8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

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

Date of Report (Date of earliest event reported)

February 21, 2008 (February 21, 2008)

St. Mary Land & Exploration Company

(Exact name of registrant as specified in its charter)

Delaware	001-31539	41-0518430
(State or other jurisdiction	(Commission	(I.R.S. Employer
of incorporation)	File Number)	Identification No.)

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

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

Not applicable

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2.):

[_] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[_] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[_] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[_] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02                      Results of Operations and Financial Condition.

In accordance with General Instruction B.2. of Form 8-K, the following information, including Exhibits 99.1 and 99.2, shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”) or otherwise subject to the liabilities of that section, nor shall such information and Exhibits be deemed incorporated by reference in any filing under the Securities Act of 1933 or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

On February 21, 2008, St. Mary Land & Exploration Company (the “Company”) issued a press release announcing its results of operations for the full year and fourth quarter of 2007.  A copy of the press release is furnished as Exhibit 99.1 to this report.  As indicated in the press release, the Company has scheduled a related full year and fourth quarter 2007 earnings teleconference call for February 22, 2008, at 8:00 a.m. (Mountain Time).  The teleconference call is publicly accessible, and the press release includes instructions as to when and how to access the teleconference and the location on the Company’s web site where the teleconference information will be available.

The press release contains information about the Company’s discretionary cash flow, which is a “non-GAAP financial measure” under SEC rules.  The press release also presents information about the Company’s net cash provided by operating activities, which is the most directly comparable GAAP financial measure, and contains a reconciliation of discretionary cash flow to net cash provided by operating activities for the periods presented, a presentation of other cash flow information under GAAP, and a statement indicating why management believes that the presentation of discretionary cash flow provides useful information to investors.

The press release contains information about the Company’s adjusted net income, which is a “non-GAAP financial measure” under SEC rules.  The press release also presents information about the Company’s net income, which is the most directly comparable GAAP financial measure, and contains a reconciliation of net income to adjusted net income for the periods presented and a statement indicating why management believes that the presentation of adjusted net income provides useful information to investors.

Additionally, on February 21, 2008, the Company issued a separate press release providing an update of its operations during the fourth quarter of 2007 and first quarter of 2008, and an update of its significant drilling programs as of December 31, 2007.  A copy of the press release is furnished as Exhibit 99.2 to this report.

Item 9.01                      Financial Statements and Exhibits.

(d)	Exhibits.	The following exhibits are furnished as part of this report:
	Exhibit 99.1	Press release of St. Mary Land & Exploration Company dated February 21, 2008 - Results for Full Year and Fourth Quarter 2007.
	Exhibit 99.2	Press release of St. Mary Land & Exploration Company dated February 21, 2008 - Operations Update

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

			ST. MARY LAND & EXPLORATION COMPANY
Date:	February 21, 2008	By:	/s/ DAVID W. HONEYFIELD
			David W. Honeyfield
			Senior Vice President-Chief Financial Officer and Secretary

EX-99.1

Exhibit 99.1

               For Information

            Brent A. Collins

            303-861-8140

FOR IMMEDIATE RELEASE

ST. MARY REPORTS RESULTS FOR THE

FULL YEAR AND FOURTH QUARTER 2007

DENVER, February 21, 2008– St. Mary Land & Exploration Company (NYSE: SM) today reports net income for the year ended 2007 of $189.7 million, or $2.94 per diluted share.

Tony Best, President and CEO, commented, “St. Mary had another solid year operationally and financially in 2007.  Production for the fourth quarter and full year both were Company records for their respective periods.  We posted strong earnings and cash flow numbers for the year, which reflects 16% annual production growth and strong commodity prices.  Our operating margins are strong as a result of our significant oil exposure and we are generating significant cash flow.  We enter 2008 on solid financial footing as we execute our business plan.”

FULL YEAR RESULTS

St. Mary announces 2007 earnings of $189.7 million or $2.94 per diluted share.  Earnings for 2006 were $190.0 million or $2.94 per diluted share.  Adjusted net income, which adjusts for significant non-cash and non-recurring items, was $222.2 million or $3.44 per diluted share for 2007 compared to $205.4 million or $3.18 per diluted share for 2006.  Discretionary cash flow increased to $636.9 million in 2007 from $525.1 million in the preceding year, an increase of 21 percent.  Net cash provided by operating activities increased to $630.8 million in 2007 from $467.7 million in 2006.

Revenues for 2007 were $990.1 million compared to $787.7 million in 2006.  Oil and gas production for the year averaged 294.5 million cubic feet of gas equivalent per day (MMCFED), a new annual record for the Company.  This was an increase of 16% from 254.2 MMCFED in 2006.  The Company continued to enjoy strong operating margins during the year.  In 2007, the operating margin increased 5% to $6.12 per MCFE, compared to $5.85 per MCFE in 2006.

