form_10q.htm




UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2009
 
Commission file number 001-31539
 
 
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
 
Delaware
(State or other jurisdiction
of incorporation or organization)
41-0518430
(I.R.S. Employer
Identification No.)

1776 Lincoln Street, Suite 700, Denver, Colorado
(Address of principal executive offices)
80203
(Zip Code)
 
(303) 861-8140
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
Yes þ  No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
 
Yes o  No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).
 
Yeso           No þ
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 
As of October 27, 2009 the registrant had 62,536,644 shares of common stock, $0.01 par value, outstanding.
 
 


 
 
 
 
 
ST. MARY LAND & EXPLORATION COMPANY
INDEX
 
Part I.
FINANCIAL INFORMATION
PAGE
       
 
Item 1.
Financial Statements (Unaudited)
 
       
   
Consolidated Balance Sheets
September 30, 2009, and December 31, 2008
3
       
   
Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2009, and 2008
4
       
   
Consolidated Statements of Stockholders’ Equity
and Comprehensive Income (Loss)
September 30, 2009, and December 31, 2008
5
       
   
Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2009, and 2008
6
       
   
Notes to Consolidated Financial Statements
September 30, 2009
8
       
 
Item 2.
Management’s Discussion and Analysis of Financial
Condition and Results of Operations
28
       
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
(included within the content of Item 2)
59
       
 
Item 4.
Controls and Procedures
59
       
Part II.
OTHER INFORMATION
 
       
 
Item 1A.
Risk Factors
59
       
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
60
       
 
Item 6.
Exhibits
61

 
 
 
 


PART I.  FINANCIAL INFORMATION
       
ITEM 1.   FINANCIAL STATEMENTS
       
         
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
(In thousands, except share amounts)
 
         
 
September 30,
 
December 31,
 
 
2009
 
2008
 
                                                         ASSETS
   
(As adjusted, Note 7)
 
Current assets:
       
Cash and cash equivalents
$ 20,517   $ 6,131  
Short-term investments
  -     1,002  
Accounts receivable, net of allowance for doubtful accounts
           
of $16,919 in 2009 and $16,788 in 2008
  98,709     157,690  
Refundable income taxes
  2,821     13,161  
Prepaid expenses and other
  16,802     22,161  
Accrued derivative asset
  41,428     111,649  
Total current assets
  180,277     311,794  
             
Property and equipment (successful efforts method), at cost:
           
Land
  1,371     1,350  
Proved oil and gas properties
  2,804,559     2,969,722  
Less - accumulated depletion, depreciation, and amortization
  (1,063,232 )   (947,207 )
Unproved oil and gas properties, net of impairment allowance
           
of $51,511 in 2009 and $42,945 in 2008
  147,825     168,817  
Wells in progress
  56,958     90,910  
Materials inventory, at lower of cost or market
  30,411     40,455  
Oil and gas properties held for sale less accumulated depletion,
           
depreciation, and amortization
  148,937     1,827  
Other property and equipment, net of accumulated depreciation
           
of $16,617 in 2009 and $13,848 in 2008
  14,516     13,458  
    2,141,345     2,339,332  
             
Other noncurrent assets:
           
Accrued derivative asset
  4,614     21,541  
Restricted cash subject to Section 1031 Exchange
  -     14,398  
Other noncurrent assets
  17,523     10,182  
Total other noncurrent assets
  22,137     46,121  
             
Total Assets
$ 2,343,759   $ 2,697,247  
             
LIABILITIES AND STOCKHOLDERS' EQUITY
       
Current liabilities:
           
Accounts payable and accrued expenses
$ 215,363   $ 254,811  
Accrued derivative liability
  25,370     501  
Deferred income taxes
  8,424     41,289  
Total current liabilities
  249,157     296,601  
             
Noncurrent liabilities:
           
