exhibit991.htm

EXHIBIT 99.1

For Information

Brent A. Collins

303-861-8140

FOR IMMEDIATE RELEASE

ST. MARY REPORTS RESULTS FOR FOURTH QUARTER OF 2009

AND 2009 PROVED RESERVES AND CAPITAL EXPENDITURES;

PROVIDES OPERATIONAL AND 2010 GUIDANCE UPDATE

·	Quarterly production of 26.1 BCFE at high end of guidance of 24.75 – 26.25 BCFE

·	Reported GAAP net income of $990 thousand, or $0.02 per diluted share; adjusted net income of $20.1 million or $0.31 per diluted share

·	Proved reserves at year-end 2009 of 772.2 BCFE

·	Positive results from additional wells in Eagle Ford shale program, where leased and optioned acreage has increased 10% to 250,000 net acres

DENVER, February 22, 2010 – St. Mary Land & Exploration Company (NYSE: SM) today reports financial results from the fourth quarter of 2009. In addition, a new presentation for the fourth quarter earnings and operational update has been posted at the Company’s website at stmaryland.com. This presentation will be referenced in the conference call scheduled for 8:00 a.m. Mountain time (10:00 a.m. Eastern time) on February 23, 2010. Information for the earnings call can be found below.

MANAGEMENT COMMENTARY

Tony Best, CEO and President, remarked, “Last year was a transformational year for St. Mary. We entered 2009 with a great deal of uncertainty regarding the economy and we responded appropriately by cutting back our level of capital investment, particularly in development activities. Our focus shifted to advancing a number of exploration projects and we were rewarded as the Eagle Ford shale emerged as an exciting new resource play in our portfolio. For the year, St. Mary replaced production and held production on retained properties flat while investing 62% less on development activities compared to 2008. We are well positioned as we enter 2010, with an inventory of projects stronger than at any time in our recent history and ample liquidity to fund our programs.”

FOURTH QUARTER 2009 RESULTS

St. Mary posted net income for the fourth quarter of 2009 of $990 thousand, or $0.02 per diluted share. This compares to a net loss of ($127.1) million, or a loss of ($2.04) per diluted share, for the same period in 2008. Adjusted net income for the quarter, which adjusts for significant non-recurring or unusual non-cash items, was $20.1 million, or $0.31 per diluted share, versus $26.0 million, or $0.42 per diluted share, for the fourth quarter of 2008. A summary of the adjustments made to arrive at adjusted net income is presented in the table below.

	For the Three Months Ended December 31,
	2009							2008
Weighted-average diluted share count (in millions)					64.1						62.2
	$ in millions			Per Diluted Share			$ in millions			Per Diluted Share
Reported net income (loss)	$	1.0		$	0.02		$	(127.1	)	$	(2.04	)
After –tax adjustments**
Change in Net Profits Plan liability	$	4.3		$	0.07		$	(52.8	)	$	(0.85	)
Unrealized derivative (gain) loss	$	2.0		$	0.03		$	(7.8	)	$	(0.13	)
Gain on property sales	$	(13.8	)	$	(0.21	)	$	(6.2	)	$	(0.10	)
Bad debt recovery associated with SemGroup, L.P.	$	(3.1	)	$	(0.05	)		-			-
Loss on insurance settlement		-			-		$	0.5		$	0.01

Adjusted net loss, before impairments	$	(9.5	)	$	(0.15	)	$	(193.5	)	$	(3.11	)

After –tax non-cash impairments**
Impairment of proved properties	$	13.5		$	0.21		$	190.7		$	3.07
Abandonment & impairment of unproved properties	$	15.7		$	0.24		$	22.7		$	0.36
Impairment of goodwill		-			-		$	6.2		$	0.10
Impairment of materials inventory	$	0.5		$	0.01			-			-

Adjusted net income	$	20.1		$	0.31		$	26.0		$	0.42

NOTE: Totals may not add due to rounding
* On January 1, 2009, the Company adopted new authoritative guidance under FASB ASC Topic 470-20, "Debt with Conversion and Other Options" ("ASC Topic 470") which required retrospective application. As result, prior period balances presented have been adjusted to reflect the period-specific effects of applying ASC Topic 470. ** The Company’s standard practice is to use the effective income tax rate for the respective period when adjusting pre-tax items in the calculation of adjusted net income. For the fourth quarter of 2009, the full year effective tax rate of 38% was used in lieu of the quarterly effective tax rate. This is due to minor changes in permanent tax deductions disproportionately impacting the effective tax rate in a period when the Company had little pre-tax book income.

Discretionary cash flow was $144.2 million for the fourth quarter of 2009 compared to $163.6 million for the same period in 2008. Net cash provided by operating activities was $83.1 million for the fourth quarter of 2009 compared with $110.4 million for the same period in 2008.

Adjusted net income and discretionary cash flow are non-GAAP financial measures – please refer to the respective reconciliation in the accompanying Financial Highlights section at the end of this release.

St. Mary reported quarterly production of 26.1 BCFE for the fourth quarter of 2009, which was at the upper end of the guidance range of 24.75 to 26.25 BCFE. Reported production for the same period last year was 30.0 BCFE. Production from retained properties, which adjusts for divestitures that have taken place over the past two years, was 25.2 and 27.8 BCFE for the fourth quarters of 2009 and 2008, respectively. Sequentially, reported production and production from retained properties in the fourth quarter of 2009 were essentially flat with the preceding quarter.