Average realized prices, inclusive of hedging activities, were $7.63 per Mcf and $62.60 per barrel during 2007.  These were 4% and 11% higher, respectively, than the realized prices for the prior year.  Average prices, excluding hedging activities, were $6.74 per Mcf and $67.56 per barrel in 2007, which were 2% and 14% higher, respectively, than last year.  The Company’s natural gas realizations continue to benefit from high Btu gas in several of our regions.  This higher Btu gas is being processed to extract the

natural gas liquids (NGLs) that exist in the production stream.  The price for NGLs trends directionally with crude oil prices, and accordingly the price for NGLs has increased with the rise in oil prices in recent months.

Total lease operating and transportation expense was up 6% between 2007 and 2006 on a per MCFE basis.  Cost pressures related to fluid disposal, well maintenance, and trucking, as well as higher labor costs explain the majority of the difference.  The increase in depletion and depreciation expense between the two periods reflects the higher finding cost environment experienced by the industry in recent years to acquire and develop properties.  Year over year, the overall increase in exploration expense is the result of increased levels of personnel associated with exploration activities.  General and administrative expense increased significantly, both in absolute dollars and on a per MCFE basis, due to costs associated with increased headcount and higher payments from the Net Profits Interest Bonus Plan (Net Profits Plan).  The large increase in the non-cash expense related to the change in the Net Profits Plan liability is due to higher commodity prices and a decrease in the discount rate used to determine the liability.

FOURTH QUARTER 2007 RESULTS

Earnings for the fourth quarter of 2007 were $32.9 million or $0.51 per diluted share, compared to $43.5 million or $0.69 per diluted share for the same period in the prior year.  Adjusted net income for the quarter was $64.4 million or $1.00 per diluted share, versus $49.1 million or $0.77 per diluted share for the fourth quarter of 2006.  Discretionary cash flow increased to $176.4 million for the fourth quarter of 2007 from $126.4 million in the same period of the preceding year.  Net cash provided by operating activities increased to $156.8 million for the fourth quarter 2007 from $150.2 million in the same period in 2006.

Revenues forthe quarter were $275.2 million compared to $202.7 million for the same period in 2006.  Quarterly production set a new record during the fourth quarter of 2007.  Oil and gas production for the quarter increased 14% year over year to an average 310.2 MMCFED in the fourth quarter of 2007 from 272.5 MMCFED in the fourth quarter of 2006.  St. Mary’s operating margin increased to $6.53 per MCFE in the quarter, up 18% from $5.54 per MCFE in the fourth quarter of 2006.

Average realized prices, inclusive of hedging activities, were $7.80 per Mcf and $69.99 per barrel in the fourth quarter of 2007, which were up 8% and 36%, respectively, from the same period a year ago.  Average prices, excluding hedging activities, were $7.07 per Mcf and $84.63 per barrel during the quarter.  These were 13% and 62% higher, respectively, than the fourth quarter of 2006.

Oil and gas production expense was up 7% between the fourth quarters of 2007 and 2006 on a per MCFE basis.  The Company continues to be impacted by pricing pressure for service related to the production and maintenance of oil properties, as well as higher labor costs.  The increase in depletion and depreciation expense between the two periods reflects the higher finding cost environment experienced by the industry in

2

recent years to acquire and develop properties.  General and administrative expense came in below guidance for the quarter as a result of lowering the cash and restricted stock unit bonuses for the year.  Year over year, general and administrative expense increased as a result of increased headcount and higher Net Profits Plan payments.  There was a significant increase in the expense recognized in the fourth quarter of 2007 related to the change in the Net Profits Plan liability as a result of higher oil prices and a decrease in the discount rate used to determine the liability.

YEAR-END 2007 FINANCIAL STANDING

As of the end of 2007, St. Mary had total long-term debt of $572.5 million, comprised of $287.5 million in 3.50% Senior Convertible Notes and $285.0 million drawn under our existing long-term credit facility.  The Company’s debt to book capitalization ratio as of December 31, 2007 was 40%.  Subsequent to year-end, the previously announced divestiture of non-strategic oil and gas properties closed on January 31, 2008 for $131.1 million before commission costs.  Proceeds from this sale were used to pay down borrowings under our existing credit facility resulting in a pro forma debt to book capitalization ratio of approximately 34%.  Currently, the Company has a borrowing base of $1.25 billion and commitment amount of $500 million related to the credit facility.