Long-term credit facility
  235,000     300,000  
Senior convertible notes, net of unamortized
           
discount of $22,716 in 2009, and $28,787 in 2008
  264,784     258,713  
Asset retirement obligation
  68,682     108,755  
Asset retirement obligation associated with oil and gas properties held for sale
  23,711     238  
Net Profits Plan liability
  163,328     177,366  
Deferred income taxes
  285,042     354,328  
Accrued derivative liability
  46,315     27,419  
Other noncurrent liabilities
  11,623     11,318  
Total noncurrent liabilities
  1,098,485     1,238,137  
             
Commitments and contingencies
           
             
Stockholders' equity:
           
Common stock, $0.01 par value: authorized  - 200,000,000 shares;
           
issued:  62,638,839 shares in 2009 and 62,465,572 shares in 2008;
           
outstanding, net of treasury shares: 62,511,946 shares in 2009
           
and 62,288,585 shares in 2008
  626     625  
Additional paid-in capital
  151,620     141,283  
Treasury stock, at cost:  126,893 shares in 2009 and 176,987 shares in 2008
  (1,230 )   (1,892 )
Retained earnings
  850,593     957,200  
Accumulated other comprehensive income (loss)
  (5,492 )   65,293  
Total stockholders' equity
  996,117     1,162,509  
             
Total Liabilities and Stockholders' Equity
$ 2,343,759   $ 2,697,247  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
-3-
 
 
 
 


ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
(In thousands, except per share amounts)
 
 
               
 
For the Three Months
 
For the Nine Months
 
 
Ended September 30,
 
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
     
(As adjusted, Note 7)
     
(As adjusted, Note 7)
 
Operating revenues and other income:
               
Oil and gas production revenue
$ 152,651   $ 358,508   $ 428,347   $ 1,068,901  
Realized oil and gas hedge gain (loss)
  28,331     (53,491 )   127,230     (145,837 )
Gain (loss) on divestiture activity  (Note 13)
  (11,277 )   (4,992 )   (10,632 )   54,063  
Marketed gas system and other operating revenue
  16,082     24,063     45,260     66,005  
Total operating revenues and other income
  185,787     324,088     590,205     1,043,132  
                         
Operating expenses:
                       
Oil and gas production expense
  48,634     72,724     153,928     205,825  
Depletion, depreciation, amortization,
                       
and asset retirement obligation liability accretion
  66,958     72,362     229,061     219,070  
Exploration
  15,733     10,669     48,821     42,378  
Impairment of proved properties
  91     564     153,183     10,130  
Abandonment and impairment of unproved properties
  4,761     1,231     20,294     4,295  
Impairment of materials inventory
  2,114     -     13,449     -  
General and administrative
  20,790     24,145     55,349     67,149  
Bad debt expense
  -     6,650     -     16,592  
Change in Net Profits Plan liability
  6,804     (34,867 )   (14,038 )   46,901  
Marketed gas system expense
  14,360     22,960     41,352     60,918  
Unrealized derivative (gain) loss
  4,117     (4,429 )   17,251     802  
Other expense
  968     7,753     12,424     9,155  
Total operating expenses
  185,330     179,762     731,074     683,215  
                         
Income (loss) from operations
  457     144,326     (140,869 )   359,917  
 
                       
Nonoperating income (expense):
                       
Interest income
  90     239     217     395  
Interest expense
  (7,565 )   (7,026 )   (21,324 )   (20,862 )
                         
Income (loss) before income taxes
  (7,018 )   137,539     (161,976 )   339,450  
Income tax benefit (expense)
  2,603     (50,542 )   61,616     (125,010 )
                         
Net income (loss)
$ (4,415 ) $ 86,997   $ (100,360 ) $ 214,440  
                         
Basic weighted-average common shares outstanding
  62,505     62,187     62,420     62,254  
                         
Diluted weighted-average common shares outstanding
  62,505     63,078     62,420     63,327  
                         