Total operating revenues and other income for the fourth quarter of 2009 was $242.0 million compared to $258.2 million for the same period in 2008. In the fourth quarter of 2009, the Company’s average equivalent price per MCFE, net of hedging, was $7.69 per MCFE, which is a decrease of 2% from the $7.84 per MCFE realized in the comparable period in 2008.

Lease operating expense in the fourth quarter of 2009 of was $1.31 per MCFE, which is below the Company’s guidance of $1.35 to $1.40 per MCFE. This represents an 18% decrease from the $1.59 per MCFE in the comparable period last year. Sequentially, lease operating expense remained flat in the fourth quarter of 2009 from the third quarter.

Transportation expense in the fourth quarter of 2009 was $0.20 per MCFE, which is within the guidance range of $0.20 to $0.25 per MCFE. The reported per unit expense remained flat from the comparative period in 2008. Transportation expense per MCFE was also unchanged from the third quarter of 2009.

Production taxes for the fourth quarter of 2009 were $0.51 per MCFE, which is higher than the guidance of $0.45 to $0.50 per MCFE that had previously been provided and was 31% higher on a per unit basis than the same period a year ago. Sequentially, production taxes increased $0.34 per MCFE in the third quarter of 2009. Production taxes are a function of the pre-hedged oil and natural gas revenue realized in the respective periods.

Total general and administrative (“G&A”) expense for the fourth quarter of 2009 was $0.80 per MCFE, which is below the guidance range of $0.86 to $0.93 per MCFE. The variance from guidance is largely the result of lower compensation related costs than had been previously assumed. On a sequential basis, general and administrative remained essentially flat.

Depletion and depreciation expense decreased 9%, or $0.30 per MCFE, between the fourth quarters of 2009 and 2008. Year over year, DD&A per MCFE decreased to $2.88 per MCFE from $3.18 per MCFE. The decrease in DD&A is largely due to the reduction

of the book value of the Company’s oil and gas assets as a result of impairments that have been recognized over the past year. Sequentially, DD&A in the fourth quarter of 2009 increased 13% from $2.54 per MCFE in the third quarter. Guidance for DD&A in the fourth quarter was $2.50 to $2.70 per MCFE. The sequential increase and the variance from guidance is the result of a decrease in the Company’s year-end proved reserves, which resulted in a smaller base over which capitalized costs related to the Company’s producing properties are depleted and resulted in a higher DD&A rate for the period.

Impairment of proved properties was $21.6 million in the fourth quarter of 2009 compared to $292.1 million for the comparable period in 2008. The majority of the impairment in the fourth quarter of 2009 related to properties located in the Company’s ArkLaTex region. Decline in year-end 2008 proved reserves and lower natural gas prices at the end of 2008 were major contributors to the 2008 impairment of proved properties.

Abandonments and impairments of unproved properties were $25.2 million and $34.8 million for the fourth quarters of 2009 and 2008, respectively. The 2009 amount includes roughly $12 million related to leasehold in the Mid-Continent region that is either expiring or is being impaired since the Company will not develop it under its current capital investment allocation. The remainder relates to leasehold that will not be developed given the Company’s current view regarding capital allocation or is believed to not be prospective.

In the fourth quarter of 2008, the Company fully impaired the goodwill associated with an acquisition made in 2005.

Exploration expense of $13.4 million was recognized in the fourth quarter of 2009, compared to $17.7 million in the same period in 2008. The decrease reflects a decrease in exploration overhead in 2009. Geologic and geophysical spending was relatively consistent between the two periods.

In the fourth quarter of 2009, St. Mary recognized a pre-tax non-cash charge of $7.0 million as a result of the increase in the Net Profits Plan (“NPP”) liability, compared to a benefit of $80.9 million in the fourth quarter of 2008. This periodic expense is a reflection of the change in the liability during the respective periods. This liability is a significant management estimate and is highly sensitive to a number of assumptions including future commodity prices, production rates, and operating costs. The last pool created under this legacy compensation plan was in 2007.

St. Mary’s effective tax rate for 2009 was 38%. During the fourth quarter, due primarily to deductions driven by increased drilling activity, the Company determined a net operating loss could be carried back to 2005 resulting in a significant tax refund. This resulted in certain “permanent” tax deductions which carry limitations to be reversed in the fourth quarter provision. These items totaled only $614,000 but due to the relatively small book pre-tax income amount in the fourth quarter, the adjustment caused the

effective rate for the quarter to increase to roughly 60%. This had minimal impact on the full year rate of 38%.

FULL YEAR PRODUCTION

Following is a table detailing the Company’s full year production for 2009 compared to 2008 which adjusts for divestiture efforts over the last two years.

Full Year Production (in BCFE)
	2008		2009		Difference		%Difference
Total properties	114.6		109.1		(-5.5	)	-5%
Production contribution of sold properties	(10.1	)	(5.1	)	(5.0	)
Retained production	104.5		103.9		(0.6	)	-1%

Despite the decrease in capital expenditures in 2009 compared to 2008 and the focus on exploration activities last year, St. Mary managed to keep production from the retained properties flat year over year.

PROVED RESERVES AND COST INCURRED

Below is a roll-forward of the Company’s proved reserves from year-end 2008 to year-end 2009.