NON-GAAP FINANCIAL MEASURES

Adjusted net income and discretionary cash flow are non-GAAP financial measures – please refer to the respective reconciliation for the nearest comparable GAAP financial measure in the Financial Highlights section at the end of this release, which contains explanations as to how these non-GAAP measures are computed and why the Company believes these non-GAAP measures are meaningful.

EARNINGS CALL INFORMATION

The Company has scheduled a teleconference call to discuss fourth quarter and full year 2007 earnings results on February 22, 2008, at 8:00 am (Mountain Time).  The call participation number is 888-424-5231.  A digital recording of the conference call will be available two hours after the completion of the call, 24 hours per day through March 7, 2008, at 800-642-1687, conference number 30812009.  International participants can dial 706-634-6088 to take part in the conference call and can access a replay of the call at 706-645-9291, conference number 30812009.  In addition, the call will be broadcast live through St. Mary’s website at  www.stmaryland.com and the earnings press release and financial highlights will be available before the call.  An audio recording of the conference call will be available at that site through March 7, 2008.

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ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2007
(Unaudited)
Production Data	For the Three Months							For the Years
	Ended December 31,							Ended December 31,
	2007			2006			Percent Change	2007			2006			Percent Change
Average realized sales price, before hedging:
Oil (per Bbl)	$	84.63		$	52.39		62%	$	67.56		$	59.33		14%
Gas (per Mcf)	$	7.07		$	6.25		13%	$	6.74		$	6.58		2%
Average realized sales price, net of hedging:
Oil (per Bbl)	$	69.99		$	51.57		36%	$	62.60		$	56.60		11%
Gas (per Mcf)	$	7.80		$	7.20		8%	$	7.63		$	7.37		4%
Production:
Oil (MMBbls)		1.7			1.6		6%		6.9			6.1		14%
Gas (Bcf)		18.3			15.5		19%		66.1			56.4		17%
BCFE (6:1)		28.5			25.1		14%		107.5			92.8		16%
Daily production:
Oil (MBbls per day)		18.5			17.4		6%		18.9			16.6		14%
Gas (MMcf per day)		199.1			168.0		19%		181.0			154.7		17%
MMCFE per day (6:1)		310.2			272.5		14%		294.5			254.2		16%
Margin analysis per MCFE:
Average realized sales price, before hedging	$	9.59		$	7.20		33%	$	8.48		$	7.88		8%
Average realized price, net of hedging	$	9.18		$	7.73		19%	$	8.71		$	8.18		6%
Lease operating expense and transportation		1.45			1.36		7%		1.45			1.37		6%
Production taxes		0.67			0.51		31%		0.58			0.54		7%
General and administrative		0.53			0.32		66%		0.56			0.42		33%
Operating margin	$	6.53		$	5.54		18%	$	6.12		$	5.85		5%
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion	$	2.27		$	1.77		28%	$	2.12		$	1.67		27%
Information on Reserves and Costs Incurred
Proved oil and gas reserve quantities:
	For the Year							For the Year
	Ended December 31, 2007							Ended December 31, 2006
	Oil or Condensate			Gas				Oil or Condensate			Gas
Developed and undeveloped:
Beginning of year		74,195			482,475				62,903			417,075
Revisions of previous estimate		5,238			9,489				524			10,946
Discoveries and extensions		1,166			28,483				857			36,723
Infill reserves in an existing proved field		4,592			69,090				4,131			49,107
Purchases of minerals in place		567			91,374				11,857			28,030
Sales of reserves		(4	)		(1,400	)			(20	)		(2,958	)
Production		(6,907	)		(66,061	)			(6,057	)		(56,448	)
End of year		78,847			613,450				74,195			482,475
Proved developed reserves as of the end of the year		68,277			426,627				61,519			358,477
Costs incurred in oil and gas producing activities:
	For the Years Ended December 31,
	2007			2006
Development costs	$	591,013		$	367,546
Exploration		111,470			126,220
Acquisitions:
Proved		161,665			238,400
Unproved		23,495			44,472
Leasing activity		38,436			28,816
Total	$	926,079		$	805,454

