EXHIBIT 99.1


For Information
Brent A. Collins
303-861-8140

FOR IMMEDIATE RELEASE

ST. MARY REPORTS RESULTS FOR FOURTH QUARTER OF 2008
AND PROVED RESERVES AS OF YEAR-END 2008

·  
Record quarterly production of 30.0 BCFE exceeds guidance of 28.0 – 29.0 BCFE

·  
Reported GAAP net loss of ($126.0 million), or ($2.01) per diluted share; pre-tax non-cash impairments of $336.3 million had significant impact on earnings

·  
Adjusted net income of $27.1 million, or $0.43 per diluted share

·  
Proved reserves at year-end 2008 of 865.5 BCFE; lower year-end commodity price resulted in significant negative price revisions

·  
Drilling and acquisition activity, excluding revisions, replaced 174% of production in 2008


DENVER, February 23, 2009 – St. Mary Land & Exploration Company (NYSE: SM) today reports financial results from the fourth quarter of 2008 and provides a brief update of its financial condition.  The Company also is reporting its proved and 3P reserves as of December 31, 2008.

FOURTH QUARTER 2008 RESULTS

St. Mary posted a net loss for the fourth quarter of 2008 of ($126.0) million, a loss of ($2.01) per diluted share.  This compares to net income of $32.9 million or $0.51 per diluted share, for the same period in 2007.    Adjusted net income for the quarter, which adjusts for significant non-recurring and unusual non-cash items, was $27.1 million or $0.43 per diluted share, versus $64.9 million or $1.00 per diluted share, for the fourth quarter of 2007.  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,
  
 
2008
  
2007
  
Weighted-average diluted share count (in millions)
   62.6         64.6  
                     
 
$ in millions
Per Diluted Share
$ in millions
  
Per Diluted Share
  
Reported Net Income (Loss)
 $ (126.0 ) $ (2.01 ) $ 32.9   $ 0.51  
                         
After-tax adjustments, assuming effective tax rate for respective period                         
Change in Net Profits Plan liability
 $ (52.8 ) $ (0.84 ) $ 28.5   $ 0.44  
Unrealized derivative (gain) loss
   (7.8 )   (0.13 )   2.1     0.03  
(Gain) loss on sale of proved properties
   (6.2 )   (0.10 )   0.2     0.00  
Loss on insurance settlement
   0.5     0.01     0.7     0.01  
                         
Adjusted net income, before non-cash impairments
 $ (192.5 ) $ (3.07 ) $ 64.4   $ 1.00  
                         
After-tax adjustments for non-cash impairments, assuming effective tax rate for respective period                         
Impairment of proved properties
 $ 190.7   $ 3.05   $ 0.0   $ 0.00  
Abandonment & impairment of unproved properties
   22.7     0.36     0.6     0.01  
Impairment of goodwill
   6.2     0.10     0.0     0.00  
                         
Adjusted net income
 $ 27.1   $ 0.43   $ 64.9   $ 1.00  
                         
NOTE: Totals may not add due to rounding
              

Discretionary cash flow decreased to $163.3 million for the fourth quarter of 2008 from $177.8 million in the same period last year.  Net cash provided by operating activities decreased to $110.1 million for the fourth quarter of 2008 from $156.8 million in the same period in 2007.

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 record quarterly production of 30.0 BCFE which came in above the guidance range of 28.0 to 29.0 BCFE.  Strong performance in the Mid-Continent region was the primary driver in exceeding production guidance for the quarter.  Year over year, the Company grew reported production 5% from 28.5 BCFE in the fourth quarter of 2007.  Adjusting for sales of non-strategic assets that took place in 2008, year over year production growth was 11%.  The Company’s oil and gas production growth on retained properties year over year is being driven primarily by development of the Cotton Valley program in the ArkLaTex region, successful drilling in the Wolfberry tight
 
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oil program in West Texas, and the horizontal Woodford shale program in the Arkoma Basin.

Revenues for the quarter were $258.2 million compared to $275.2 million for the same period in 2007.  Average realized prices, excluding hedging activities, were $5.30 per Mcf and $50.17 per barrel during the quarter.  These prices were 25% and 41% lower, respectively, than the fourth quarter of 2007.  Compared to recent history, the Company experienced wider price differentials during the fourth quarter of 2008.  Average realized prices, inclusive of hedging activities, were $7.09 per Mcf and $55.63 per barrel in the fourth quarter of 2008, which is a decrease of 9% and 21%, respectively, from the same period a year ago.  In the fourth quarter of 2008, the Company’s average equivalent price per MCFE, net of hedging, was $7.84 per MCFE, which is a decrease of 15% from the $9.18 per MCFE realized in the comparable period in 2007.

Lease operating expense increased 20%, or $0.27 per MCFE, between the fourth quarters of 2007 and 2008 to $1.59 per MCFE.  This amount is slightly below the Company’s lease operating expense guidance range of $1.60 to $1.65 per MCFE. Recurring lease operating costs were up approximately 11% or $0.13 per MCFE year over year.  This increase reflects the impact of stronger commodity prices and high levels of activity in the first half of 2008 on the operating cost structure of exploration and production companies.  Sequentially, recurring lease operating expense declined 2% or $0.03 per MCFE in the fourth quarter of 2008 from the preceding quarter.  St. Mary expects that there will be continuing downward pressure on recurring lease operating expense in 2009 as a result of lower commodity prices and decreased levels of industry activity.  Workover expense for the quarter increased by approximately $2.6 million year over year, primarily as a result of optimization efforts in the Rocky Mountain region.

