, Commercial Director of ARCO British, and Vice President of Operations and Development, ARCO Permian.

A. Wade Pursell joined St. Mary in September 2008 as Executive Vice President and Chief Financial Officer. Mr. Pursell was Executive Vice President and Chief Financial Officer for Helix Energy Solutions Group, Inc., a global provider of life-of-field services and development solutions to offshore energy producers and an oil and gas producer, from February 2007 to September 2008. From October 2000 to February 2007, he was Senior Vice President and Chief Financial Officer of Helix. He joined Helix in May 1997, as Vice President — Finance and Chief Accounting Officer. From 1988 through 1997 he was with Arthur Andersen LLP, lastly as an Experienced Manager specializing in the offshore services industry.

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 over 22 years. From September 2006 to September 2007 he was Vice President and General Manager at Samson Exploration Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, in Calgary, Canada, where his responsibilities included fiscal performance, reserves, and all operational functions of the company. From April 2005 until its sale in August 2006, Mr. Mueller was Vice President and General Manager for Samson Canada Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, where he was responsible for all business units and the eventual sale of the company. 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 Canadian oil and gas company that was 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.

Milam Randolph Pharo was appointed Senior Vice President and General Counsel in August 2008. He joined St. Mary as Vice President – Land and Assistant Secretary in January 1996. In May 1998 he was appointed Vice President – Land and Legal and Assistant Secretary. From 1979 until joining St. Mary, Mr. Pharo served in private practice as an attorney specializing in oil and gas matters.

Paul M. Veatch was appointed Senior Vice President and Regional Manager in March 2006. Mr. Veatch joined St. Mary in April 2001 as Regional A & D Engineer. He was Vice President – General Manager, ArkLaTex from August 2004 to March 2006 and Manager of Engineering for the ArkLaTex region from April 2003 to August 2004.

Stephen C. Pugh joined St. Mary as Senior Vice President and Regional Manager of the ArkLaTex Region in July 2007. Mr. Pugh has over 27 years of experience in the oil and gas industry. Prior to joining St. Mary, Mr. Pugh was Managing Director for Scotia Waterous, a global leader in oil and gas merger and acquisition advisory services. Mr. Pugh was responsible for new business development, managing client relationships and providing merger and acquisition advice, including transaction execution to clients in the energy sector. Mr. Pugh held this position from July 2006 to July 2007. Prior to joining Scotia Waterous, Mr. Pugh had over 17 years of experience in acquisitions and divestitures, operations and engineering with Burlington Resources, and its successor-by-merger, ConocoPhillips. His most recent position with Burlington Resources, Inc. and ConocoPhillips 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.

Gregory T. Leyendecker was appointed Vice President and Regional Manager in July 2007. Mr. Leyendecker joined St. Mary in December 2006 as Operations Manager for the South Texas & Gulf Coast Region in Houston. Mr. Leyendecker has worked for 28 years in the energy industry and held various positions with Unocal Corporation, an independent oil and natural gas exploration and production company, 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 the San Joaquin Valley business unit of Chevron, as successor-by-merger of Unocal Corporation, 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 from February 2006 to November 2006 for Enventure Global Technology, a provider of solid expandable tubular technology.

John R. Monark was appointed Vice President – Human Resources in July 2008. Mr. Monark joined St. Mary in May of 2008 as Director of Human Resources. Mr. Monark was Director – Human Resources for JF Shea Corporation, a leading construction and homebuilding company, from 2004 to May 2008. He served as Vice President – Human Resources for Pameco Corporation, a distributor of HVAC systems and equipment and refrigeration products, from 2000 to 2004. From 1996 to 2000 he served as Vice President – Human Resources for CH2M HILL.

Lehman E. Newton, III joined St. Mary in December 2006 as General Manager for the Midland office and was appointed Vice President and Regional Manager of the Permian region in June 2007. Mr. Newton has over 28 years of experience in engineering, operations, and business development roles in the exploration and production industry. From November 2005 to November 2006 Mr. Newton served as Project Manager for one of Chevron’s largest lower 48 projects. 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 Permian Basin E&P firm, 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.

Kenneth J. Knott was appointed Vice President – Business Development and Land and Assistant Secretary in August 2008. Mr. Knott joined St. Mary in November 2000 as Senior Landman for the South Texas & Gulf Coast region in Lafayette, LA and later assumed the position of South Texas & Gulf Coast Regional Land Manager when the office was moved to Houston in March 2004. Mr. Knott has worked for 22 years in the energy industry holding various Land and Business Development positions with ARCO, Vastar Resources, and BP Amoco. Between 1987 and 1993, Mr. Knott worked for ARCO in a land capacity handling land and business development responsibilities in several geographic areas, such as Permian, Mid-Continent, Michigan, and California. Upon ARCO’s spin-off of Vastar Resources in 1993, he joined Vastar Resources as a Senior Landman working the Gulf Coast and Gulf of Mexico regions until 1999, at which time he assumed the role of Director of Business Development for the Gulf Coast region. He remained in that capacity until the merger of Vastar Resources into BP Amoco in September 2000, whereby he assumed a Senior Landman position working the Gulf Coast region.