Basic net income (loss) per common share
$ (0.07 ) $ 1.40   $ (1.61 ) $ 3.44  
                         
Diluted net income (loss) per common share
$ (0.07 ) $ 1.38   $ (1.61 ) $ 3.39  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
-4-
 
 
 
 


ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 
(In thousands, except share amounts)
 
                                 
                         
Accumulated
     
         
Additional
             
Other
 
Total
 
 
Common Stock
 
Paid-in
 
Treasury Stock
 
Retained
 
Comprehensive
 
Stockholders'
 
 
Shares
 
Amount
 
Capital
 
Shares
 
Amount
 
Earnings
 
Income (Loss)
 
Equity
 
                                 
Balances, December 31, 2007 (As adjusted, Note 7)
64,010,832   $ 640   $ 211,913   (1,009,712 ) $ (29,049 ) $ 876,038   $ (156,968 ) $ 902,574  
                                             
Comprehensive income, net of tax:
                                           
 Net income (As adjusted, Note 7)
-     -     -   -     -     87,348     -     87,348  
 Change in derivative instrument fair value
-     -     -   -     -     -     177,005     177,005  
 Reclassification to earnings
-     -     -   -     -     -     46,463     46,463  
 Minimum pension liability adjustment
-     -     -   -     -     -     (1,207 )   (1,207 )
Total comprehensive income
                                        309,609  
Cash dividends, $ 0.10 per share
-     -     -   -     -     (6,186 )   -     (6,186 )
Treasury stock purchases
-     -     -   (2,135,600 )   (77,150 )   -     -     (77,150 )
Retirement of treasury stock
(2,945,212 )   (29 )   (103,237 ) 2,945,212     103,266     -     -     -  
Issuance of common stock under Employee
                                         
 Stock Purchase Plan
45,228     -     1,055   -     -     -     -     1,055  
Issuance of common stock upon settlement of
                                         
RSUs following expiration of restriction period,
                                         
net of shares used for tax withholdings
482,602     5     (6,910 ) -     -     -     -     (6,905 )
Sale of common stock, including income
                                         
tax benefit of stock option exercises
868,372     9     24,691   -     -     -     -     24,700  
Stock-based compensation expense
3,750     -     13,771   23,113     1,041     -     -     14,812  
                                             
Balances, December 31, 2008 (As adjusted, Note 7)
62,465,572   $ 625   $ 141,283   (176,987 ) $ (1,892 ) $ 957,200   $ 65,293   $ 1,162,509  
                                             
Comprehensive loss, net of tax:
                                           
Net loss
-     -     -   -     -     (100,360 )   -     (100,360 )
Change in derivative instrument fair value
-     -     -   -     -     -     (12,810 )   (12,810 )
Reclassification to earnings
-     -     -   -     -     -     (57,979 )   (57,979 )
Minimum pension liability adjustment
-     -     -   -     -     -     4     4  
Total comprehensive loss
                                        (171,145 )
Cash dividends, $ 0.10 per share
-     -     -   -     -     (6,247 )   -     (6,247 )
Issuance of common stock under Employee
                                         
Stock Purchase Plan
49,767     -     858   -     -     -     -     858  
Issuance of common stock upon settlement of
                                         
    RSUs following expiration of restriction period,
                                         
    net of shares used for tax withholdings,
                                         
including income tax cost of RSUs
89,236     1     (3,157 ) -     -     -     -     (3,156 )
Sale of common stock, including income
                                         
tax benefit of stock option exercises
33,014     -     320   -     -     -     -     320  
Stock-based compensation expense
1,250     -     12,316   50,094     662     -     -     12,978  
                                             
Balances, September 30, 2009
62,638,839   $ 626   $ 151,620   (126,893 ) $ (1,230 ) $ 850,593   $ (5,492 ) $ 996,117  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
-5-
 
 
 
 

 
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
(In thousands)
 
         
 
For the Nine Months
 
 
Ended September 30,
 
 
2009
 
2008
 
     
(As adjusted, Note 7)
 
