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.
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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
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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
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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
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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.
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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.
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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
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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
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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.
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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.
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