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ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2007
(Unaudited)
Consolidated Statements of Operations
(In thousands, except per share amounts)	For the Three Months						For the Years
	Ended December 31,						Ended December 31,
	2007			2006			2007			2006
Operating revenues:
Oil and gas production revenue	$	273,736		$	180,556		$	912,093		$	730,737
Realized oil and gas hedge gain (loss)		(11,676	)		13,368			24,484			28,176
Marketed gas system revenue		13,909			8,149			45,149			20,936
Gain (loss) on sale of proved properties		(367	)		(323	)		(367	)		6,910
Other revenue		(355	)		942			8,735			942
Total operating revenues		275,247			202,692			990,094			787,701
Operating expenses:
Oil and gas production expense		60,590			47,100			218,208			176,590
Depletion, depreciation, amortization,
and asset retirement obligation liability accretion		64,919			44,404			227,596			154,522
Exploration* (4)		16,030			16,017			58,686			51,889
Impairment of proved properties		-			684			-			7,232
Abandonment and impairment of unproved properties		870			933			4,756			4,301
General and administrative* (4)		15,187			7,933			60,149			38,873
Change in Net Profits Plan liability		43,875			6,389			50,823			23,759
Marketed gas system expense		13,031			5,545			42,485			18,526
Unrealized derivative loss		3,234			1,765			5,458			7,094
Other expense		946			2,649			2,522			2,649
Total operating expenses		218,682			133,419			670,683			485,435
Income from operations		56,565			69,273			319,411			302,266
Nonoperating income (expense):
Interest income		134			122			746			1,576
Interest expense		(6,010	)		(3,423	)		(19,895	)		(8,521	)
Income before income taxes		50,689			65,972			300,262			295,321
Income tax expense		(17,815	)		(22,440	)		(110,550	)		(105,306	)
Net income	$	32,874		$	43,532		$	189,712		$	190,015
Basic weighted-average common shares outstanding		63,300			55,480			61,852			56,291
Diluted weighted-average common shares outstanding		64,635			64,886			64,850			65,962
Basic net income per common share	$	0.52		$	0.78		$	3.07		$	3.38
Diluted net income per common share	$	0.51		$	0.69		$	2.94		$	2.94
*  As explained in Note 4 below, due to a change in circumstances the Company adjusted its accounting classification of Net Profits Plan distributions to terminated employees. As a result, distributions to individuals that are no longer employed by the Company from the Net Profits Plan have been fully allocated to general and administrative expense during 2007. Pro forma general and administrative expense (in thousands) reflecting this reclassification is $12,891, $16,266, and $15,805 for the three month periods ended March 31, 2007, June 30, 2007, and September 30, 2007, respectively. Pro forma exploration expense (in thousands) reflecting this reclassification is $19,020, $11,074, and $12,562 for the three months ended March 31, 2007, June 30, 2007, and September 30, 2007, respectively.

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ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2007
(Unaudited)
Consolidated Balance Sheets
(In thousands, except share amounts)	December 31,			December 31,
ASSETS	2007			2006
Current assets:
Cash and cash equivalents	$	43,510		$	1,464
Short-term investments		1,173			1,450
Accounts receivable		159,149			142,721
Refundable income taxes		933			7,684
Prepaid expenses and other		14,129			17,485
Accrued derivative asset		17,836			56,136
Deferred income taxes		33,211			-
Total current assets		269,941			226,940
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties		2,721,229			2,063,911
Less - accumulated depletion, depreciation, and amortization		(804,785	)		(630,051	)
Unproved oil and gas properties, net of impairment allowance
of $10,319 in 2007 and $9,425 in 2006		134,386			100,118
Wells in progress		137,417			97,498
Oil and gas properties held for sale less accumulated depletion,
depreciation, and amortization		76,921			-
Other property and equipment, net of accumulated depreciation
of $11,549 in 2007 and $9,740 in 2006		9,230			6,988
		2,274,398			1,638,464
Noncurrent assets:
Goodwill		9,452			9,452
Accrued derivative asset		5,483			16,939
Other noncurrent assets		12,406			7,302
Total noncurrent assets		27,341			33,693
Total Assets	$	2,571,680		$	1,899,097
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	254,918		$	171,834
Short-term note payable		-			4,469
Accrued derivative liability		97,627			13,100
Deferred income taxes		-			14,667
Deposit associated with oil and gas properties held for sale		10,000			-
Total current liabilities		362,545			204,070
Noncurrent liabilities:
Long-term credit facility		285,000			334,000
Senior convertible notes		287,500			99,980
Asset retirement obligation		96,432			77,242
Asset retirement obligation associated with oil and gas properties held for sale		8,744			-
Net Profits Plan liability		211,406			160,583
Deferred income taxes		257,603			224,518
Accrued derivative liability		190,262			46,432
Other noncurrent liabilities		8,843			8,898
Total noncurrent liabilities		1,345,790			951,653
Stockholders' equity:
Common stock, $0.01 par value: authorized - 200,000,000 shares;
issued:  64,010,832 shares in 2007 and 55,251,733 shares in 2006;
outstanding, net of treasury shares:  63,001,120 shares in 2007
and 55,001,733 shares in 2006		640			553
Additional paid-in capital		170,070			38,940
Treasury stock, at cost:  1,009,712 shares in 2007 and 250,000 shares in 2006		(29,049	)		(4,272	)
Retained earnings		878,652			695,224
Accumulated other comprehensive income (loss)		(156,968	)		12,929
Total stockholders' equity		863,345			743,374
Total Liabilities and Stockholders' Equity	$	2,571,680		$	1,899,097