	(BCFE)
Beginning of year	865.5

Revisions of previous estimate (engineering and price)	(49.6	)
Discoveries and extensions	72.3
Infill reserves in an existing proved field	37.3
Purchases of minerals in place	-
Sales of reserves	(44.2	)
Production	(109.1	)

End of year	772.2

St. Mary’s proved reserves as of December 31, 2009, were 772.2 BCFE, which is a decrease of 11% from 865.5 BCFE at the end of 2008. The reserves are comprised of 53.8 MMBbl of oil and 449.5 Bcf of natural gas, and are 82% proved developed. The before income tax PV-10 value of St. Mary’s proved reserves at December 31, 2009, was $1.3 billion ( 98% of which relates to the proved developed reserves), which is essentially flat with last year’s PV-10 value. Over 85% of St. Mary’s proved reserves by value were reviewed by an outside reserve engineering firm. More detailed information

regarding the breakdown of these proved reserves by product and development status is available in the accompanying Financial Highlights. The Company’s management will discuss its proved reserves on the conference call scheduled for Tuesday, February 23, 2010.

Prices used at year end to calculate the Company’s estimate of proved reserves were $3.87 per MMBTU of natural gas and $61.18 per barrel of oil and reflect the SEC’s new pricing methodology which requires the use of the trailing 12-month arithmetic average of the first of month price. These prices are 32% lower and 37% higher than the prices used at the end of 2008 for natural gas and oil, respectively.

If proved reserves had been calculated consistent with the pricing methodology in place at the end of last year (i.e. end of year price), the Company’s estimate of proved reserves would have been 897.2 BCFE. Of this amount, 59% would be natural gas and 78% would be characterized as proved developed reserves. The before income tax PV-10 of this scenario would be $2.4 billion, 90% of which relates to the proved developed reserves.

Below is a table detailing the Company’s costs incurred in oil and gas producing activities for the year ended December 31, 2009. St. Mary invested 51% less in 2009 compared to 2008 and deployed 62% less in development activities year over year.

Costs incurred in oil and gas producing activities:
	For the Year Ended
	December 31,
	2009
	($ in thousands)
Development costs	$	223,108
Exploration costs		154,122
Acquisitions:
Proved properties		76
Unproved properties – acquisitions of
proved properties		-
Unproved properties – other		41,677
Total, including asset retirement obligation	$	418,983

FINANCIAL POSITION AND LIQUIDITY

As of December 31, 2009, St. Mary had total long-term debt of $454.9 million. The long-term credit facility was down $47 million from September 30, 2009, to $188.0 million and the balance on the 3.50% Senior Convertible Notes was $266.9 million, net of debt discount. The credit facility matures in July of 2012 and the Senior Convertible Notes cannot be put to the Company until April of 2012. The Company’s debt-to-book capitalization ratio was 32% as of the end of the quarter.

The borrowing base for the long-term credit facility was reaffirmed by St. Mary’s bank group on September 29, 2009, and remains unchanged at an amount of $900 million. The Company has a commitment amount of $678 million from the 12 banks that comprise the Company’s bank group.

OPERATIONAL UPDATE

Capital Investment Budget

There have been no significant changes to the 2010 capital budget of $725 million that was provided in the Company’s December 16, 2009, press release.

Eagle Ford Shale

St. Mary currently has 250,000 net acres leased or optioned in South Texas that are prospective for the Eagle Ford shale, which is an increase from the 225,000 net acres last reported. The acreage is comprised of roughly 168,000 net acres in Webb and LaSalle counties where the Company has essentially 100% working interest and 82,500 net acres in a joint venture with Anadarko Petroleum in Dimmit County.

St. Mary has drilled and completed an additional 5 wells on its operated acreage since its last update. The table below provides production and operational details regarding these recent Eagle Ford shale wells.

Name	7-day Max Sales (MMCFE/d)	30-day Max Sales (MMCFE/d)	BTU/SCF	Condensate Yield (BPM)	Lateral Length	Completion Stages
Briscoe G 2H	9.1	6.6	1,300	32	4,995	15
Briscoe B 1H	7.6	4.8	1,300	29	5,044	15
Briscoe G GU 1 3H	5.8	3.7	1,280	39	5,035	15
Galvan Ranch 7H	6.7	5.6	1,160	0	5,031	15
Briscoe G 4H	8.0	N/A	1,260	102	5,050	15

The Company plans to operate two drilling rigs throughout 2010 and will drill 34 gross wells in its Eagle Ford program. St. Mary also plans to participate in the partner-operated program on the joint venture acreage.

Marcellus Shale

In the Marcellus shale program in north central Pennsylvania, the Company expects wells drilled in the McKean County portion of its acreage to have initial production rates of between 3 to 5 MMCFE/d based on testing done to date. A gathering line that will connect these first two wells to the sales pipeline, as well as serve future planned development, is currently under construction. The connection to the first well has been completed and sales will commence when a temporary facility issue has been corrected. The connection to the second well is expected to be completed around mid-year.

St. Mary has leased or optioned approximately 42,000 net acres in McKean and Potter Counties, Pennsylvania. The Company plans to drill a total of four horizontal wells in 2010; two each in McKean and Potter Counties. A seismic shoot over a portion of the acreage is also planned for this year.

Haynesville Shale

The 3D data for the Company’s acreage in Shelby and San Augustine Counties, Texas has been received and is currently being evaluated. St. Mary has one operated rig drilling in East Texas targeting the Haynesville shale. The Company has 41,000 net acres that it believes are prospective for the Haynesville shale, of which 31,000 net acres are located in Shelby and San Augustine Counties, Texas. Much of the acreage in these counties is also believed to be prospective for the Bossier shale.

Seven operated horizontal wells targeting the Haynesville shale are planned for 2010, all of which will be on high working interest acreage in East Texas.