Transportation expense of $0.20 per MCFE in the fourth quarter of 2008 was below guidance of $0.21 to $0.26 per MCFE.  The reported per unit expense was an increase from $0.13 per MCFE for the comparative period in 2007.  The increase is being driven primarily by the change in asset composition, and the associated transportation arrangements, in the Gulf Coast and ArkLaTex regions where the Company’s development activities are taking place in areas with different transportation arrangements than what St. Mary has historically used.

Significant commodity price decreases for both oil and natural gas resulted in a 42% decrease in production taxes between the fourth quarters of 2008 and 2007.  Production taxes for the fourth quarter were $0.39 per MCFE, which was below guidance of $0.46 to $0.51 per MCFE as a result of lower than forecasted commodity prices throughout the quarter.

General and administrative expense for the fourth quarter of 2008 was $0.41 per MCFE, representing a 23% decrease from the $0.53 per MCFE recognized in the comparable quarter a year ago.  The decrease year over year relates to smaller payments to participants in the Net Profits Plan, which was affected by lower commodity prices
 
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realized in the fourth quarter of 2008.  Offsetting a portion of these decreases were increases between the periods in costs associated with headcount, such as salary, benefits, and office space.  Reported G&A for the fourth quarter of 2008 was below guidance of $0.78 to $0.83 per MCFE.

Depletion and depreciation expense increased to $3.18 per MCFE in the fourth quarter of 2008 from $2.27 per MCFE in the comparable period in 2007.  Sequentially, DD&A increased 22% from $2.61 per MCFE in the third quarter of 2008.  Guidance for DD&A in the fourth quarter was $2.75 to $2.95 per MCFE.  The increase in DD&A in the fourth quarter of 2008 is the result of a decrease in the Company’s proved reserves.  Commodity prices used to determine the proved reserves at year-end 2008 were significantly lower than those used in the prior year.  Additionally, the price differentials on oil in the Rocky Mountain region were wider than what the Company has experienced historically, which further lowered the oil price used to determine proved reserves at year-end.  As a result, St. Mary’s proved reserves decreased by approximately 20% year over year due primarily to downward pricing revisions.  This decrease in reserves results in a smaller base to amortize the capitalized costs related to our producing properties and therefore results in a higher DD&A rate for the period.

St. Mary recognized $336.3 million before income taxes in non-cash impairments in the fourth quarter of 2008, compared to $870,000 in the same period in 2007.  The largest part of this amount was the impairment of producing properties of $292.1 million.  The largest individual component was an impairment of $154.0 million related to properties in South Texas targeting the Olmos shallow gas formation.  Additionally, St. Mary recognized producing property impairments on properties in the Hanging Woman Basin coalbed methane project, in the Greater Green River Basin, and in the Gulf of Mexico.  Significantly lower prices for oil and gas in effect at year-end played a large part in triggering these impairments on producing properties.  St. Mary also recognized an impairment of non-producing leasehold costs of $34.8 million in the fourth quarter of 2008.  The bulk of this impairment relates to value initially assigned to probable and possible drilling locations in South Texas related to the Olmos shallow gas assets purchased in 2007, as well as acreage value related to the Floyd shale.  Lastly, the Company recognized an impairment of goodwill for $9.5 million associated with an acquisition made in 2005.

In fourth quarter of 2008, St. Mary recognized a pre-tax non-cash benefit of $80.9 million as a result of the decrease in the Net Profits Plan liability, which decreased during the quarter as a result of the significant decrease in forecasted oil and natural gas prices from September 30, 2008, to December 31, 2008.  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.

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FINANCIAL POSITION AND LIQUIDITY

As of December 31, 2008, St. Mary had total long-term debt of $587.5 million, comprised of $287.5 million in 3.50% Senior Convertible Notes and $300.0 million drawn under the existing long-term credit facility.  The Company’s debt-to-book capitalization ratio was 34% as of the end of the quarter.  The long-term credit facility requires compliance with two financial covenants, consisting of a leverage to trailing EBITDA limit and a minimum modified current ratio multiple.  St. Mary was in compliance with both covenants at quarter-end.

The borrowing base for the long-term credit facility was redetermined by St. Mary’s bank group on October 1, 2008, at an amount of $1.4 billion.  The bank group is comprised of ten banks, led by Wells Fargo.  The Company has elected a commitment amount of $500 million given its expected near term liquidity needs.  The current credit facility is set to expire in April of 2010.  St. Mary has been in discussions with banks both within and outside the existing bank group about replacing the existing credit facility and potentially increasing the commitment amount.  The Company expects to have a new credit facility in place in the first half of 2009.

PROVED RESERVES

Below is a roll-forward of the Company’s proved reserves from year-end 2007 to year-end 2008.
 
