exhibit992.htm

Tony Best, President and CEO, commented, “St. Mary will grow production 10% on retained properties in 2008 with a program that is near expected cash flow. We have continued to broaden and strengthen our inventory of drilling opportunities as we execute our strategic shift to focus on resource plays. You can expect to see us entering emerging resource plays much earlier and in a more compelling way that will result in improved economics and multi-year drilling programs with the scope and scale to provide significant future growth. Our entry into the Maverick Basin during the past year is a perfect example, which now provides us with tremendous exposure to the emerging Eagleford and Pearsall shale plays. I am very pleased with the expansion and improvement of our portfolio and see new opportunities for growth in front of us.”

The Company is encouraged by recent positive developments in the greater Maverick Basin. St. Mary entered the basin in the second half of 2007 with two acquisitions that primarily focused on the Olmos shallow gas play. At that time, the Company was aware of several other horizons of interest in the basin, including the Eagleford and Pearsall shales. Since that time, the Company has increased its acreage position through leasing efforts and a joint venture with TXCO Resources and Anadarko Petroleum. The joint venture allows St. Mary to earn up to approximately 75,000 net acres in Webb and Dimmit Counties as certain conditions are met. In the joint venture acreage, four horizontal wells have been drilled and are at various stages of testing. Two of these wells were horizontal re-entry wells targeting the Eagleford shale, while the Pearsall interval was tested with one horizontal re-entry well and one horizontal grass roots well. A recent announcement of a successful horizontal well by a competitor has drawn increased attention to the Eagleford shale. The competitor well is located in La Salle County, just east of Webb and Dimmit Counties where the Company’s joint venture acreage is located. Additionally, a successful well in northern Dimmit County targeting the Pearsall shale has been reported by TXCO Resources on acreage that is not part of the joint venture. Assuming the Company earns all of the acreage associated with the aforementioned joint venture, St. Mary will have captured over 210,000 net acres and 160,000 net acres in the Eagleford and Pearsall shales, respectively. The company will begin testing on its acreage outside the joint venture in the next few quarters.

St. Mary is currently drilling its first horizontal Haynesville shale well, which is located in De Soto Parish, Louisiana at the Spider Field. The rig is currently taking core samples in the Bossier and Haynesville sections and is expected to kick off the horizontal lateral within the next two weeks. The well design calls for an approximately 4,500 foot horizontal lateral. The well is expected to be completed in early January 2009.

Results from the operated horizontal Woodford shale program continue to improve. To date, the Company has drilled and completed 24 wells that have meaningful production histories. The average estimated ultimate recovery (EUR) for the last 14 wells is 3.4 BCFE. The four most recent wells have preliminary EURs which are at or above that per well average. The Company has previously guided to a range of 2.7 to 3.0 BCFE for a typical horizontal Woodford well. Completed well costs on the past 14 wells have come down over time and the estimated completed well cost for a typical well is now expected to be in the range of $4.0 to $5.5 million per well, depending on depth and the number of completion stages. As development moves east in the play, the formation is deeper and costs for those wells will be on the high end of the cost guidance. Currently, St. Mary is operating three rigs in the play.

In the Williston Basin, St. Mary recently drilled and completed its initial three horizontal Bakken test wells in the Company’s Powers Lake and Stillwater prospects on the Mountrail and Burke county line. While the wells have shown modest production rates, the Company does not believe that the area will be commercial for the Bakken in the

current commodity price and cost environment. Log data from the first of these wells confirmed the presence of the Three Forks formation under the Bakken, and information from offset operators suggests that this interval could be prospective on our acreage. In eastern McKenzie County, St. Mary has a rig scheduled to arrive in November in our Bear Den prospect to drill several horizontal Bakken and Three Forks wells. A recent St. Mary operated re-entry well targeting the Bakken was successful in this prospect, and the Company is encouraged by offset operator activity. The Bakken formation in the Bear Den acreage appears to have higher pressure compared to the Company’s acreage at Powers Lake and Stillwater. As previously announced, St. Mary recently acquired 6,200 net acres in the Bear Den area which brings the Company’s total acreage in the area to roughly 10,000 net acres. The Company has approximately 74,000 net acres in non-legacy areas in North Dakota. Declining oil prices combined with widening differentials and restricted pipeline takeaway capacity are potential limiting factors for future development in the Williston Basin.