David J. Whitcomb was appointed Vice President – Marketing in August 2008. Mr. Whitcomb joined St. Mary in November 1994 as Gas Contract Analyst and was named Assistant Vice President of Gas Marketing in October 1995. In March 2007 his responsibilities were expanded to include oil marketing at which time his title was changed to Assistant Vice President – Director of Marketing. From 1991 until the time of his employment with St. Mary, Mr. Whitcomb worked for Anderman/Smith Operating Company as a Gas Contract Analyst during which time his primary responsibility was to resolve take-or-pay gas contract disputes. Mr. Whitcomb began his career in the industry in 1986 with Apache Corporation where he worked as an internal auditor for several years and then moved into marketing where he worked as a Gas Controller and Gas Contracts Analyst.

Dennis A. Zubieta was appointed Vice President – Engineering and Evaluation in August 2008. Mr. Zubieta joined St. Mary in June 2000 as Corporate A&D Engineer, assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was employed by Burlington Resources (formerly known as Meridian Oil, Inc.) from June 1988 to May 2000 in various operations and reservoir engineering capacities.

Mark T. Solomon was appointed Controller in January 2007. Mr. Solomon was also appointed Acting Principal Financial Officer from April 30, 2008, to September 8, 2008, which was during the period of time that the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined St. Mary in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President – Financial Reporting from September 2002 to May 2006 and Assistant Vice President - Assistant Controller from May 2006 to January 2007. Prior to joining St. Mary, Mr. Solomon was an auditor with Ernst & Young.

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 closing prices for the quarterly periods in 2009 and 2008, as reported by the New York Stock Exchange:

Quarter Ended	High		Low
December 31, 2009	$	38.05	$	29.80
September 30, 2009		33.62		17.13
June 30, 2009		23.48		12.05
March 31, 2009		24.60		11.21

December 31, 2008	$	35.81	$	14.76
September 30, 2008		65.58		32.53
June 30, 2008		65.00		37.73
March 31, 2008		39.95		31.70

PERFORMANCE GRAPH

The following performance graph compares the cumulative return on St. Mary’s common stock, not including dividend payments, for the period beginning December 31, 2004, and ending on December 31, 2009, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index.

COMPARE 5-YEAR CUMULATIVE TOTAL RETURN

“Performance Graph” shall be deemed to be “furnished” but not “filed” with the Securities and Exchange Commission.

Holders. As of February 16, 2010, the number of record holders of St. Mary’s common stock was 111. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 17,000.

Dividends. St. Mary has paid cash dividends to stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2009. 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, cash flow, 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 the level of our current ratio of current assets to current liabilities 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 $6.2 million in 2009 and $6.2 million in 2008.

Equity Incentive Compensation Plan. In May 2009, the shareholders approved an amendment to rename the 2006 Equity Incentive Compensation Plan to the Equity Incentive Compensation Plan (the “Equity Plan”).

Restricted Shares. St. Mary has no restricted shares outstanding as of December 31, 2009, aside from Rule 144 restrictions on shares for insiders, shares are subject to transfer restrictions under the provisions of the Employee Stock Purchase Plan, and shares issued to directors under the Equity Plan.

Equity Compensation Plans. St. Mary has the 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 our equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under the equity compensation plans as of December 31, 2009:

	(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))
Equity compensation plans approved by security holders:
Equity Incentive Compensation Plan
Stock options and incentive stock options (1)		1,274,920	$	13.31		-
Restricted stock (1)		408,356		-		-
Performance share awards (1)(3)		1,145,871	$	32.52		1,771,009
Total for Equity Incentive Compensation Plan		2,829,147	$	22.40		1,771,009
Employee Stock Purchase Plan (2)		-		-		1,468,275

Equity compensation plans not approved by security holders		-		-		-

Total for all plans		2,829,147	$	22.40		3,239,284

(1)

In May 2006 the stockholders approved the 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 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 referred to as the “Predecessor Plans”). All grants of equity are now made out of the 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 Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan on March 26, 2008, and the amended plan was approved by stockholders at our annual stockholders’ meeting May 21, 2008. Our Board of Directors approved additional amendments to the Equity Plan on March 26, 2009, and the amendments were approved by stockholders at our annual stockholders’ meeting on May 20, 2009. Awards granted in 2009, 2008, and 2007 under the Equity Plan were 1,016,931, 932,767, and 135,138, respectively.

(2)

Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (the “ESPP”), eligible employees may purchase shares of our 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 six-month offering period, and shares issued under the ESPP through December 31, 2009, are restricted for a period of 18 months from the date issued. Effective January 1, 2010, shares issued under the ESPP will be restricted for a period six months from the date issued. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 86,308, 45,228, and 29,534 in 2009, 2008, and 2007, respectively.