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ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2007
(Unaudited)
Consolidated Statements of Cash Flows
(In thousands)	For the Three Months						For the Years
	Ended December 31,						Ended December 31,
	2007			2006			2007			2006
Reconciliation of net income to net cash provided
by operating activities:
Net income	$	32,874		$	43,532		$	189,712		$	190,015
Adjustments to reconcile net income to net cash		-			-
provided by operating activities:		-			-
(Gain) loss on insurance settlement		1,097			-			(5,243	)		-
(Gain) loss on sale of proved properties		367			323			367			(6,910	)
Depletion, depreciation, amortization,		-			-
and asset retirement obligation liability accretion		64,919			44,404			227,596			154,522
Exploratory dry hole expense		1,651			6,158			14,365			10,191
Impairment of proved properties		-			7,232			-			7,232
Abandonment and impairment of unproved properties		870			(5,614	)		4,756			4,301
Unrealized derivative loss		3,234			1,765			5,458			7,094
Change in Net Profits Plan liability		43,875			6,389			50,823			23,759
Stock-based compensation expense*		1,489			2,443			10,095			11,422
Deferred income taxes		13,666			10,220			92,955			74,832
Other		(5,329	)		(2,877	)		(10,497	)		(2,479	)
Changes in current assets and liabilities:		-			-
Accounts receivable		(6,349	)		(8,334	)		(6,557	)		22,476
Refundable income taxes		2,164			21,495			6,751			-
Prepaid expenses and other		(8,660	)		(2,838	)		19,375			(17,886	)
Accounts payable and accrued expenses		13,217			26,827			40,769			5,215
Income tax benefit from the exercise of stock options		(2,275	)		(974	)		(9,933	)		(16,084	)
Net cash provided by operating activities		156,810			150,151			630,792			467,700
Cash flows from investing activities:
Proceeds from insurance settlement		(1,116	)		-			5,948			-
Proceeds from sale of oil and gas properties		171			(323	)		495			860
Capital expenditures		(137,637	)		(161,079	)		(637,748	)		(455,056	)
Acquisition of oil and gas properties		(150,233	)		(260,706	)		(182,883	)		(270,639	)
Deposits for acquisition of oil and gas assets		15,310			-			-			-
Deposits to short-term investments available-for-sale		(15	)		-			(1,168	)		-
Receipts from short-term investments available-for-sale		-			25			1,450			25
Other		10,005			12			10,034			91
Net cash used in investing activities		(263,515	)		(422,071	)		(803,872	)		(724,719	)
Cash flows from financing activities:
Proceeds from credit facility		268,086			597,137			822,000			935,137
Repayment of credit facility		(138,086	)		(329,137	)		(871,000	)		(601,137	)
Repayment of short-term note payable		-			-			(4,469	)		-
Proceeds from short-term note payable		-			4,469			-			4,469
Income tax benefit from the exercise of stock options		2,275			974			9,933			16,084
Proceeds from issuance of convertible debt, net of deferred financing costs		(7	)		-			280,657			-
Proceeds from sale of common stock		3,665			1,670			10,007			17,716
Repurchase of common stock		-			-			(25,904	)		(123,108	)
Dividends paid		(3,144	)		(2,745	)		(6,284	)		(5,603	)
Other		186			-			186			-
Net cash provided by financing activities		132,975			272,368			215,126			243,558
Net change in cash and cash equivalents		26,270			448			42,046			(13,461	)
Cash and cash equivalents at beginning of period		17,240			1,016			1,464			14,925
Cash and cash equivalents at end of period	$	43,510		$	1,464		$	43,510		$	1,464
*  Stock-based compensation expense is a component of General and administrative and Exploration on the Consolidated Statements of Operations. For the years ended December 31, 2007, and 2006, $6.9 million and $8.3 million, respectively, of stock-based compensation expense is included in the general and administrative expense and $3.2 million and $3.1 million, respectively, of stock-based compensation expense is included in exploration expense. For the three months ended December 31, 2007, and 2006, $889,000 and $1.8 million, respectively, of stock-based compensation expense is included in general and administrative expense and $600,000 and $656,000, respecteively, is included in exploration expense.