During the year, the Company began testing the viability of 40-acre increased density Wolfberry oil wells at Sweetie Peck in the Permian Basin. The program included 15 wells in three pilot areas. Early results from testing have been positive. Performance of these infill wells has been similar to the wells drilled on 80-acre spacing. At the time of the acquisition of the Sweetie Peck assets in late 2006, the EURs and estimated initial production rates for the 40-acre locations were significantly discounted to reflect the unknown potential of 40-acre development. Further drilling on 40-acre spacing is expected at Sweetie Peck.

Production – The decrease in the Company’s oil and gas production guidance for the full year is due to disruptions to production caused primarily by the hurricanes in the Gulf of Mexico during September 2008. The Company estimates that approximately 2.0 BCFE of production was lost for the year as a result of Hurricanes Gustav and Ike. At the mid-point of the full year production guidance, St. Mary will grow production on retained properties 10% from 2007 divestiture-adjusted production of 102.5 BCFE. This production growth is expected to be generated by an exploration and development budget that is near cash flow for the year.

Lease operating expense – Lease operating expense for the fourth quarter is anticipated to be up slightly on a sequential basis from the third quarter of 2008. Anticipated costs related to non-recurring workovers of properties in the Rockies region are included in this guidance. St. Mary anticipates there could be some softening in pricing in future quarters in the oilfield services industry as a result of the expected pull back in activity levels across the exploration and production sector, however the Company has yet to see these cost reductions materialize.

Depreciation, depletion, and amortization expense – With forecasted commodity prices being significantly lower than earlier in the year, there could be some downward pricing revisions to proved reserve estimates throughout the exploration and production industry. Downward pricing revisions have a corresponding upward impact on DD&A rates, and accordingly the Company is guiding to higher DD&A rates in anticipation of

Hedging update – Below is an updated summary hedging schedule for the Company. All the prices in the table below have been converted to an average NYMEX equivalent for ease of comparison using quality and transportation differentials as of September 30, 2008. No hedges have been added between the end of the third quarter of 2008 and the date of this release. The majority of the oil trades are settled against NYMEX. The gas contracts have been executed to settle against regional delivery points that correspond with the Company’s production areas, thereby reducing basis risk. Approximately 60% and 55% of the Company’s oil and natural gas production, respectively, have been hedged for the remainder of 2008. For detailed schedules on the Company’s hedging program, please refer to the Company’s Form 10-Q for the quarter ended September 30, 2008, which is expected to be filed with the Securities and Exchange Commission on November 4, 2008.

Oil Swaps - NYMEX Equivalent				Oil Collars - NYMEX Equivalent

						Floor		Ceiling
	Bbls	$/Bbl			Bbls	$/Bbl		$/Bbl
2008				2008
Q4	466,000	$	71.74	Q4	519,000	$	58.19	$	78.43
2009	1,570,000	$	71.64	2009	1,526,000	$	50.00	$	67.31
2010	1,239,000	$	66.47	2010	1,367,500	$	50.00	$	64.91
2011	1,032,000	$	65.36	2011	1,236,000	$	50.00	$	63.70

Natural Gas Swaps - NYMEX Equivalent				Natural Gas Collars - NYMEX Equivalent

						Floor		Ceiling
	MMBTU	$/MMBTU			MMBTU	$/MMBTU		$/MMBTU
2008				2008
Q4	5,860,000	$	10.13	Q4	3,957,500	$	9.58	$	12.21
2009	20,420,000	$	9.06	2009	9,110,000	$	6.59	$	10.58
2010	8,730,000	$	8.60	2010	7,825,000	$	6.54	$	8.83
2011	1,240,000	$	7.77	2011	6,625,000	$	6.41	$	7.65

Natural Gas Liquid Swaps - Mont. Belvieu


	Bbls	$/Bbl
2008
Q4	245,992	$	40.79
2009	813,732	$	41.87
2010	139,724	$	49.59
2011	19,643	$	49.01

This release contains forward looking statements within the meaning of securities laws, including forecasts and projections. The words “will,” “believe,” “budget,” “anticipate,” “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, 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 our hedging strategy, and other such matters discussed in the “Risk Factors” section of St. Mary’s 2007 Annual Report on Form 10-K/A and subsequent quarterly reports on Form 10-Q 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.

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 term “EUR” (estimated ultimate recovery), which SEC guidelines prohibit from being included in filings with the SEC. EUR means those quantities of petroleum which are estimated to be potentially recoverable from an accumulation, plus those quantities already produced therefrom. Estimates of unproved 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.

	2008 Exploration & Development Capital
	($ in millions)

ArkLaTex	$	190
Mid-Continent		167
Permian		150
Rocky Mountain		165
Gulf Coast		86
TOTAL	$	758