(3)

The PSAs represent the right to receive, upon settlement of the PSAs after the completion of a three-year performance measurement period, a number of shares of our common stock that may be from zero to two times the number of PSAs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSAs have vested. The performance criteria for the PSAs are based on a combination of our cumulative Total Shareholder Return (“TSR”) for the performance period and the relative measure of our TSR compared with the TSR an index comprised of certain peer companies for the performance period. The current outstanding PSAs were granted on August 1, 2009, and 2008, and utilize a three-year performance measurement period which began on July 1, 2009, and 2008, respectively. On July 1, 2009, the market value per share of our common

stock was $21.15, and on the date of grant the market value per share of our common stock was $23.87. On July 1, 2008, the market value per share of our common stock was $62.51, and on the date of grant the market value per share of our common stock was $43.11. The PSAs do not have an exercise price associated with them, but rather the $32.52 price shown in the above table represents the weighted-average per share fair value as of December 31, 2009, calculated pursuant to ASC Topic 718, which is presented in order to provide additional information regarding the potential dilutive effect of the PSAs as of December 31, 2009, in view of the share price level at the beginning of the performance period which will be utilized to compute the TSR measurements for determination of the number of shares to be issued upon settlement of the PSAs after completion of the three-year performance measurement period.

Issuer Purchases of Equity Securities. 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, 2009, 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 (1)(2)(3)(4)	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(5)

January 1, 2009 – March 31, 2009	58,688	$	13.60	-0-	3,072,184

April 1, 2009 - June 30, 2009	341	$	18.69	-0-	3,072,184

July 1, 2009 - September 30, 2009	412	$	24.86	-0-	3,072,184

October 1, 2009 - October 31, 2009	30	$	35.36	-0-	3,072,184

November 1, 2009 - November 30, 2009	86	$	34.10	-0-	3,072,184

December 1, 2009 - December 31, 2009	21,391	$	35.34	-0-	3,072,184

Total October 1, 2009 - December 31, 2009	21,507	$	35.33	-0-	3,072,184

Total	80,948	$	19.45	-0-	3,072,184

(1)	Includes a total of 6,500 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.

(2)	Includes a total of 5,000 shares purchased by A. Wade Pursell, St. Mary’s Executive Vice President and Chief Financial Officer, in open market transactions that were not made pursuant to our stock repurchase program.

(3)	Includes a total of 10,000 shares purchased by William D. Sullivan, a Director of St. Mary, in open market transactions that were not made pursuant to our stock repurchase program.

(4)	Includes 59,448 shares withheld (under the terms of grants under the Equity Incentive Compensation Plan) to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying restricted stock units that were not made pursuant to our stock repurchase program.

(5)

In July 2006 our 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, we have Board authorization to repurchase 3,072,184 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 payment of dividends and stock repurchases are subject to covenants in our bank credit facility, including the requirement that we maintain certain levels of stockholders’ equity and the limitation that does not allow our annual dividend rate to exceed $0.25 per share.

ITEM 6. SELECTED FINANCIAL DATA

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

	Years Ended December 31,
	2009			2008 (1)			2007(1)		2006		2005
	(In thousands, except per share data)

Total operating revenues	$	832,201		$	1,301,301	$	990,094	$	787,701	$	739,590

Net income (loss)	$	(99,370	)	$	87,348	$	187,098	$	190,015	$	151,936

Net income (loss) per share:
Basic	$	(1.59	)	$	1.40	$	3.02	$	3.38	$	2.67
Diluted	$	(1.59	)	$	1.38	$	2.90	$	2.94	$	2.33

Total assets at year end	$	2,360,936		$	2,697,247	$	2,572,942	$	1,899,097	$	1,268,747

Long-term obligations:
Line of credit	$	188,000		$	300,000	$	285,000	$	334,000	$	-
Senior convertible notes, net of debt discount	$	266,902		$	258,713	$	251,070	$	99,980	$	99,885

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

(1)	As Adjusted, see Note 5 to the Consolidated Financial Statements

Supplemental Selected Financial and Operations Data

	Years Ended December 31,
	2009			2008		2007			2006		2005
	(In thousands, except per share data)
Balance Sheet Data
Total working capital (deficit)	$	(87,625	)	$	15,193	$	(92,604	)	$	22,870	$	4,937
Total stockholders’ equity	$	973,570		$	1,162,509	$	902,574		$	743,374	$	569,320

Weighted-average shares outstanding
Basic		62,457			62,243		61,852			56,291		56,907
Diluted		62,457			63,133		64,850			65,962		66,894

Reserves
Oil (MMBbl)		53.8			51.4		78.8			74.2		62.9
Gas (Mcf)		449.5			557.4		613.5			482.5		417.1
MCFE		772.2			865.5		1,086.5			927.6		794.5

Production and Operational:
Oil and gas production revenues, including hedging	$	756,601		$	1,158,304	$	936,577		$	758,913	$	711,005
Oil and gas production expenses	$	206,800		$	271,355	$	218,208		$	176,590	$	142,873
DD&A	$	304,201		$	314,330	$	227,596		$	154,522	$	132,758
General and administrative	$	76,036		$	79,503	$	60,149		$	38,873	$	32,756

Production Volumes:
Oil (MMBbl)		6.3			6.6		6.9			6.1