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ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2007
(Unaudited)
Adjusted Net Income
(In thousands, except per share data)
Reconciliation of Net Income (GAAP)	For the Three Months						For the Years
to Adjusted Net Income (Non-GAAP):	Ended December 31,						Ended December 31,
	2007			2006			2007			2006
Reported Net Income (GAAP)	$	32,874		$	43,532		$	189,712		$	190,015
Change in Net Profits Plan liability		43,875			6,389			50,823			23,759
Unrealized derivative loss		3,234			1,765			5,458			7,094
(Gain) loss on sale of proved properties		367			323			367			(6,910	)
(Gain) loss on insurance settlement (1)		1,097			-			(5,243	)		-
Total of Adjustments		48,573			8,477			51,405			23,943
Expense from tax effect on adjustments		(17,071	)		(2,883	)		(18,926	)		(8,538	)
Adjusted Net Income (Non-GAAP) (2)	$	64,376		$	49,126		$	222,191		$	205,420
Adjusted Net Income Per Share (Non-GAAP)
Basic	$	1.02		$	0.89		$	3.59		$	3.65
Diluted	$	1.00		$	0.77		$	3.44		$	3.18
Average Number of Shares Outstanding
Basic		63,300			55,480			61,852			56,291
Diluted		64,635			64,886			64,850			65,962
(1)    Included within line item Other revenue on the Consolidated Statements of Operations.
(2)   Adjusted net income is calculated as net income adjusted for significant non-cash and non-recurring items. Examples of non-cash charges include non-cash changes in the Net Profits Plan liability and unrealized derivative gains and losses. Examples of non-recurring items include gains or losses from sales of properties and insurance settlements. 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, profitablility, 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.

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ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2007
(Unaudited)
Discretionary Cash Flow
(In thousands)
Reconciliation of Net Cash Provided by Operating	For the Three Months									For the Years
Activities (GAAP) to Discretionary Cash Flow (Non-GAAP):	Ended December 31,									Ended December 31,
	2007			2006						2007			2006
Net cash provided by operating activities (GAAP)	$	156,810		$	150,151					$	630,792		$	467,700
Gain (loss) on insurance settlement		(1,097	)		-						5,243			-
Gain (loss) on sale of proved properties		(367	)		(323	)					(367	)		6,910
Exploration (4)		16,030			16,017						58,686			51,889
Less:  Exploratory dry hole expense		(1,651	)		(6,158	)					(14,365	)		(10,191	)
Less:  Stock-based compensation expense included in Exploration		(599	)		-						(3,215	)		-
Other		5,329			2,877						10,497			2,476
Changes in current assets and liabilities		1,903			(36,176	)					(50,405	)		6,279
Discretionary cash flow (Non-GAAP) (3)	$	176,358		$	126,388					$	636,866		$	525,063
Revised Quarterly Discretionary Cash Flow
(In thousands)
Revised reconciliation of Net Cash Provided by Operating	For the Three Months Ended
Activities (GAAP) to Discretionary Cash Flow (Non-GAAP)	March 31,			June 30,			September 30,
	2007			2007			2007
Net cash provided by operating activities (GAAP)	$	126,075		$	156,246		$	191,661
Gain on insurance settlement		-			6,325			15
Gain on sale of proved properties		-			-			-
Exploration  (4)		19,020			11,074			12,562
Less:  Exploratory dry hole expense		(9,569	)		(1,651	)		(1,494	)
Less:  Stock-based compensation expense included in Exploration		(1,004	)		(886	)		(726	)
Other		125			2,571			2,472
Changes in current assets and liabilities		6,835			(13,562	)		(45,581	)
Discretionary cash flow (Non-GAAP) (3)	$	141,482		$	160,117		$	158,909
(3)   Discretionary cash flow is computed as net income plus depreciation, depletion, amortization, asset retirement obligation liability accretion, impairments, deferred taxes, exploration expense, stock-based compensation expense, and non-cash changes in the Net Profits Plan liability less the effect of unrealized derivative (gain) loss. The non-GAAP measure of discretionary cash flow is presented since 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.
4)    As a result of a change in circumstances, a greater portion of distributions from the Net Profits Plan have been classified as general and and administrative expense than in prior years.  This is a result of a greater portion of payments being made to individuals that are no longer employed by the Company.  In 2007, only those distributions related to individuals that are currently employed and are involved with the Company's exploration efforts are classified as exploration expense.  As time has progressed, less of the distribution relates to prospective exploration efforts as more of the distributions are made to employees that have terminated employment and thereby do not provide any exploration support.  Therefore, the quarterly financial information presented in the above tables reflects the recording of current distributions under the Net Profits Plan for terminated employees as being fully allocated entirely to general and administrative expense since there is no longer any functional link to geologic  and geophysical or exploration related work by those terminated individuals.

