Exhibit 99.1

	For Information
		Mark A. Hellerstein
		Robert T. Hanley
	303-861-8140

FOR IMMEDIATE RELEASE

ST. MARY ANNOUNCES YEAR-END 2005 RESERVES AND 2006 CAPITAL EXPENDITURES BUDGET, AND PROVIDES OPERATIONS UPDATE

AND NEW GUIDANCE

DENVER, January 26, 2006 – St. Mary Land & Exploration Company (NYSE: SM) announces today its year-end 2005 estimated proved reserves, as well as the estimated proved, probable and possible (3P) reserves for the Company’s more significant resource programs. The Company is providing its 2006 capital expenditures budget and 2006 guidance. Additionally, St. Mary is updating its 2005 financial guidance and summarizing the results of the 2005 drilling and exploration program.

Mark Hellerstein, Chairman, President and CEO, comments, “2005 was a record year in terms of production, prices, reserves and earnings. Moreover, we made great strides in advancing our prospect inventory. We now have five project areas that offer significant multi-year inventory at various stages of development. We are successfully transitioning from a company that historically spent 35%-40% of its budget on acquisitions to one that is able to add substantial growth through the drill bit. We replaced 255% of our 2005 production overall. Of particular note, when acquisitions are excluded, we replaced 194% of our 2005 production. We also grew production 16%, most of which came through the drill bit. The 56% increase in our 2006 exploration and development budget represents a substantial increase in organic activity. We have positioned the Company for continued growth in 2006 and beyond.”

2005 Oil and Gas Reserves

Estimated proved oil and gas reserves as of December 31, 2005 increased 21% to 794.5 BCFE from 658.6 BCFE as of year-end 2004. Eighty-two percent of the reserves are proved developed. The present value of the Company’s estimated net cash flows before taxes discounted at 10% (PV-10 value) from its reserves as of December 31, 2005, is $2.5 billion. In addition to proved reserves, the Company estimates that, as of December 31, 2005, probable reserves were 495 BCFE and possible reserves were 1,168 BCFE for a total of 2.5 TCFE of 3P reserves. (see "Information About Forward-Looking Statements" and “Information About Reserves” below). The proved

undeveloped (PUD), probable and possible reserves (BCFE) of the Company’s more significant multi-year drilling programs are as follows:

							PUD				PUD, Prob, Poss
			Reserves					Wells				Reserves				Wells
Hanging Woman Basin
	Coalbed Natural Gas					4				76			810		3,000*
Bakken – Williston Basin				20						33				60					81
Centrahoma – Arkoma B.				24						27			240				385
Elm Grove – East Texas				35					204					45				247
Atoka / Granite Wash					7					23			155				512
		NE Mayfield – Anadarko B.

* This number could vary significantly depending on whether certain coal seams are completed up-hole within an existing wellbore or with a new grassroots well

2006 Guidance

The capital expenditures budget for 2006 is $600 million. The 2006 budget represents a 42% increase from the $421 million forecasted capital expenditures for 2005. The 2006 budget includes $500 million for exploration and development, which is a 56% increase over the estimated $320 million spent for exploration and development in 2005. Approximately 38% of the exploration and development budget is being allocated to the Rocky Mountain region, 34% to the Mid-Continent region, 14% to the Gulf Coast region (including the Permian Basin region) and 13% to the ArkLaTex region. The Company is budgeting $100 million for property and entity acquisitions in 2006. The amount and allocation of actual capital expenditures in 2006 will depend upon a number of factors, including the impact of oil and gas prices and the availability of attractive exploration, development, and acquisition opportunities.

The Company provides guidance for the first quarter and the full year of 2006 as follows:

1st Quarter

Year

Oil and gas production

21.5 – 22.5 BCFE

96.0 – 98.0 BCFE

Lease operating expenses

$1.16 - $1.22/MCFE

$1.18 - $1.24/MCFE

Production taxes

$0.60 - $0.65/MCFE

General and administrative expense

$0.52 - $0.58/MCFE

$0.47 - $0.53/MCFE

Depreciation, depletion & amort.

$1.67 - $1.73/MCFE

$1.92 - $1.98/MCFE

St. Mary estimates its basis differential for the first quarter of 2006 will be $5.75 to $6.00 per barrel of oil and $1.00 to $1.15 per MMbtu of gas. As a result of increased oil production in the Williston Basin created by the successful Bakken program, the pipelines and other infrastructure used to transport oil to markets for Williston Basin oil production are at or near capacity. Although St. Mary has experienced some delays by marketers off taking oil from tanks (approximately 20,000 barrels were delayed at year-end 2005), only minimal production from two wells has been shut in to date. The lack of pipeline capacity has increased the basis differentials over those St. Mary has realized in the past. The Company is actively marketing its oil production in the Williston Basin in order to limit any disruption created by the current situation.