 
(BCFE)
  
Beginning of year
 1,086.5  
     
Production
 (114.6 )
Purchase of minerals in place
 29.1  
Sales of reserves
 (61.4 )
Discoveries and extensions
 45.1  
Infill reserves in an existing proved field
 125.0  
Performance revisions
 (44.5 )
Pricing revisions
 (199.7 )
End of year
 865.5  

St. Mary’s proved reserves as of December 31, 2008, were 865.5 BCFE, which is a decrease of 20% from 1086.5 BCFE at the end of 2007.  The reserves are comprised of 51.4 MMBbl of oil and 557.4 Bcf of natural gas, and are 83% proved developed.  Over 80% of St. Mary’s proved reserves by value were either prepared or reviewed by outside reserve engineering firms.  Prices used to determine the proved reserves decreased significantly from 2007 to 2008; SEC-mandated pricing in effect at December 31, 2008, was $5.71 per MMBtu and $44.60 per barrel, which are down 16% and 54%, respectively, from the $6.80 per MMBtu and $95.98 per barrel used on December 31, 2007.  In addition to the drop in base commodity prices used for the calculation of 2008’s reserves, the Company was impacted by larger differentials for oil
 
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and natural gas liquids on this measurement date.  In the Williston Basin in the Rocky Mountain region, where St. Mary has a significant legacy oil-dominated asset base, average oil differentials increased roughly from $7.00 per barrel to $15.00 per barrel as of year-end.  In South Texas, the natural gas liquid fractionation spread shrank from $10.34 per MMBtu at year-end 2007 to $0.29 per MMBtu at year-end 2008.

Proved reserves were adversely impacted by negative pricing and performance revisions at year-end 2008.  St. Mary’s negative price revision for the year was 199.7 BCFE, of which 74% related to proved developed reserves.  Two-thirds of the 199.7 BCFE in negative price revisions related to the Company’s oil-weighted properties in the Rocky Mountain region, which bore the brunt of the reserve impact caused by a lower year-end oil price and a wider price differential.  Lower year-end prices for natural gas liquids also led to a meaningful negative price revision on proved reserves in South Texas.

The SEC recently published new rules for reporting year-end reserves that will go into effect for the calendar year 2009. Pursuant to the new rules, prices to be used to calculate year-end reserves will be based on the average of the prices that were in effect on the first trading day of each calendar month of the year rather than on the price that was in effect on the last trading day of the year.  The table below details the amount of reserves the Company would recapture at various pricing assumptions.
 
(in BCFE)
Year-end 2008 at year-end 2007 SEC pricing and differentials
  
Year-end 2008 under new SEC pricing & differentials methodology
  
         
Assumed pricing
$95.98/bbl & $6.80 MMBtu
  
$102.06/bbl & $8.91 MMBtu
  
         
Year-end 2008 SEC Proved Reserves
 865.5   865.5  
Recaptured PDP reserves
 147.0   157.0  
Recaptured PDN/PUD reserves
 38.0   42.0  
Drilling adds
 35.0   35.0  
Year-end 2008 at assumed pricing
 1,085.5   1,099.5  

The largest component of the negative performance revision relates to Olmos shallow gas properties in South Texas that were acquired in 2007.  Results from the Olmos development did not meet the Company’s expectations, and midway through 2008 development was stopped to conduct a technical review.  While parts of the technical review are still underway, the initial results have cast doubt on the viability of Olmos development on the scale originally contemplated at the time these acquisitions were made.  Compared to the Company’s original assumptions, the reservoir is more compartmentalized than initially expected and lower reserve outcomes have been realized while attempting to infill parts of the field.  While results from the Olmos
 
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program have been disappointing, St. Mary’s activities targeting the deeper formations in the basin have been promising.  The Company participated during the year in a joint venture with two other exploration and production companies that allows St. Mary to earn acreage in an area of the basin that is prospective for the Eagle Ford and Pearsall shale formations, both of which appear to have potential given recent industry activity.

3P RESERVES

St. Mary’s proved, probable, and possible (3P) reserves as of year-end 2008 were negatively impacted by the same pricing conditions referred to above for proved reserves.  The following table provides the components of the Company’s 3P reserves as of year-end 2007 and 2008.
 
 
December 31,
  
 
2008
  
2007
  
(in BCFE)
      
Proved
 865.5   1,086.5  
Probable
 587.8   835.9  
Possible
 699.6   870.0  
Total 3P
 2,152.9   2,792.5  

Not included in the 3P reserves for 2008 above is any potential related to the Company’s exposure to three emerging resource plays – the Haynesville shale, the Eagle Ford shale, and the Marcellus shale.  St. Mary has approximately 50,000, 210,000, and 43,000 net acres, respectively, in these shale plays assuming all the acreage is earned.

Proved reserves were evaluated using the parameters and pricing required by the SEC.  Probable and possible reserves were evaluated using the parameters set forth by the Society of Petroleum Engineers.