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EX-99.2

Exhibit 99.2

             For Information

              Brent A. Collins

          &# 160;     303-861-8140

FOR IMMEDIATE RELEASE

ST. MARY PROVIDES OPERATIONS UPDATE

DENVER, February 21, 2008 – St. Mary Land & Exploration Company (NYSE: SM) today provides an update of its operations.

Tony Best, President and CEO, commented, “I am very pleased with our strong start this year in executing our 2008 business plan.  We currently have 13 rigs operating across our five regions, and the pace of our development programs will increase through the year.  Our key projects are progressing well, and we continue to pursue new opportunities that will add to our multi-year inventory.  I have high confidence in this year’s program and believe that it will deliver growth and value that will reward our stockholders.”

MID-CONTINENT REGION

In the Mid-Continent region, the Company is currently operating two rigs in the horizontal Woodford program and three rigs throughout the Anadarko Basin.

In the horizontal Woodford program, recent results reflect the improvement of the Company’s understanding of some of the geotechnical aspects of the play and better completion techniques.  The Company is currently evaluating recently obtained 3D seismic data covering 75 percent of the Company’s acreage position in the Woodford.  The Company’s current average estimated ultimate recovery (EUR) for horizontal Woodford wells is 2.7 BCFE, with a recent operated completion having an EUR in excess of 5 BCFE based on several months of production data.  The two most recent completions with meaningful production histories are performing in line with better wells in the play.  The Wilma Hampton 1-5 (SM 34% WI) had an initial ten day sales rate of 1.5 MMCFED and is currently producing 2.0 MMCFED.  The Carman 3-11 (SM 71% WI) had an initial ten day sales rate of 1.8 MMCFED and is currently producing 2.5 MMCFED.  To date, St. Mary has drilled and completed 15 horizontal wells in the Woodford out of an inventory of several hundred potential wells.  Two operated wells are currently being completed, and the Company is participating in a number of wells with our operating partners in the play.

St. Mary continues to be active in the Anadarko Basin.  The Company recently completed the Joy 1-34 (SM 38% WI) well, which had an initial ten day sales rate of 3.3 MMCFED and recently acheived a ten day sales average of 6.0 MMCFED.   This well utilized an optimized completion design which also reduced the cost of the completed well.  The Western Oklahoma Washes program which targets the Atoka and

Granite Wash formations has one operated rig running at this time.  Elsewhere in the Anadarko Basin, we have two rigs operating that are working on a program testing deeper sections of the basin.

ARKLATEX REGION

There are two St. Mary operated rigs running in the ArkLaTex region currently, and the Company continues to participate in two significant Cotton Valley programs that are operated by others.

In the horizontal James Lime program, there are two operated drilling rigs currently active in the play.  As of year-end, the Company has increased its acreage position in the James Lime trend to roughly 50,300 net acres.  Leasing efforts by the Company are ongoing and competition in the area has increased markedly.   Drilling operations are focused on both proven development areas as well as potential extension acreage.  Two recent notable wells were the Johnson 7-1 Alt. and the Ricks 9-3 Alt. (both SM 100% WI) at Spider Field which had initial ten day sales rates of 2.6 MMCFED and 2.8 MMCFED, respectively.  Management continues to believe that the James Lime offers attractive economic returns.

The Company recently drilled its first horizontal Cotton Valley well in the Carthage area, which is scheduled to be completed in early March.  Two more horizontal wells are planned for the remainder of the year.

The programs operated by others at Elm Grove and Terryville fields continue to be active areas of significant capital investment.  The horizontal Killen 13-3H (SM 20% WI) at Elm Grove, which targets a section of the Cotton Valley formation, had an impressive initial production rate of 16.5 MMCFED according to public comments by the operator. The well continues to produce at meaningful rates based on field reports from the operator.  An offset horizontal well is currently being drilled, and if successful could substantiate the viability of further development in the field through horizontal drilling.  At Terryville, there is currently one drilling rig operating on acreage in which we have an interest.

ROCKY MOUNTAIN REGION

In the Rockies region there is one operated rig running in the region.  The Company also continues to participate in a number of projects with operating partners.

The Company recently participated in a horizontal Bakken well in eastern McKenzie County, North Dakota that had an initial ten day sales rate of 356 BOED.  This well is due west of the prolific Parshall Field and utilized new drilling and fracturing techniques that previously have not been used by the Company in developing the Bakken formation.  The Company plans to participate in several North Dakota Bakken wells in 2008.  St. Mary has roughly 35,000 net acres in Burke, Mountrail, and eastern

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McKenzie counties in North Dakota that the Company believes could be prospective for the Bakken formation.

At Hanging Woman Basin, St. Mary recently completed a three rig drilling program.  The focus for the remainder of the first half of 2008 is the completion and connection of wells drilled in recent months, and then the monitoring and evaluation of those wells.  Results from this technical work will determine the future pace and scope of our development program at Hanging Woman Basin.