Woodford Shale

The two increased density simultaneous fracture stimulation (“simul-frac”) pilots that were conducted in 2009 have been concluded and analyzed, and the results are positive. During 2009, the Company’s first test involved simul-fracing four wells on 128-acre spacing, or five wells per section. Positive initial results from this test led to a four well test on 64-acre spacing, or ten wells per section. The Company believes that it will be able to book proved reserves on these infill wells at a range of 2.7 to 3.0 BCFE per well, which is consistent with the range seen on lower density drilling. St. Mary believes that the results learned from this effort will improve its understanding of the ultimate spacing in some other shale plays, particularly the Eagle Ford and Marcellus shales.

St. Mary has roughly 34,000 net acres in the Arkoma Basin in Oklahoma with potential for the Woodford shale. The Company’s plan to drill six horizontal wells in 2010 is designed primarily to preserve its acreage position in the play.

Bakken/Three Forks

The Company recently completed a test designed to determine the connectivity of the Bakken and Three Forks formations in a portion of its acreage. Two horizontal wells were drilled, with one targeting the Bakken and the other targeting the Three Forks. These wells were then simul-fraced together. The combined 24 hour IP of the two wells was roughly 2,800 BOEPD. The Company will be monitoring the performance of the wells over a number of months to determine the extent to which the two wells may be producing incremental reserves beyond what could be obtained through a single zone completion.

St. Mary has approximately 70,000 net acres in North Dakota that it believes are prospective for development of the Bakken and Three Forks intervals. This is an increase of roughly 17,000 net acres from the end of 2008. Approximately 48,000 net

acres are located in McKenzie and Williams counties. The Company also has roughly 21,000 net acres in Divide County, North Dakota where testing is focused on the Three Forks interval.

The Company plans to drill 17 operated wells in the Williston Basin in 2010, the majority of which will be Bakken wells in its Bear Den prospect in McKenzie County.

Other Activity

In the Permian Basin, two operated rigs are currently running in the basin. The Wolfberry tight oil program continues to be the primary focus of the Company in the basin.

The Company is currently drilling a horizontal Granite Wash well in its Mayfield area in Beckham County, Oklahoma. St. Mary has roughly 32,000 net acres that are prospective for the Granite Wash interval, the majority of which is held by production. Four operated wells are planned in this program for 2010.

St. Mary is engaged in an exploration program targeting the Niobrara formation in south eastern Wyoming. The Company is currently in the process of drilling its first well. St. Mary currently has 24,000 net acres under lease in the area.

2010 GUIDANCE

The Company’s guidance for the first quarter and the full year of 2010 is as follows:

	1st Quarter		Full Year
Oil and gas production, reported	255 – 278 MMCFE/d		253 – 276 MMCFE/d
Lease operating expense	$1.40 – $1.45/MCFE		$1.33 – $1.38/MCFE
Transportation expense	$0.18 – $0.23/MCFE		$0.20 – $0.25/MCFE
Production taxes, as a percentage of pre-hedge oil & gas revenue		7%		7%

General and admin. – cash	$0.47 – $0.50/MCFE		$0.51 – $0.54/MCFE
General and admin. – cash NPP	$0.22 – $0.24/MCFE		$0.22 – $0.24/MCFE
General and admin. – non-cash	$0.15 – $0.17/MCFE		$0.18 – $0.20/MCFE
General and admin. – TOTAL	$0.84 – $0.91/MCFE		$0.91 – $0.98/MCFE

Depreciation, depletion, & amort.	$2.95 – $3.15/MCFE		$2.90 – $3.10/MCFE
Non-cash interest	$	3.3 MM	$	13.5 MM
Effective tax rate		37%		37%

Production guidance for 2010 is unchanged from the information that was provided in the press release provided December 16, 2010. As reported in that release, production is anticipated to decline sequentially in the first half of 2010 due primarily to previously

announced divestitures, which results in higher per unit costs for costs that have a larger component of fixed costs.

Beginning with this press release, the Company is breaking down its general and administrative expense into three components. The G&A – cash line item is for items such as salaries, office, and general corporate expenses that will be paid in cash and that the Company can be reasonably expected to control and forecast. The G&A – cash NPP line relates to cash payments from St. Mary’s legacy Net Profits Plan. These payments are tied to the net revenues generated by properties in associated pools. Over time the proved reserves associated with these profit pools will produce out and payments from this program can be expected to go down directionally over time, absent the impact of commodity prices. Net revenues are directly related to commodity prices, which causes this line item to be difficult to forecast with a high degree of accuracy. The G&A – non-cash line is related to the amortization of stock compensation. St. Mary’s current long-term equity incentive program began in 2008 and involves awards that vest over three years. Each annual award to employees for the last two years has resulted in a new layer of stock compensation that amortizes over a three year life for the respective grant. With the 2010 annual award, a third layer will be added for G&A stock compensation. Going forward there will be three grant years amortizing through the income statement since the expense related to future awards will be offset by awards from prior year awards becoming fully amortized after three years.

A summary of the Company’s current hedge position is included in the appendix in the investor relations presentation that will supplement the Company’s earnings call schedule for February 23, 2010. The presentation can be found in the Investor Relations section of the Company’s website at stmaryland.com.

EARNINGS CALL INFORMATION

The Company has scheduled a teleconference to discuss the fourth quarter results on February 23, 2010, at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). The call participation number is 877-265-4451 and the conference number is 50355324. An audio replay of the call will be available approximately two hours after the call at 800-642-1687, conference number 50355324. International participants can dial 702-928-6464 to take part in the conference call and can access a replay of the call at 706-645-9291, conference number 50355324. Replays can be accessed through March 9, 2010.