EARNINGS CALL INFORMATION

The Company has scheduled a teleconference to discuss fourth quarter and full year 2008 results on February 24, 2009 at 8:00 a.m. Mountain time (10:00 a.m. Eastern time).  The call participation number is 888-811-1227.  An audio replay of the call will be available approximately two hours after the call at 800-642-1687, conference number 84161206.  International participants can dial 706-679-9922 to take part in the conference call and can access a replay of the call at 706-645-9291, conference number 84161206.  Replays can be accessed through March 20, 2009.

In addition, the call will be webcast live and can be accessed at St. Mary’s web site at www.stmaryland.com.  An audio recording of the conference call will be available at that site through March 20, 2009.
 
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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,” “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 the Company’s hedging strategy, and other such matters discussed in the “Risk Factors” section of St. Mary’s 2008 Annual Report on Form 10-K, which is expected to be filed on or around February 24, 2009.  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 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, 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 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, presenting the estimated impact of applying the 12-month-average pricing provisions of the oil and gas reserve reporting rules recently promulgated by the SEC or the reserves that would be recaptured at various price scenarios are strictly prohibited from being included in filings with the SEC.  Lastly, the Company’s 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.
 
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ST. MARY LAND & EXPLORATION COMPANY
  
FINANCIAL HIGHLIGHTS
  
December 31, 2008
  
                         
Production Data
For the Three Months
      
For the Years
      
 
Ended December 31,
      
Ended December 31,
      
 
2008
  
2007
  
Percent Change
  
2008
  
2007
  
Percent Change
  
                         
Average realized sales price, before hedging:
                        
Oil (per Bbl)
 $ 50.17   $ 84.63   -41%   $ 92.99   $ 67.56   38%  
Gas (per Mcf)
 $ 5.30   $ 7.07   -25%   $ 8.60   $ 6.74   28%  
                                 
Average realized sales price, net of hedging:
                                
Oil (per Bbl)
 $ 55.63   $ 69.99   -21%   $ 75.59   $ 62.60   21%  
Gas (per Mcf)
 $ 7.09   $ 7.80   -9%   $ 8.79   $ 7.63   15%  
                                 
Production:
                                
Oil (MMBbls)
   1.7     1.7   1%     6.6     6.9   -4%  
Gas (Bcf)
   19.7     18.3   7%     74.9     66.1   13%  
BCFE (6:1)
   30.0     28.5   5%     114.6     107.5   7%  
                                 
Daily production:
                                
Oil (MBbls per day)
   18.7     18.5   1%     18.1     18.9   -4%  
Gas (MMcf per day)
   213.8     199.1   7%     204.7     181.0   13%  
MMCFE per day (6:1)
   326.0     310.2   5%     313.1     294.5   6%  
                                 
Margin analysis per MCFE:
                                
Average realized sales price, before hedging
 $ 6.35   $ 9.59   -34%   $ 10.99   $ 8.48   30%  
                                 
Average realized sales price, net of hedging
 $ 7.84   $ 9.18   -15%   $ 10.11   $ 8.71   16%  
Lease operating expense
 $ 1.59   $ 1.32   20%     1.46     1.31   11%  
Transportation
 $ 0.20   $ 0.13   54%     0.19     0.14   36%  
Production taxes
 $ 0.39   $ 0.67   -42%     0.71     0.58   22%  
General and administrative
 $ 0.41   $ 0.53   -23%     0.69     0.56   23%  
Operating margin
 $ 5.25   $ 6.53   -20%   $ 7.06   $ 6.12   15%  
Depletion, depreciation, amortization, and
                                
asset retirement obligation liability accretion
 $ 3.18   $ 2.27   40%   $ 2.74   $ 2.12   29%  


 
 
 

 ST. MARY LAND & EXPLORATION COMPANY
  
 FINANCIAL HIGHLIGHTS
  
 December 31, 2008
  
                 
Consolidated Statements of Operations
                
(In thousands, except per share amounts)
For the Three Months
  
For the Year
  
 
Ended December 31,
  
Ended December 31,
  
 
2008
  
2007
  
2008
  
2007
  
Operating revenues and other income:
                
Oil and gas production revenue
 $ 190,499   $ 273,736   $ 1,259,400   $ 912,093  
Realized oil and gas hedge gain (loss)
   44,741     (11,676 )   (101,096 )   24,484  
Marketed gas system revenue
   11,935     13,909     77,350     45,149  
Gain (loss) on sale of proved properties
   9,494     (367 )   63,557     (367 )
Other revenue
   1,500     (355 )   2,090     8,735  
Total operating revenues and other income
   258,169     275,247     1,301,301     990,094  
                         
Operating expenses:
                        
Oil and gas production expense
   65,530     60,590     271,355     218,208  
Depletion, depreciation, amortization,
                        
                 and asset retirement obligation liability accretion
   95,260     64,919     314,330     227,596  
Exploration
   17,743     16,030     60,121     58,686  
Impairment of proved properties
   292,100     -     302,230     -  
Abandonment and impairment of unproved properties
   34,754     870     39,049     4,756  
Impairment of goodwill
   9,452     -     9,452     -  
General and administrative
   12,354     15,187     79,503     60,149  
Bad debt expense
   143     -     16,735     -  
Change in Net Profits Plan liability
   (80,941 )   43,875     (34,040 )   50,823  
Marketed gas system expense
   11,241     13,031     72,159     42,485  
Unrealized derivative (gain) loss
   (12,011 )   3,234     (11,209 )   5,458  
Other expense
   1,260     946     10,415     2,522  
Total operating expenses
   446,885     218,682     1,130,100     670,683  
                         