Cash flows from operating activities:
       
Reconciliation of net income (loss) to net cash provided
       
by operating activities:
       
Net income (loss)
$ (100,360 ) $ 214,440  
Adjustments to reconcile net income (loss) to net cash
           
provided by operating activities:
           
(Gain) loss on divestiture activities
  10,632     (54,063 )
Depletion, depreciation, amortization,
           
and asset retirement obligation liability accretion
  229,061     219,070  
Exploratory dry hole expense
  4,849     6,583  
Impairment of proved properties
  153,183     10,130  
Abandonment and impairment of unproved properties
  20,294     4,295  
Impairment of materials inventory
  13,449     -  
Stock-based compensation expense*
  12,978     10,477  
Bad debt expense
  -     16,592  
Change in Net Profits Plan liability
  (14,038 )   46,901  
Unrealized derivative loss
  17,251     802  
Loss related to hurricanes
  8,273     6,980  
Loss on insurance settlement
  -     1,600  
Amortization of debt discount and deferred financing costs
  8,922     6,942  
Deferred income taxes
  (69,082 )   99,380  
Plugging and abandonment
  (12,110 )   (1,355 )
Other
  1,432     (3,416 )
Changes in current assets and liabilities:
           
Accounts receivable
  58,844     (39,455 )
Refundable income taxes
  10,340     (3,650 )
Prepaid expenses and other
  (8,660 )   2,029  
Accounts payable and accrued expenses
  7,794     34,763  
Excess income tax benefit from the exercise of stock options
  -     (10,281 )
Net cash provided by operating activities
  353,052     568,764  
             
Cash flows from investing activities:
           
Proceeds from insurance settlement
  15,336     -  
Proceeds from sale of oil and gas properties
  1,137     155,203  
Capital expenditures
  (292,466 )   (495,155 )
Acquisition of oil and gas properties
  (58 )   (83,433 )
Receipts from restricted cash
  14,398     -  
Receipts from short-term investments
  1,002     161  
Other
  -     (9,984 )
Net cash used in investing activities
  (260,651 )   (433,208 )
             
Cash flows from financing activities:
           
Proceeds from credit facility
  1,898,500     832,000  
Repayment of credit facility
  (1,963,500 )   (947,000 )
Debt issuance costs related to credit facility
  (11,074 )   -  
Excess income tax benefit from the exercise of stock options
  -     10,281  
Proceeds from sale of common stock
  1,179     11,327  
Repurchase of common stock
  -     (77,202 )
Dividends paid
  (3,120 )   (3,076 )
Net cash used in financing activities
  (78,015 )   (173,670 )
             
Net change in cash and cash equivalents
  14,386     (38,114 )
Cash and cash equivalents at beginning of period
  6,131     43,510  
Cash and cash equivalents at end of period
$ 20,517   $ 5,396  
             
* Stock-based compensation expense is a component of exploration expense and general and administrative expense on
 
the consolidated statements of operations. For the nine months ended September 30, 2009, and 2008, respectively,
 
approximately $4.4 million and $3.8 million of stock-based compensation expense was included in exploration expense.
 
For the nine months ended September 30, 2009, and 2008, respectively, approximately $8.6 million and $6.7 million of
 
stock-based compensation expense was included in general and administrative expense.
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
-6-
 
 
 
 
 

 
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)
 
           
           
           
Supplemental schedule of additional cash flow information and noncash investing and financing activities:
           
   
For the Nine Months
 
   
Ended September 30,
 
   
2009
 
2008
 
   
(In thousands)
 
           
Cash paid for interest
  $ 11,150   $ 14,483  
               
Cash paid (refunded) for income taxes
  $ (10,119 $ 18,943  
               
               
Dividends of approximately $3.1 million have been declared by the Company's Board of Directors, but
not paid, as of September 30, 2009.
             