In addition, the call will be webcast live and can be accessed at St. Mary’s web site at stmaryland.com. An audio recording of the conference call will be available at that site through March 9, 2010.

A presentation to be referred to during the earnings call will be available on the home page of St. Mary’s website at stmaryland.com prior to the earnings call.

INFORMATION ABOUT FORWARD LOOKING STATEMENTS

This release contains forward looking statements within the meaning of securities laws, including forecasts and projections. The words “will,” “believe,” “budget,” “plan,” “intend,” “estimate,” “forecast,” and “expect” and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, which may cause St. Mary’s actual results to differ materially from results expressed or implied by the forward looking statements. These risks include such factors as the volatility and level of oil and natural gas prices, the uncertain nature of the expected benefits from the acquisition and divestiture of oil and gas properties, the pending nature of reported divestiture plans for certain non-core oil and gas properties as well as the ability to complete divestiture transactions and the uncertain nature of the amount of proceeds that may be received from divestitures, uncertainties inherent in projecting future rates of production from drilling activities and acquisitions, the ability of purchasers of production to pay for those sales, the availability of debt and equity financing, the ability of the banks in the Company’s credit facility to fund requested borrowings, the ability of hedge counterparties to settle hedges in favor of the Company, the imprecise nature of estimating oil and gas reserves, the availability of additional economically attractive exploration, development, and property acquisition opportunities for future growth and any necessary financings, unexpected drilling conditions and results, unsuccessful exploration and development drilling, drilling and operating service availability, the risks associated with the Company’s hedging strategy, and other such matters discussed in the “Risk Factors” section of St. Mary’s 2009 Annual Report on Form 10-K, which is anticipated to be filed on or about February 23, 2010. Although St. Mary may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by securities laws.

ABOUT THE COMPANY

St. Mary Land & Exploration Company is an independent energy company engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil. St. Mary routinely posts important information about the Company on its website. For more information about St. Mary, please visit its website at stmaryland.com.

ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2009


Production Data	For the Three Months					For the Years
	Ended December 31,					Ended December 31,
	2009		2008		Percent Change	2009		2008		Percent Change

Average realized sales price, before hedging:
Oil (per Bbl)	$	68.98	$	50.17	37%	$	54.40	$	92.99	-41%
Gas (per Mcf)		4.88		5.30	-8%		3.82		8.60	-56%

Average realized sales price, net of hedging:
Oil (per Bbl)	$	64.43	$	55.63	16%	$	56.74	$	75.59	-25%
Gas (per Mcf)		6.07		7.09	-14%		5.59		8.79	-36%

Production:
Oil (MMBbls)		1.5		1.7	-12%		6.3		6.6	-4%
Gas (Bcf)		17.1		19.7	-13%		71.1		74.9	-5%
BCFE (6:1)		26.1		30.0	-13%		109.1		114.6	-5%

Daily production:
Oil (MBbls per day)		16.4		18.7	-12%		17.3		18.1	-4%
Gas (MMcf per day)		185.3		213.8	-13%		194.8		204.7	-5%
MMCFE per day (6:1)		284.0		326.0	-13%		298.8		313.1	-5%

Margin analysis per MCFE:
Average realized sales price, before hedging	$	7.18	$	6.35	13%	$	5.65	$	10.99	-49%

Average realized sales price, net of hedging		7.69		7.84	-2%		6.94		10.11	-31%
Lease operating expense		1.31		1.59	-18%		1.33		1.46	-9%
Transportation		0.20		0.20	0%		0.19		0.19	0%
Production taxes		0.51		0.39	31%		0.37		0.71	-48%
General and administrative		0.80		0.41	95%		0.70		0.69	1%
Operating margin	$	4.87	$	5.25	-7%	$	4.35	$	7.06	-38%
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion	$	2.88	$	3.18	-9%	$	2.79	$	2.74	2%

ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2009


NOTE: On January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 470-20, “Debt with Conversion and Other Options” (“ASC Topic
470") required retrospective application. As a result, prior period balances presented have been adjusted to reflect the period-specific effects of applying
ASC Topic 470

Consolidated Statements of Operations
(In thousands, except per share amounts)	For the Three Months						For the Years
	Ended December 31,						Ended December 31,
		2009			2008			2009			2008
				(As adjusted)						(As adjusted)
Operating revenues and other income:
Oil and gas production revenue	$	187,606		$	190,499		$	615,953		$	1,259,400
Realized oil and gas hedge gain (loss)		13,418			44,741			140,648			(101,096	)
Marketed gas system revenue		16,977			11,935			58,459			77,350
Gain on divestiture activity		22,076			9,494			11,444			63,557
Other revenue		1,919			1,500			5,697			2,090
Total operating revenues and other income		241,996			258,169			832,201			1,301,301

Operating expenses:
Oil and gas production expense		52,872			65,530			206,800			271,355
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion		75,140			95,260			304,201			314,330
Exploration		13,414			17,743			62,235			60,121
Impairment of proved properties		21,630			292,100			174,813			302,230
Abandonment and impairment of unproved properties		25,153			34,754			45,447			39,049
Impairment of materials inventory		774			-			14,223			-
Impairment of goodwill		-			9,452			-			9,452
General and administrative		20,687			12,354			76,036			79,503
Bad debt expense (recovery)		(5,189	)		143			(5,189	)		16,735
Change in Net Profits Plan liability		6,963			(80,941	)		(7,075	)		(34,040	)
Marketed gas system expense		16,235			11,241			57,587			72,159
Unrealized derivative (gain) loss		3,218			(12,011	)		20,469			(11,209	)
Other expense		1,065			1,260			13,489			10,415
Total operating expenses		231,962			446,885			963,036			1,130,100