Income (loss) from operations
   (188,716 )   56,565     171,201     319,411  
                         
Nonoperating income (expense):
                        
Interest income
   90     134     485     746  
Interest expense
   (4,417 )   (6,010 )   (20,275 )   (19,895 )
                         
Income (loss) before income taxes
   (193,043 )   50,689     151,411     300,262  
Income tax (expense) benefit
   67,003     (17,815 )   (59,858 )   (110,550 )
                         
Net income (loss)
 $ (126,040 ) $ 32,874   $ 91,553   $ 189,712  
                         
Basic weighted-average common shares outstanding
   62,212     63,300     62,243     61,852  
                         
Diluted weighted-average common shares outstanding
   62,630     64,635     63,133     64,850  
                         
Basic net income (loss) per common share
 $ (2.03 ) $ 0.52   $ 1.47   $ 3.07  
                         
Diluted net income (loss) per common share
 $ (2.01 ) $ 0.51   $ 1.45   $ 2.94  
 

 
 
 
 

ST. MARY LAND & EXPLORATION COMPANY
  
FINANCIAL HIGHLIGHTS
  
December 31, 2008
  
         
Consolidated Balance Sheets
        
(In thousands, except share amounts)
December 31,
December 31,
  
ASSETS
2008
  
2007
  
Current assets:
        
Cash and cash equivalents
 $ 6,131   $ 43,510  
Short-term investments
   1,002     1,173  
Accounts receivable, net of allowance for doubtful accounts
        
of $16,788 in 2008 and $152 in 2007
   157,690     159,149  
Refundable income taxes
   13,161     933  
Prepaid expenses and other
   22,161     14,129  
Accrued derivative asset
   111,649     17,836  
Deferred income taxes
   -     33,211  
Total current assets
   311,794     269,941  
             
Property and equipment (successful efforts method), at cost:
        
Land
   1,350     -  
Proved oil and gas properties
   3,007,946     2,721,229  
Less - accumulated depletion, depreciation, and amortization
   (947,207 )   (804,785 )
Unproved oil and gas properties, net of impairment allowance
        
of $42,945 in 2008 and $10,319 in 2007
   168,817     134,386  
Wells in progress
   90,910     137,417  
Oil and gas properties held for sale less accumulated depletion,
      
depreciation, and amortization
   1,827     76,921  
Other property and equipment, net of accumulated depreciation
  
of $13,848 in 2008 and $11,549 in 2007
   13,458     9,230  
    2,337,101     2,274,398  
             
Other noncurrent assets:
            
Goodwill
   -     9,452  
Accrued derivative asset
   21,541     5,483  
Restricted cash subject to Section 1031 Exchange
   14,398     -  
Other noncurrent assets
   10,182     12,406  
Total other noncurrent assets
   46,121     27,341  
             
Total Assets
 $ 2,695,016   $ 2,571,680  
             
LIABILITIES AND STOCKHOLDERS' EQUITY
            
Current liabilities:
            
Accounts payable and accrued expenses
 $ 254,811   $ 254,918  
Accrued derivative liability
   501     97,627  
Deposit associated with oil and gas properties held for sale
   -     10,000  
Deferred income taxes
   41,289     -  
Total current liabilities
   296,601     362,545  
             
Noncurrent liabilities:
            
Long-term credit facility
   300,000     285,000  
Senior convertible notes
   287,500     287,500  
Asset retirement obligation
   108,755     96,432  
Asset retirement obligation associated with oil and gas
        
properties held for sale
   238     8,744  
Net Profits Plan liability
   177,366     211,406  
Deferred income taxes
   358,334     257,603  
Accrued derivative liability
   27,419     190,262  
Other noncurrent liabilities
   11,318     8,843  
Total noncurrent liabilities
   1,270,930     1,345,790  
             
Stockholders' equity:
            
Common stock, $0.01 par value: authorized - 200,000,000 shares;
  
issued: 62,465,572 shares in 2008 and 64,010,832 shares
        
in 2007; outstanding, net of treasury shares: 62,288,585 shares
  
in 2008 and 63,001,120 shares in 2007
   625     640  
Additional paid-in capital
   99,440     170,070  
Treasury stock, at cost: 176,987 shares in 2008 and 1,009,712
  
shares in 2007
   (1,892 )   (29,049 )
Retained earnings
   964,019     878,652  
Accumulated other comprehensive loss
   65,293     (156,968 )
Total stockholders' equity
   1,127,485     863,345  
             
Total Liabilities and Stockholders' Equity
 $ 2,695,016   $ 2,571,680  


 
 
 