St. Mary anticipates an increase in general and administrative expense in 2006. In addition to the increased costs associated with higher levels of activity and more personnel, the cost of the Company’s employee incentive plans are expected to increase as projected cash flow from operations increases. St. Mary’s unique combination of employee incentive plans are designed to reward substantial contributions by employees in economically growing the Company’s net asset value per share, and thus the plans are tied to shareholder value while also serving to attract and retain quality employees in this competitive workforce environment.

Hedging Schedule

St. Mary’s 2006 hedged volume and NYMEX equivalent prices are summarized below. The majority of the oil trades are settled against NYMEX. The gas trades have been executed to settle against regional delivery points that correspond with production areas of the Company, thereby reducing basis risk. All the prices in the table below have been converted to a NYMEX equivalent for ease of comparison.

OIL
	Swaps - NYMEX Equivalent		Collars - NYMEX Equivalent
				Floor	Ceiling
	Bbls	$/Bbl	Bbls	$/Bbl	$/Bbl
2006
Q1	409,366	$53.47	545,000	$51.34	$72.07
Q2	357,976	$54.88	537,000	$51.32	$72.05
Q3	314,372	$55.18	516,000	$51.31	$72.06
Q4	185,686	$51.39	607,000	$51.59	$72.28

NATURAL GAS
	Swaps - NYMEX Equivalent		Collars - NYMEX Equivalent
				Floor	Ceiling
	MMBTU	$/MMBTU	MMBTU	$/MMBTU	$/MMBTU
2006
Q1	3,540,000	$11.06	1,980,000	$10.99	$22.06
Q2	3,610,000	$8.77	2,060,000	$8.24	$13.77
Q3	3,310,000	$8.81	2,140,000	$8.05	$13.32
Q4	2,140,000	$9.73	1,815,000	$8.99	$14.88

2005 Financial and Operational Update

The Company updated its forecast for the fourth quarter and full year of 2005 as follows:

4th Quarter

Year

Oil and gas production

21.5 – 22.0 BCFE

87.0 – 87.5 BCFE

Lease operating expenses

$1.19 - $1.23/MCFE

$1.06 - $1.10/MCFE

Production taxes

$0.72 - $0.76/MCFE

$0.54 - $0.58/MCFE

General and administrative expense

$0.46 - $0.52/MCFE

$0.37 - $0.41/MCFE

Depreciation, depletion & amort.

$1.47 - $1.55/MCFE

$1.50 - $1.56/MCFE

Change in non-cash net profits

interest bonus plan liability

$34.0 - $35.0 million

$105.0 - $106.0 million

St. Mary estimates its basis differential for the fourth quarter of 2005 will be $4.05 to $4.55 per barrel of oil and $1.25 to $1.35 per MMbtu of gas.

St. Mary’s higher than anticipated lease operating expenses in the fourth quarter of 2005 resulted from an increased level of workover costs in its Rocky Mountain and Gulf Coast regions. The Rocky Mountain region incurred additional workover cost associated with acquisitions made in 2005, and the increased costs in the Gulf Coast region were related to hurricane damage.

2005 EXPLORATION AND DEVELOPMENT PROGRAM

During the fourth quarter of 2005, St. Mary participated in the drilling of 79 conventional wells, of which 73 were completed as producers (92% success rate). For the year 2005, the Company completed 258 conventional wells as producers out of the 278 total wells drilled, for a 93% success rate. At year-end St. Mary was completing 25 wells, waiting on completion of 8 wells and drilling 16 wells. The Company also drilled 149 coalbed methane wells during 2005.

MID-CONTINENT REGION

In the Mid-Continent region there were 91 wells drilled with 87 successful completions and four dry holes during 2005. In Northeast Mayfield the Company is concentrating its efforts in the Atoka and Granite Wash formations where it holds leases with an average working interest of approximately 30%. St. Mary plans to initially downspace the drilling density to an 80-acre pattern, as initial estimates indicate that each of the currently producing wells will drain significantly less than 80 acres. During the fourth quarter, the Tipton Trust 1-26 (SM 58% WI) was completed in the Atoka/Granite Wash at an initial rate of 6,400 MCFED. The Holland 1-12 (SM 25% WI) was completed in the Atoka/Granite Wash during the third quarter at an initial rate of 5,000 MCFED and was producing at a rate of 25,900 MCFED at the end of 2005.