The Company plans to continue to concentrate its property base in the Rocky Mountain region.  A divestiture package of properties and acreage in the Green River Basin is currently being marketed.  The Company is also conducting a thorough review of its Rockies acreage position and similar divestitures of non-core assets are anticipated in the region in the future.

PERMIAN REGION

St. Mary is operating three drilling rigs in the Permian region, with the primary focus being on the Wolfberry assets at Sweetie Peck and Halff East.  All of the operated drilling rigs are running at Sweetie Peck and at Halff East the Company continues to participate in the two rig program the operating partner has implemented for 2008.  Throughout 2007, the Company high graded the rig fleet at Sweetie Peck.  Additionally, the Permian office now has a fully staffed drilling group that has taken over operations from contract service providers.  The expectation is that the combination of more efficient rigs and crews together with in-house management of the asset by St. Mary personnel will improve our operational execution.  This should result in cost and efficiency improvement, which ultimately will enhance the economics of this successful program.  The Company is currently in the process of drilling and completing wells in one of the 40 acre pilot test areas.

GULF COAST REGION

There are three rigs being operated by St. Mary in the shallow Olmos gas project in South Texas.  Additionally, the Company continues to participate with operating partners on Gulf of Mexico projects.

The region is continuing its efforts to evaluate and exploit the Rockford and Catarina acquisitions, and is in the process of reprocessing 54 square miles of seismic data over this acreage.  In mid-March 2008, a workover program will begin during which 66 recompletion operations are scheduled for the year.

SIGNIFICANT PROGRAM INVENTORY UPDATE

As of December 31, 2007, St. Mary had proved reserves of 1,087 BCFE, 56 percent of which were natural gas and 23 percent were proved undeveloped.  This represents a 17% increase over year-end 2006 proved reserves.  The Company’s proved, probable,

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and possible (3P) reserves at year-end were approximately 2,800 BCFE, 74 percent of which were natural gas.

The schedule below presents the Company’s drilling inventory, comprised of proved undeveloped (PUD), probable, and possible locations, and the associated reserves at the end of 2007, and is intended to provide visibility to some of the larger multi-year drilling programs.  See the section “Information About Reserves and Resources” below for more detailed information regarding these terms.

Program	Region	3P Net Drilling Potential (BCFE)	% of 3P Potential Booked as PUD	Potential Gross Locations
Elm Grove	ArkLaTex	171	32%	580
James Lime	ArkLaTex	62	17%	86
Olmos Gas	Gulf Coast	115	47%	382
Wolfberry Tight Oil	Permian	143	27%	310
Atoka/Granite Wash	Mid-Continent	147	1%	537
Horizontal Arkoma	Mid-Continent	571	3%	521
TOTAL		1,209		2,416

The table above no longer includes reserves associated with the Hanging Woman Basin coalbed methane project.  A significant portion of those reserves were reclassified as contingent resources as of the end of 2007.  The Company’s estimated proved reserves at year-end 2007 related to Hanging Woman Basin of 40.2 BCFE, 75% of which were proved developed.  Total 3P reserves, including proved developed reserves, for the project were 395 BCFE at the end of 2007.

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,” “anticipate,” “intend,” “estimate,” “forecast,” ”plan,” 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 potential effects of increased levels of debt financing, 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, and other such matters discussed in the “Risk Factors” section of St. Mary’s 2006 Annual Report on Form 10-K/A filed with the SEC and the 2007 Annual Report on Form 10-K expected to be filed with the SEC on or about February 22, 2008.  Although St. Mary may from

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time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by securities laws.

INFORMATION ABOUT RESERVES AND RESOURCES

The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  St. Mary uses in this press release the terms “probable”, “possible”, and “3P” reserves, “estimated ultimate recovery (EUR)”, and “contingent resources”, which SEC guidelines prohibit from being included in filings with the SEC.  Probable reserves are unproved reserves which are more likely than not to be recoverable.  Possible reserves are unproved reserves which are less likely to be recoverable than probable reserves.  EUR means those quantities of petroleum which are estimated to be potentially recoverable from an accumulation, plus those quantities already produced therefrom.  Contingent resources are those quantities of petroleum estimated to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies.  Estimates of unproved reserves and sub-commercial contingent resources which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.  In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

3P Drilling Potential should be thought of as reserves net to St. Mary and characterized as of December 31, 2007, as PUD, probable, or possible reserves that could be produced through future drilling or capital spending.  Potential Gross Locations should be thought of as the number of gross drilling locations categorized as PUD, probable, or possible reserves as of December 31, 2007.

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