 ST. MARY LAND & EXPLORATION COMPANY
  
 FINANCIAL HIGHLIGHTS
  
 December 31, 2008
  
                 
Consolidated Statements of Cash Flows
                
(In thousands)
For the Three Months
  
For the Years
  
 
Ended December 31,
  
Ended December 31,
  
Cash flows from operating activities:
2008
  
2007
  
2008
  
2007
  
Reconciliation of net income to net cash provided
              
by operating activities:
                
Net income (loss)
 $ (126,040 ) $ 32,874   $ 91,553   $ 189,712  
Adjustments to reconcile net income (loss) to net cash
                    
provided by operating activities:
                        
Loss related to hurricanes
   -     -     6,980     -  
(Gain) loss on insurance settlement
   696     1,097     2,296     (5,243 )
(Gain) loss on sale of proved properties
   (9,494 )   367     (63,557 )   367  
Depletion, depreciation, amortization,
                        
and asset retirement obligation liability accretion
   95,260     64,919     314,330     227,596  
Bad debt expense
   143     -     16,735     -  
Exploratory dry hole expense
   240     1,651     6,823     14,365  
Impairment of proved properties
   292,100     -     302,230     -  
Impairment of goodwill
   9,452     -     9,452     -  
Abandonment and impairment of unproved properties
   34,754     870     39,049     4,756  
Unrealized derivative (gain) loss
   (12,011 )   3,234     (11,209 )   5,458  
Change in Net Profits Plan liability
   (80,941 )   43,875     (34,040 )   50,823  
Stock-based compensation expense (1)
   4,335     1,489     14,812     10,095  
Deferred income taxes
   (60,597 )   13,666     40,634     92,955  
Other
   (97 )   (5,329 )   (3,593 )   (10,497 )
Changes in current assets and liabilities:
                        
Accounts receivable
   25,128     (6,349 )   (14,327 )   (6,557 )
Refundable income taxes
   (8,578 )   2,164     (12,228 )   6,751  
Prepaid expenses and other
   (3,533 )   (8,660 )   (1,504 )   19,375  
Accounts payable and accrued expenses
   (47,111 )   13,217     (12,348 )   40,769  
Excess income tax benefit from the exercise of stock options
   (3,586 )   (2,275 )   (13,867 )   (9,933 )
Net cash provided by operating activities
   110,120     156,810     678,221     630,792  
                         
Cash flows from investing activities:
                        
Proceeds from insurance settlement
   -     (1,116 )   -     5,948  
Proceeds from sale of oil and gas properties
   23,664     171     178,867     495  
Capital expenditures
   (251,125 )   (137,637 )   (745,617 )   (637,748 )
Acquisition of oil and gas properties
   1,610     (150,233 )   (81,823 )   (182,883 )
Deposits to restricted cash
   (14,398 )   -     (14,398 )   -  
Other
   9     25,300     (9,814 )   10,316  
Net cash used in investing activities
   (240,240 )   (263,515 )   (672,785 )   (803,872 )
                         
Cash flows from financing activities:
                        
Proceeds from credit facility
   1,739,500     268,086     2,571,500     822,000  
Repayment of credit facility
   (1,609,500 )   (138,086 )   (2,556,500 )   (871,000 )
Excess tax benefit from the exercise of stock options
   3,586     2,275     13,867     9,933  
Net proceeds from issuance of senior convertible debt
   -     (7 )   -     280,657  
Proceeds from sale of common stock
   561     3,665     11,888     10,007  
Repurchase of common stock
   -     -     (77,202 )   (25,904 )
Dividends paid
   (3,110 )   (3,144 )   (6,186 )   (6,284 )
Other
   (182 )   186     (182 )   (4,283 )
Net cash provided by (used in) financing activities
   130,855     132,975     (42,815 )   215,126  
                         
Net change in cash and cash equivalents
   735     26,270     (37,379 )   42,046  
Cash and cash equivalents at beginning of period
   5,396     17,240     43,510     1,464  
Cash and cash equivalents at end of period
 $ 6,131   $ 43,510   $ 6,131   $ 43,510  
                         
(1)   Stock-based compensation expense is a component of exploration expense and general and administrative expense on the consolidated statements of operations.
  
For the three-month periods ended December 31, 2008, and 2007, respectively, approximately $2.0 million and $600,000 of stock-based compensation expense
  
was included in exploration expense. For the years ended December 31, 2008, and 2007, respectively, approximately $5.8 million and $3.2 million
  
of stock-based compensation expense was included in exploration expense. For the three-month periods ended December 31, 2008, and 2007, respectively,
  
approximately $2.3 million and $889,000 of stock-based compensation expense was included in general and administrative expense. For the years
  
ended December 31, 2008, and 2007, respectively, approximately $9.0 million and $6.9 million of stock-based compensation expense was included in
  
        general and administrative expense.
                        