Income (loss) from operations		10,034			(188,716	)		(130,835	)		171,201

Nonoperating income (expense):
Interest income		10			90			227			485
Interest expense		(7,532	)		(6,088	)		(28,856	)		(26,950	)

Income (loss) before income taxes		2,512			(194,714	)		(159,464	)		144,736
Income tax benefit (expense)		(1,522	)		67,622			60,094			(57,388	)

Net income (loss)	$	990		$	(127,092	)	$	(99,370	)	$	87,348

Basic weighted-average common shares outstanding		62,565			62,212			62,457			62,243

Diluted weighted-average common shares outstanding		64,113			62,212			62,457			63,133

Basic net income (loss) per common share	$	0.02		$	(2.04	)	$	(1.59	)	$	1.40

Diluted net income (loss) per common share	$	0.02		$	(2.04	)	$	(1.59	)	$	1.38

ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2009


Consolidated Balance Sheets
(In thousands, except share amounts)	December 31,			December 31,
ASSETS	2009			2008
				(As adjusted)
Current assets:
Cash and cash equivalents	$	10,649		$	6,131
Short-term investments		-			1,002
Accounts receivable, net of allowance for doubtful accounts
of $- in 2009 and $16,788 in 2008		116,136			157,690
Refundable income taxes		32,773			13,161
Prepaid expenses and other		14,259			22,161
Derivative asset		30,295			111,649
Deferred income taxes		4,934			-
Total current assets		209,046			311,794

Property and equipment (successful efforts method), at cost:
Land		1,371			1,350
Proved oil and gas properties		2,797,341			2,969,722
Less - accumulated depletion, depreciation, and amortization		(1,053,518	)		(947,207	)
Unproved oil and gas properties, net of impairment allowance
of $66,570 in 2009 and $42,945 in 2008		132,370			168,817
Wells in progress		65,771			90,910
Materials inventory, at lower of cost or market		24,467			40,455
Oil and gas properties held for sale less accumulated depletion,
depreciation, and amortization		145,392			1,827
Other property and equipment, net of accumulated depreciation
of $14,550 in 2009 and $13,848 in 2008		14,404			13,458
		2,127,598			2,339,332

Other noncurrent assets:
Derivative asset		8,251			21,541
Restricted cash subject to Section 1031 Exchange		-			14,398
Other noncurrent assets		16,041			10,182
Total other noncurrent assets		24,292			46,121

Total Assets	$	2,360,936		$	2,697,247

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable and accrued expenses	$	236,242		$	254,811
Derivative liability		53,929			501
Deposit associated with oil and gas properties held for sale		6,500			-
Deferred income taxes		-			41,289
Total current liabilities		296,671			296,601

Noncurrent liabilities:
Long-term credit facility		188,000			300,000
Senior convertible notes, net of unamortized
discount of $20,598 in 2009, and $28,787 in 2008		266,902			258,713
Asset retirement obligation		60,289			108,755
Asset retirement obligation associated with oil and gas properties held for sale		18,126			238
Net Profits Plan liability		170,291			177,366
Deferred income taxes		308,189			354,328
Derivative liability		65,499			27,419
Other noncurrent liabilities		13,399			11,318
Total noncurrent liabilities		1,090,695			1,238,137

Commitments and contingencies

Stockholders' equity:
Common stock, $0.01 par value: authorized - 200,000,000 shares;
issued: 62,899,122 shares in 2009 and 62,465,572 shares in 2008;
outstanding, net of treasury shares: 62,772,229 shares in 2009
and 62,288,585 shares in 2008		629			625
Additional paid-in capital		160,516			141,283
Treasury stock, at cost: 126,893 shares in 2009 and 176,987 shares in 2008		(1,204	)		(1,892	)
Retained earnings		851,583			957,200
Accumulated other comprehensive income (loss)		(37,954	)		65,293
Total stockholders' equity		973,570			1,162,509

Total Liabilities and Stockholders' Equity	$	2,360,936		$	2,697,247

ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2009


Consolidated Statements of Cash Flows
(In thousands)	For the Three Months						For the Years
	Ended December 31,						Ended December 31,
	2009			2008			2009			2008
Cash flows from operating activities:				(As adjusted)						(As adjusted)

Net income (loss)	$	990		$	(127,092	)	$	(99,370	)	$	87,348
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Gain on divestiture activities		(22,076	)		(9,494	)		(11,444	)		(63,557	)
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion		75,140			95,260			304,201			314,330
Exploratory dry hole expense		2,961			240			7,810			6,823
Impairment of proved properties		21,630			292,100			174,813			302,230
Abandonment and impairment of unproved properties		25,153			34,754			45,447			39,049
Impairment of materials inventory		774			-			14,223			-
Impairment of goodwill		-			9,452			-			9,452
Stock-based compensation expense*		5,787			4,335			18,765			14,812
Bad debt expense (recovery)		(5,189	)		143			(5,189	)		16,735
Change in Net Profits Plan liability		6,963			(80,941	)		(7,075	)		(34,040	)
Unrealized derivative (gain) loss		3,218			(12,011	)		20,469			(11,209	)
Loss related to hurricanes		28			-			8,301			6,980
Loss on insurance settlement		-			696			-			2,296
Amortization of debt discount and deferred financing costs		3,291			2,402			12,213			9,344
Deferred income taxes		29,347			(61,216	)		(39,735	)		38,164
Plugging and abandonment		(14,286	)		(7,813	)		(26,396	)		(9,168	)
Other		1,950			7,291			3,382			3,875
Changes in current assets and liabilities:
Accounts receivable		(12,101	)		25,128			46,743			(14,327	)
Refundable income taxes		(29,952	)		(8,578	)		(19,612	)		(12,228	)
Prepaid expenses and other		2,034			(3,533	)		(6,626	)		(1,504	)
Accounts payable and accrued expenses		(12,608	)		(47,111	)		(4,814	)		(12,348	)
Excess income tax benefit from the exercise of stock options		-			(3,586	)		-			(13,867	)
Net cash provided by operating activities		83,054			110,426			436,106			679,190