               
In August 2009 and 2008, the Company issued 725,092 and 465,751 Performance Share Awards to
 
employees as equity-based compensation pursuant to the Company's Equity Incentive Compensation
Plan. The total fair value of the issuance equaled $25.8 million and $12.3 million respectively.
 
               
During the first nine months of 2009 and 2008, the Company issued 241,745 and 427,607 restricted stock
units respectively, to employees as equity-based compensation, pursuant to the Company's Equity
Incentive Compensation Plan. The total fair value of the issuances was $5.8 million and $23.3 million
respectively.
             
               
As of September 30, 2009, and 2008, $59.8 million, and $159.5 million, respectively, are included as
 
additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas
property additions are reflected in cash used in investing activities in the periods that the payables are
settled.
             
               
In May 2009 and 2008 the Company issued 50,094 and 23,113 shares, respectively, of common stock
from treasury to its non-employee directors pursuant to the Company's Equity Incentive Compensation
Plan. The Company recorded compensation expense related to these issuances of approximately
$662,000 and $922,000 for the nine-month periods ended September 30, 2009, and 2008, respectively.
               
In September 2008, the Company hired a new senior executive. Upon commencement of employment,
the Company issued 15,496 shares of restricted stock awards to the senior executive, of which half will
vest on December 15, 2009, and the remaining half will vest on December 15, 2010, provided on such
vesting dates the executive is employed by the Company. The total fair value of the issuance was
$600,005.
             

The accompanying notes are an integral part of these consolidated financial statements.
 
-7-
 
 
 
 

ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
 
September 30, 2009
 
Note 1 – The Company and Business
 
St. Mary Land & Exploration Company (“St. Mary” or the “Company”) is an independent energy company engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil.  The Company’s operations are conducted entirely in the continental United States.
 
Note 2 – Basis of Presentation and Significant Accounting Policies
 
Basis of Presentation
 
The accompanying unaudited condensed consolidated financial statements of St. Mary have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and the instructions to Form 10-Q and Regulation S-X.  They do not include all information and notes required by generally accepted accounting principles (“GAAP”) for complete financial statements.  However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in St. Mary’s Annual Report on Form 10-K for the year ended December 31, 2008.  In the opinion of management, all adjustments, consisting of normal recurring accruals that are considered necessary for fair presentation of the interim financial information, have been included.  Operating results for the periods presented are not necessarily indicative of expected results for the full year.  In connection with the preparation of the condensed consolidated financial statements of St. Mary and in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 855, “Subsequent Events” (“ASC Topic 855”) the Company evaluated subsequent events after the balance sheet date of September 30, 2009, through the filing of this report, November 3, 2009.  Please refer to Note 3 – Recent Accounting Pronouncements for additional information regarding ASC.
 
On January 1, 2009, the adoption of new authoritative accounting guidance under FASB ASC Topic 470-20, “Debt with Conversion and Other Options” (“ASC Topic 470”) required retrospective application.  As a result, prior period balances presented have been adjusted to reflect the period-specific effects of applying ASC Topic 470.  Please refer to Note 7 – Long-term Debt for additional information regarding adoption.
 
Materials Inventory
 
The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling or repair operations.  Materials inventory is valued at the lower of cost or market and totaled $30.4 million and $40.5 million at September 30, 2009, and December 31, 2008, respectively.  The Company incurred net materials inventory write-downs for the three-month and nine-month periods ended September 30, 2009, totaling $2.1 million and $13.4 million, respectively, as a result of the decrease in the value of tubular goods.  There were no materials inventory write-downs for the three-month and nine-month periods ended September 30, 2008.
 
-8-
 
 
 
 
 
Other Significant Accounting Policies
 
The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Form 10-K for the year ended December 31, 2008, and are supplemented throughout the footnotes of this document.  It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes included in St. Mary’s Annual Report on Form 10-K for the year ended December 31, 2008.
 