 
 
 

 ST. MARY LAND & EXPLORATION COMPANY
  
 FINANCIAL HIGHLIGHTS
  
 December 31, 2008
  
                 
Adjusted Net Income
                
(In thousands, except per share data)
                
                 
Reconciliation of Net Income (Loss) (GAAP)
For the Three Months
  
For the Years
  
to Adjusted Net Income (Non-GAAP):
Ended December 31,
  
Ended December 31,
  
 
2008
  
2007
  
2008
  
2007
  
                 
Reported Net Income (Loss) (GAAP)
 $ (126,040 ) $ 32,874   $ 91,553   $ 189,712  
                         
Adjustments:
                        
Change in Net Profits Plan liability
   (80,941 )   43,875     (34,040 )   50,823  
Unrealized derivative (gain) loss
   (12,011 )   3,234     (11,209 )   5,458  
(Gain) loss on sale of proved properties
   (9,494 )   367     (63,557 )   367  
(Gain) loss on insurance settlement (2)
   696     1,097     2,296     (5,243 )
Bad debt expense associated with SemGroup, L.P.
   (5 )   -     16,635     -  
(Gain) loss related to hurricanes (3)
   -     -     6,980     -  
Tax adjustment at effective rate for period
   35,318     (17,071 )   32,771     (18,926 )
                         
Adjusted Net Income (Loss), before impairments
   (192,477 )   64,375     41,429     222,190  
                         
Non-cash impairments:
                        
Impairment of proved properties
   292,100     -     302,230     -  
Abandonment and impairment of unproved properties
   34,754     870     39,049     4,756  
Impairment of goodwill
   9,452     -     9,452     -  
Tax adjustment for impairments at effective rate for period
   (116,728 )   (306 )   (138,656 )   (1,751 )
                         
Adjusted Net Income, non recurring items
                        
& non cash impairments (4)
   27,101     64,939     253,504     225,195  
                         
Adjusted Net Income Per Share (Non-GAAP)
                        
Basic
 $ 0.44   $ 1.03   $ 4.07   $ 3.64  
Diluted
 $ 0.43   $ 1.00   $ 4.02   $ 3.48  
                         
Average Number of Shares Outstanding
                        
Basic
   62,212     63,300     62,243     61,852  
Diluted
   62,630     64,635     63,133     64,850  
                         
(2)   The (gain) loss on insurance settlement is included within line item other revenue on the consolidated statements of operations.
  
                         
(3)   The loss related to hurricanes is included within line item other expense on the consolidated statements of operations.
  
                         
(4)   Adjusted net income is calculated as net income (loss) adjusted for significant non-cash and non-recurring items. Non-cash charges include changes in
the Net Profits Plan liability, unusual and non-recurring bad debt expense, unrealized derivative gains and losses, impairment of proved properties, abandonment
and impairment of unproved properties, and impairment of goodwill. Non-recurring items include (gain) loss from sales of proved properties,
(gain) loss on insurance settlements, and (gain) loss related to hurricanes. The non-GAAP measure of adjusted net income is presented because management
believes it provides useful additional information to investors for analysis of St. Mary’s fundamental business on a recurring basis. In addition, management
believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of
companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment
decisions. Adjusted net income should not be considered in isolation or as a substitute for net income, income from operations, cash provided by operating activities
or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income excludes some, but not all, items that affect net income
and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies.

Discretionary Cash Flow
                
(In thousands)
                
                 
Reconciliation of Net Cash Provided by Operating Activities
For the Three Months
  
For the Years
  
(GAAP) to Discretionary Cash Flow (Non-GAAP):
Ended December 31,
  
Ended December 31,
  
 
2008
  
2007
  
2008
  
2007
  
Net cash provided by operating activities (GAAP)
 $ 110,120   $ 156,810   $ 678,221   $ 630,792  
                         
Exploration
   17,743     16,030     60,121     58,686  
        Less:  Exploratory dry hole expense
   (240 )   (1,651 )   (6,823 )   (14,365 )
        Less:  Stock-based compensation expense included in exploration
   (1,992 )   (599 )   (5,799 )   (3,215 )
Other
   97     5,329     3,593     10,497  
Bad debt expense
   (143 )   -     (16,735 )   -  
Changes in current assets and liabilities
   37,680     1,903     54,274     (50,405 )
Discretionary cash flow (Non-GAAP) (5)
 $ 163,265   $ 177,822   $ 766,852   $ 631,990  
                         
                         
(5)   Discretionary cash flow is computed as net income adjusted for (gain) loss on sale of proved properties, (gain) loss on insurance settlement, loss related
to hurricanes, depreciation, depletion, amortization and asset retirement obligation liability accretion, exploration expense, impairment of
proved properties, abandonment and impairment of unproved properties, impairment of goodwill, unrealized derivative (gain) loss, change in Net Profits Plan
liability, stock-based compensation expense, and deferred income taxes. 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.
                        

 
 
 

 ST. MARY LAND & EXPLORATION COMPANY
  
 FINANCIAL HIGHLIGHTS
  
 December 31, 2008
  
             
Information on Reserves and Costs Incurred
            
             
Costs incurred in oil and gas producing activities:
          
 
For the Year Ended
          
 
December 31,
          
 
2008
          
Development costs (6)
 $ 586,579          
Exploration costs
   92,199          
Acquisitions:
              
Proved properties
   51,567          
Unproved properties - acquisitions of
              
proved properties (7)
   43,274          
Unproved properties - other
   83,078          
Total, including asset retirement obligation (8)
 $ 856,697          
               
(6)   Includes capitalized interest of $3.7 million.
              