Cash flows from investing activities:
Proceeds from insurance settlement		1,453			-			16,789			-
Proceeds from sale of oil and gas properties		38,761			23,664			39,898			178,867
Capital expenditures		(86,787	)		(251,431	)		(379,253	)		(746,586	)
Acquisition of oil and gas properties		(18	)		1,610			(76	)		(81,823	)
Receipts from restricted cash		-			-			14,398			-
Deposits to restricted cash		-			(14,398	)		-			(14,398	)
Receipts from short-term investments		-			9			1,002			170
Other		3,150			-			3,150			(9,984	)
Net cash used in investing activities		(43,441	)		(240,546	)		(304,092	)		(673,754	)

Cash flows from financing activities:
Proceeds from credit facility		174,000			1,739,500			2,072,500			2,571,500
Repayment of credit facility		(221,000	)		(1,609,500	)		(2,184,500	)		(2,556,500	)
Debt issuance costs related to credit facility		-			-			(11,074	)		-
Excess income tax benefit from the exercise of stock options		-			3,586			-			13,867
Proceeds from sale of common stock		1,931			561			3,110			11,888
Repurchase of common stock		-			-			-			(77,202	)
Dividends paid		(3,127	)		(3,110	)		(6,247	)		(6,186	)
Other		(1,285	)		(182	)		(1,285	)		(182	)
Net cash provided by (used in) financing activities		(49,481	)		130,855			(127,496	)		(42,815	)

Net change in cash and cash equivalents		(9,868	)		735			4,518			(37,379	)
Cash and cash equivalents at beginning of period		20,517			5,396			6,131			43,510
Cash and cash equivalents at end of period	$	10,649		$	6,131		$	10,649		$	6,131

* Stock-based compensation expense is a component of exploration expense and general and administrative expense on the consolidated statements of
operations. For the three months ended December 31, 2009,and 2008, respectively, approximately $1.9 million and $2.0 million of stock based compensation was
included in exploration expense. For the years ended December 31, 2009, and 2008, respectively, approximately $6.3 million and $5.8 million of stock-based
compensation expense was included in exploration expense. For the three months ended December 31, 2009, and 2008, respectively, approximately $3.9 million
and $2.3 million of stock-based compensation was included in general and administrative expense. For the years ended December 31, 2009, and 2008,
respectively approximately $12.5 million and $9.0 million of stock-based compensation expense was included in general and administrative expense.

ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2009


Adjusted Net Income
(In thousands, except per share data)

Reconciliation of Net Income (Loss) (GAAP)	For the Three Months						For the Years
to Adjusted Net Income (Non-GAAP):	Ended December 31,						Ended December 31,
	2009			2008			2009			2008
				(As adjusted)						(As adjusted)

Reported Net Income (Loss) (GAAP)	$	990		$	(127,092	)	$	(99,370	)	$	87,348

Adjustments net of tax:
Change in Net Profits Plan liability		4,338			(52,831	)		(4,409	)		(20,543	)
Unrealized derivative (gain) loss		2,005			(7,840	)		12,755			(6,765	)
Gain on divestiture activities		(13,753	)		(6,197	)		(7,131	)		(38,357	)
Bad debt expense (recovery) associated with Sem Group, L.P.		(3,143	)		(3	)		(3,143	)		10,039
Loss related to hurricanes (1)		17			-			5,173			4,212
Loss on insurance settlement		-			454			-			1,386

Adjusted Net Income (Loss), before impairment adjustments		(9,546	)		(193,509	)		(96,125	)		37,320

Non-cash impairments net of tax:
Impairment of proved properties		13,475			190,657			108,935			182,395
Abandonment and impairment of unproved properties		15,670			22,684			28,320			23,566
Impairment of goodwill		-			6,169			-			5,704
Impairment of materials inventory		482			-			8,863			-
Adjusted Net Income, non-recurring items
& non-cash impairments (Non-GAAP) (2)	$	20,081		$	26,001		$	49,993		$	248,985

Adjusted Net Income Per Share (Non-GAAP)
Basic	$	0.32		$	0.42		$	0.80		$	4.00
Diluted	$	0.31		$	0.42		$	0.80		$	3.94

Average Number of Shares Outstanding
Basic		62,565			62,212			62,457			62,243
Diluted		64,113			62,212			62,457			63,133


(1) The loss related to hurricanes is included within line item other expense on the consolidated statements of operations.