Note 3 – Recent Accounting Pronouncements
 
New authoritative accounting guidance under FASB ASC Topic 105, “Generally Accepted Accounting Principles” (“ASC Topic 105”) establish FASB Accounting Standards Codification as the source of authoritative U.S. GAAP recognized by the FASB to be applied to rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under federal securities laws as authoritative GAAP for SEC registrants.  ASC Topic 105 supersedes existing FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force and related literature.  All other accounting literature is considered non-authoritative.  ASC Topic 105 changes the way the Company cites authoritative guidance within the Company’s financial statements and accounting policies.  The new authoritative guidance under ASC Topic 105 became effective for periods ending on or after September 15, 2009, and did not have a material impact on the Company’s consolidated financial statements.
 
 
New authoritative accounting guidance under FASB ASC Topic 805, “Business Combinations” (“ASC Topic 805”) requires the acquiring entity in a business combination to recognize and measure all assets and liabilities assumed in the transaction and any non-controlling interest in the acquiree at fair value as of the acquisition date.  ASC Topic 805 changes the way the Company accounts for acquisitions of oil and gas properties.  Such acquisitions will now be treated as business combinations, which will require transaction costs to be expensed as incurred, may generate gains or losses due to changes between the effective and closing dates of acquisitions, and will require possible recognition of goodwill given differences between the purchase price and fair value of assets received.  ASC Topic 805 further amends the initial recognition and measurement, subsequent measurement and accounting, and disclosures of assets and liabilities arising from contingencies in a business combination.  The new authoritative guidance under ASC Topic 805 became effective for the Company on January 1, 2009, and the impact on the Company’s consolidated financial statements will largely be dependent on the size and nature of the business combinations completed.  There have not been any significant acquisitions of oil and gas properties since adoption.
 
New authoritative accounting guidance under FASB ASC Topic 810, “Consolidation” (“ASC Topic 810”) established accounting and reporting standards that require noncontrolling interests to be reported as a component of equity along with any changes in the parent’s ownership interest.  The new authoritative guidance under ASC Topic 810 became effective for the Company on January 1, 2009, and did not have a material impact on the Company’s consolidated financial statements.
 
New authoritative accounting guidance under FASB ASC Topic 825, “Financial Instruments” (“ASC Topic 825”) requires the Company to include disclosures about the fair value of its financial instruments whenever it issues financial information for interim reporting periods and annual reporting periods, whether recognized or not recognized in the statement of financial position.  The new authoritative guidance under ASC Topic 825 became effective for the Company on April 1, 2009, and did not have a material impact on the Company’s consolidated financial statements.
 
New authoritative accounting guidance under ASC Topic 855 established general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  ASC Topic 855 requires companies to disclose the date through which the company evaluated subsequent events, the basis for that date, and whether that date represents the date the financial statements were issued.  The new authoritative guidance under ASC Topic
 
-9-
 
 
 
 
 
855 became effective for the Company on April 1, 2009, and did not have a material impact on the Company’s consolidated financial statements.
 
In December 2008 the SEC published the final rules and interpretations updating its oil and gas reporting requirements.  Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which was developed by several industry organizations and is a widely accepted standard for the management of petroleum resources.  Key revisions include a requirement to use 12-month average pricing rather than year-end pricing for estimating proved reserves, the ability to include nontraditional resources in reserves, the ability to use new technology for determining proved reserves, and permitting disclosure of probable and possible reserves.  The new authoritative guidance will be effective for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009.  Early adoption is not permitted.  The Company will apply this new authoritative guidance in the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2009.  The Company is currently assessing the impact of this new authoritative guidance on the Company’s consolidated financial statements.
 
Newly proposed authoritative accounting guidance by the FASB would align FASB ASC Topic 932, “Extractive Activities – Oil and Gas” with all of the aforementioned SEC requirements.  This proposal is expected to become an issued accounting update within the last quarter of 2009 with an effective date for annual reports for fiscal years ending on or after December 15, 2009.  The Company is currently assessing the impact of this new authoritative accounting guidance on the Company’s consolidated financial statements.
 