(7)   Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties.
(8)   Includes amounts relating to estimated asset retirement obligations of $15.4 million.
  
               
Proved oil and gas reserve quantities:
              
 
For the Year Ended
  
 
December 31, 2008
  
 
Oil or Condensate MMBbls
Gas BCF
  
BCFE
  
Developed and undeveloped:
              
Beginning of year
   78.8     613.5   1,086.5  
Revisions of previous estimate (9)
   (22.6 )   (108.3 ) (244.2 )
Discoveries and extensions
   0.7     41.1   45.1  
Infill reserves in an existing proved field
   5.4     92.4   125.0  
Purchases of minerals in place
   0.4     27.0   29.1  
Sales of reserves
   (4.7 )   (33.4 ) (61.4 )
Production
   (6.6 )   (74.9 ) (114.6 )
End of year
   51.4     557.4   865.5  
                 
Proved developed reserves
                
Beginning of year
   68.3     426.6   836.3  
End of year
   47.1     433.2   715.8  
                 
(9)   For the year ended December 31, 2008, of the (244.2) BCFE downward revision of previous estimate (199.7) BCFE relates to price and (44.5) BCFE relates to performance.
                 
Finding Cost and Reserve Replacement Ratios: (10)
            
                 
Finding Costs in $ per MCFE   Excluding Sales     Including Sales       
Drilling, excluding performance and price revisions
 $ 3.99   $ 6.25      
Drilling, including performance revisions
 $ 5.40   $ 10.57      
Drilling and acquisitions, excluding performance and price revisions
 $ 3.67   $ 5.30      
Drilling and acquisitions, including performance revisions
 $ 4.72   $ 7.83      
Acquisitions
 $ 1.77     n/a      
All-in, excluding price revisions
 $ 5.54   $ 9.18      
All-in, including performance and price revisions
 $ (19.04 ) $ (8.05 )    
                 
Reserve Replacement Ratios
                
Drilling, excluding performance and price revisions
   148%     95%      
Drilling, including performance revisions
   110%     56%      
Drilling and acquisitions, excluding performance and price revisions
   174%     120%      
Drilling and acquisitions, including performance revisions
   135%     81%      
Acquisitions
   25%     n/a      
All-in, excluding price revisions
   135%     81%      
All-in, including performance and price revisions
   -39%     -93%      
                 
(10) Finding costs and reserve replacement ratios are common metrics used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.  The metrics are easily calculated from information provided in the sections "Costs incurred in oil and gas producing activities" and "Proved oil and gas reserve quantities" above.  Finding cost provides some information as to the cost of adding proved reserves from various activities.  Reserve replacement provides information related to how successful a company is at growing its proved reserve base.  Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in "Costs incurred in oil and gas producing activities."  The Company uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
 
 
ST. MARY LAND & EXPLORATION COMPANY
FINANCIAL HIGHLIGHTS 
December 31, 2008
Finding Costs Definitions:
> Drilling, excluding performance and price revisions - numerator defined as the sum of development costs and exploration costs divided by a denominator defined as the sum of discoveries and extensions and infill reserves in an existing proved field. To consider the impact divestitures on this metric, further include sales of reserves in denominator.
> Drilling and acquisitions, excluding performance and price revisions - numerator defined as the sum of development costs, exploration costs, and acquisition costs for proved properties divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and purchases of minerals in place. To consider the impact divestitures on this metric, further include sales of reserves in denominator.
> Drilling and acquisitions, excluding performance and price revisions - numerator defined as the sum of development costs, exploration costs, and acquisition costs for proved properties divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and purchases of minerals in place. To consider the impact divestitures on this metric, further include sales of reserves in denominator. 
> Drilling and acquisitions, including performance revisions - numerator defined as the sum of development costs, exploration costs, and acquisition costs for proved properties divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions. To consider the impact divestitures on this metric, further include sales of reserves in denominator. 
> Acquisitions - numerator defined as acquisition costs for proved properties divided by a denominator defined as purchases of minerals in place. 
> All-in, excluding price revisions - numerator defined as total costs incurred, including asset retirement obligation divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions. To consider the impact divestitures on this metric, further include sales of reserves in denominator. 
> All-in, including performance and price revisions - numerator defined as total costs incurred, including asset retirement obligation divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions. To consider the impact divestitures on this metric, further include sales of reserves in denominator. 
 
Reserve Replacement Ratio Definitions:
> Drilling, excluding performance and price revisions - numerator defined as the of sum of discoveries and extensions and infill reserves in an existing proved field divided by production.  To consider the impact divestitures on this metric, further include sales of reserves in denominator.
> Drilling , including performance revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and performance revisions divided by production.  To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> Drilling and acquisitions, excluding  performance and price revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and purchases of minerals in place divided by production.  To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> Drilling and acquisitions, including performance revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions divided by production.  To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> Acquisitions - numerator defined as purchases of minerals in place divided by production.
> All-in, excluding price revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions divided by production.  To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
> All-in, including performance and price revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, performance revisions, and price revisions divided by production.  To consider the impact of divestitures on this metric, further include sales of reserves in denominator.