(2) Adjusted net income is calculated as net income (loss) adjusted for significant non-cash and non-recurring items. Non-cash charges and adjustments include
change in the Net Profits Plan liability, unrealized derivative (gain) loss, impairment of proved properties, abandonment and impairment of unproved
properties, impairment of goodwill, and impairment of materials inventory. Non-recurring items include gain on divestiture activities, loss related to
hurricanes, loss on insurance settlement, and bad debt expense (recovery) associated with Sem Group, L.P. The non-GAAP measure of adjusted net income
is presented because management believes it provides useful additional information to investors for analysis of St. Mary’s fundamental business on a
recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation,
comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published
research of industry research analysts in making investment decisions. Adjusted net income should not be considered in isolation or as a substitute for net
income, income from operations, cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under
GAAP. Since adjusted net income excludes some, but not all, items that affect net income and may vary among companies, the adjusted net income amounts
presented may not be comparable to similarly titled measures of other companies.

Discretionary Cash Flow
(In thousands)

Reconciliation of Net Cash Provided by Operating Activities		For the Three Months					For the Years
(GAAP) to Discretionary Cash Flow (Non-GAAP):		Ended December 31,					Ended December 31,
		2009			2008		2009			2008
					(As adjusted)
Net cash provided by operating activities (GAAP)	$	83,054		$	110,426	$	436,106		$	679,190

Changes in current assets and liabilities		52,627			37,680		(15,691	)		54,274

Exploration		13,414			17,743		62,235			60,121
Less: Exploratory dry hole expense		(2,961	)		(240)		(7,810	)		(6,823	)
Less: Stock-based compensation expense included in exploration		(1,917	)		(1,992)		(6,314	)		(5,799	)

Discretionary cash flow (Non-GAAP) (3)	$	144,217		$	163,617	$	468,526		$	780,963


(3) Beginning in the third quarter of 2009 the Company changed its definition of discretionary cash flow. Prior periods have been conformed to the current
definition and the change in the definition did not result in a material variance to results under the prior definiton. Discretionary cash flow is computed as
net cash provided by operating activities adjusted for changes in current assets and liabilities and exploration, less exploratory dry hole expense, and
stock-based compensation expense included in exploration. The non-GAAP measure of discretionary cash flow is presented because management believes
that it provides useful additional information to investors for analysis of St. Mary's ability to internally generate funds for exploration, development, and
acquisitions. In addition, discretionary cash flow is widely used by professional research analysts and others in the valuation, comparison, and investment
recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research
analysts in making investment decisions. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from
operations, net cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since
discretionary cash flow excludes some, but not all items that affect net income and net cash provided by operating activities and may vary among
companies, the discretionary cash flow amounts presented may not be comparable to similarly titled measures of other companies. See the consolidated
statements of cash flows herein for more detailed cash flow information.

ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2009


Information on Reserves and Costs Incurred

Costs incurred in oil and gas producing activities:
	For the Year Ended
	December 31,
	2009
Development costs	$	223,108
Exploration costs		154,122
Acquisitions:
Proved properties		76
Unproved properties - acquisitions of
proved properties (4)		-
Unproved properties - other		41,677
Total, including asset retirement obligation (5) (6)	$	418,983

(4) Represents the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties.
(5) Includes capitalized interest of $1.9 million for the year ended December 31, 2009.
(6) Includes amounts relating to estimated asset retirement obligations of $(805,000) for the year ended December 31, 2009.

Proved oil and gas reserve quantities:
	For the Year Ended
	December 31, 2009
	Oil or Condensate			Gas			Equivalents			Proved Developed			Proved Undeveloped
	(MMBbl)			(Bcf)			(BCFE)			(BCFE)			(BCFE)
Total proved reserves
Beginning of year		51.4			557.4			865.5			715.8			149.7
Revisions of previous estimate		4.5			(76.8	)		(49.6	)		(23.8	)		(25.8	)
Discoveries and extensions		3.4			51.9			72.3			38.0			34.3
Infill reserves in an existing proved field		1.2			29.9			37.3			28.0			9.3
Purchases of minerals in place		-			-			-			-			-
Sales of reserves		(0.4	)		(41.8	)		(44.2	)		(37.2	)		(7.0	)
Production		(6.3	)		(71.1	)		(109.1	)		(109.1	)		-
Conversions											18.6			(18.6	)
End of year		53.8			449.5			772.2			630.3			141.9

PV-10 value (in millions)							$	1,284.1		$	1,253.1		$	31.0

Proved developed reserves
Beginning of year		47.1			433.2			715.8
End of year		48.0			342.0			630.3


Finding Cost and Reserve Replacement Ratios: (7)

Finding Costs in $ per MCFE
Drilling, excluding revisions	$	3.44
Drilling, including revisions	$	6.29
All-in	$	6.99

Reserve Replacement Ratios
Drilling, excluding revisions		100%
Drilling, including revisions		55%
All-in		55%

(7) Finding costs and reserve replacement ratios are common metrics used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. The metrics are easily calculated from information provided in the sections "Costs incurred in oil and gas producing activities" and "Proved oil and gas reserve quantities" above. Finding cost provides some information as to the cost of adding proved reserves from various activities. Reserve replacement provides information related to how successful a company is at growing its proved reserve base. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in "Costs incurred in oil and gas producing activities." The Company uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

Finding Costs Definitions:
> Drilling, excluding revisions - numerator defined as the sum of development costs and exploration costs divided by a denominator defined as the sum of discoveries and extensions and infill reserves in an existing proved field. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> Drilling, including revisions - numerator defined as the sum of development costs and exploration costs divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and revisions. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> All-in - numerator defined as total costs incurred, including asset retirement obligation divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and revisions. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.

Reserve Replacement Ratio Definitions:
> Drilling, excluding revisions - numerator defined as the sum of discoveries and extensions and infill reserves in an existing proved field divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> Drilling, including revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> All-in - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.