New authoritative accounting guidance under FASB ASC Topic 715, “Compensation – Retirement Benefits” (“ASC Topic 715”) amends the disclosure requirements of plan assets for defined benefit pensions and other postretirement plans.  The objective of ASC Topic 715 is to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets held by the plans, the inputs and valuation techniques used to measure the fair value of plan assets, significant concentration of risk within a company’s plan assets, fair value measurements determined using significant unobservable inputs, and a reconciliation of changes between the beginning and ending balances.  ASC Topic 715 will be effective for fiscal years ending after December 15, 2009.  The disclosures required by ASC Topic 715 will be included in the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2009.  The Company is currently assessing the impact of ASC Topic 715 on the Company’s consolidated financial statements.
 
Please refer to Note 7 – Long-term Debt, Note 8 – Derivative Financial Instruments, and Note 11 – Fair Value Measurements for additional information on the recent adoption of new authoritative accounting guidance.
 
Note 4 – Earnings per Share
 
Basic net income or loss per common share of stock is calculated by dividing net income or loss available to common stockholders by the weighted-average basic common shares outstanding for the respective period.  The shares represented by vested restricted stock units (“RSUs”) are included in the calculation of the weighted-average basic common shares outstanding.  The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.
 
Diluted net income or loss per common share of stock is calculated by dividing adjusted net income or loss by the weighted-average diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested RSUs, in-the-money outstanding options to purchase the Company’s common stock, unearned Performance Share Awards (“PSAs”), and shares into which the 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”) are convertible.
 
-10-
 
 
 
 
 
The Company’s 3.50% Senior Convertible Notes have a net-share settlement right whereby each $1,000 principal amount of notes may be surrendered for conversion to cash in an amount equal to the principal amount and, if applicable, shares of common stock or cash or any combination of common stock and cash for the amount in excess of the principal amount.  The treasury stock method is used to measure the potentially dilutive impact of shares associated with that conversion feature.  The 3.50% Senior Convertible Notes have not been dilutive for any reporting period that they have been outstanding and therefore do not impact the diluted earnings per share calculation for the three-month or nine-month periods ended September 30, 2009, and 2008, respectively.
 
The Company’s PSAs have a three-year performance period.  The PSAs represent the right to receive, upon settlement of the PSAs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may be from zero to two times the number of PSAs granted on the award date, depending on the extent to which the Company’s performance criteria have been achieved and the extent to which the PSAs have vested.  The performance criteria for the PSAs are based on a combination of the Company’s total shareholder return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the TSR of certain peer companies for the performance period.  There were no potentially dilutive shares related to the PSAs included in the diluted earnings per share calculation for the three-month or nine-month periods ended September 30, 2009, and 2008.  For additional discussion on the PSAs, please see Note 5 – Compensation Plans under the heading Performance Share Awards Under the Equity Incentive Compensation Plan.
 
The treasury stock method is used to measure the dilutive impact of stock options, RSUs, 3.50% Senior Convertible Notes, and PSAs.  In accordance with FASB ASC Topic 260, “Earnings Per Share” when there is a loss from continuing operations, all potentially dilutive shares will be anti-dilutive.  As such, there were no dilutive shares for the three-month or nine-month periods ended September 30, 2009.  Unvested RSUs and in-the-money options had a dilutive impact for the three-month and nine-month periods ended September 30, 2008, as calculated in the table below.
 