In the Centrahoma field where St. Mary holds 36,000 gross and 20,000 net contiguous acres, the Company continues to test the Wapanucka, Cromwell, and Woodford shale formations with horizontal drilling and fracture stimulation of the targeted zones. St. Mary completed three wells in the Cromwell formation in 2005, is currently waiting on completion of the Faire 3-5 (SM 100% WI), and is drilling its fifth horizontal Cromwell well, the Jason K 3-6 (SM 100% WI). The three producing Cromwell wells, the Mowdy #1 (SM 100% WI) which completed at an initial rate of 3,000 MCFED, the Lanette 4-4 (SM 90% WI) which completed at an initial rate of 670 MCFED, and the Josh K 4-6 (SM 100% WI) which completed at an initial rate of 800 MCFED, are part of the continuing effort to determine the most efficient method to drill the Cromwell while achieving maximum ultimate reserve recoveries. In the same play, St. Mary completed the Ann Bey 2-7 (SM 86% WI), its first horizontal well in the Woodford shale. The Ann Bey 2-7 had an initial rate of 1,400 MCFD and has stabilized at approximately 650 MCFD. At

year-end, the Company was drilling its second horizontal Woodford shale well, the Ryan Gaylor 2-32 (SM 100% WI). In addition, St Mary is completing the first horizontal well in the Wapanuka limestone, the RP Mayer 3H-8 (SM 95% WI).

ROCKIES REGION

During 2005, 101 conventional wells were drilled in the Rocky Mountain region. Ninety-six were successfully completed and five wells were plugged and abandoned. Six wells were being completed and six wells were drilling at year-end.

During the fourth quarter, the Company completed eight wells in the middle Bakken formation in the Williston Basin, bringing the total wells it completed in the middle Bakken to 38 in 2005. Five middle Bakken wells were waiting on completion and four middle Bakken wells were drilling at year-end. Horizontal well completions in the middle Bakken during the fourth quarter include the Qualley 4-8H (SM 79% WI) which had an initial ten-day rate of 370 BOPD, the Stone Pleasant Valley 1-6H (SM 44% WI) which completed at a rate of 360 BOPD and the Larson 3-19H (SM 82% WI) which completed at a rate of 320 BOPD.

Since inception of the Hanging Woman coalbed methane program in the northern Powder River Basin, 126 wells have been placed on production (including dewatering). In 2005, the Company drilled 131 wells, of which 71 were at various stages of completion or hook-up to pipeline at year-end. It is important to note that these CBM wells are brought online in pods consisting of multiple wells as gathering systems are completed. Production at year-end was 3,700 MCFED.

ARKLATEX REGION

In the ArkLaTex region, 63 wells were drilled during 2005 with 58 successful completions and five dry holes. Eight wells were being completed at year-end, while another four wells were waiting on completion. Wells completed during the fourth quarter include the horizontal Ricks 9 Alt 1 (SM 67% WI) completed in the James Lime in the Spider field at an initial rate of 12,000 MCFED. In the Company’s Elm Grove project, 11 wells were completed in the fourth quarter and four wells were completing at year-end. Thirty-nine wells were completed in Elm Grove during 2005.

GULF COAST / PERMIAN REGION

In the Gulf Coast / Permian region, 23 wells were drilled during 2005 with 17 successful completions and six dry holes. Four wells were being completed, one well was waiting on completion and two wells were drilling at year-end. After year-end, the STM 24-1ST was brought online at a rate of 8,000 MCFED with production planned to reach 15,000 MCFED by month-end. This well is on the Company’s fee acreage in St. Mary Parish, LA, and St. Mary has a 21% royalty interest in this well.

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, unexpected drilling conditions and results, the risks of various exploration and hedging strategies, the uncertain nature of the expected benefits from the acquisition of oil and gas properties, production rates and reserve replacement, the imprecise nature of oil and gas reserve estimates, drilling and operating service availability, uncertainties in cash flow, the financial strength of hedge contract counterparties, the availability of economically attractive exploration and development and property acquisition opportunities and any necessary financing, competition, litigation, environmental matters, the potential impact of government regulations, and other such matters discussed in the “Risk Factors” section of St. Mary’s 2004 Annual Report on Form 10-K filed with the SEC. 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.

INFORMATION ABOUT RESERVES

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” and “possible” reserves, 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. Estimates of probable and possible reserves 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.

PR-06-01

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