The following table sets forth the calculation of basic and diluted earnings per share:
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
(As adjusted,
Note 7)
 
2009
 
2008
(As adjusted,
Note 7)
 
 
(In thousands, except per share amounts)
 
                 
Net income (loss)
$ (4,415 ) $ 86,997   $ (100,360 ) $ 214,440  
                         
Basic weighted-average common shares outstanding
  62,505     62,187     62,420     62,254  
Add: dilutive effect of stock options, unvested RSUs, and PSAs
  -     891     -     1,073  
Add: dilutive effect of 3.50% senior convertible notes
  -     -     -     -  
Diluted weighted-average common shares outstanding
  62,505     63,078     62,420     63,327  
                         
Basic net income (loss) per common share
$ (0.07 ) $ 1.40   $ (1.61 ) $ 3.44  
Diluted net income (loss) per common share
$ (0.07 ) $ 1.38   $ (1.61 ) $ 3.39  

-11-
 
 
 
 
 
Note 5 – Compensation Plans
 
Cash Bonus Plan
 
During the first quarters of 2009 and 2008, the Company paid $6.0 million and $3.5 million for cash bonuses earned in the 2008 and 2007 performance years, respectively.  Within the general and administrative expense and exploration expense line items in the accompanying consolidated statements of operations was $3.2 million and $2.7 million of cash bonus expense related to the specific performance year for the three-month periods ended September 30, 2009, and 2008, respectively, and $8.5 million and $7.2 million for the nine-month periods ended September 30, 2009, and 2008, respectively.
 
Performance Share Awards Under the Equity Incentive Compensation Plan
 
Total stock-based compensation expense related to PSAs for the three-month periods ended September 302009, and 2008, was $3.2 million and $789,000, respectively, and $5.7 million and $789,000 for the nine-month periods ended September 30, 2009, and 2008, respectively.  As of September 30, 2009, there was $29.0 million of total unrecognized compensation expense related to unvested PSAs.  The unrecognized compensation expense will be amortized through 2012.
 
A summary of the status and activity of PSAs for the nine-month period ended September 30, 2009, is presented in the following table:
 
 
PSAs
 
Weighted-Average Grant-Date Fair Value
 
Non-vested, at January 1, 2009
464,333   $ 26.48  
Granted
725,092   $ 35.59  
Vested
(62,562 ) $ 26.48  
Forfeited
(29,400 ) $ 27.41  
Non-vested, at September 30, 2009
1,097,463   $ 32.47  
 
The Company granted a total of 725,092 PSAs on August 1, 2009, and recorded compensation expense of $2.2 million for this grant for the three-month period ended September 30, 2009.  The fair value of this grant was $25.8 million.  The PSAs from this grant represent the right to receive shares of the Company’s common stock upon settlement of a three-year performance period ending June 30, 2012.  These PSAs vest 1/7th on August 1, 2010, 2/7ths on August 1, 2011, and 4/7ths on August 1, 2012.  For additional discussion on the PSAs, please see Note 4 – Earnings per Share.
 
Restricted Stock Incentive Program Under the Equity Incentive Compensation Plan
 
Total RSU compensation expense for the three-month periods ended September 302009, and 2008, was $2.1 million and $2.5 million, respectively, and $5.9 million and $8.5 million for the nine-month periods ended September 30, 2009, and 2008, respectively.  As of September 30, 2009, there was $12.4 million of total unrecognized compensation expense related to unvested RSU awards.  The unrecognized compensation expense will be amortized through 2012.
 
During the first nine months of 2009, the Company converted 128,427 RSUs, which relate to awards granted in 2008, 2007, and 2006, into shares of the Company’s common stock based on the terms or amended terms of the RSU awards.  The Company and the majority of the grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and the award agreements.  As a result, the Company issued 90,486 shares of common stock
 
-12-
 
 
 
 
 
associated with these grants.  The remaining 37,941 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs.
 
A summary of the status and activity of non-vested RSUs for the nine-month period ended September 30, 2009, is presented in the following table:
 
 
RSUs
 
Weighted-Average Grant-Date Fair Value
 
Non-vested, at January 1, 2009
402,297   $ 48.24  
Granted
241,745   $ 23.87  
Vested
(122,569 ) $ 34.93  
Forfeited
(20,671 ) $ 52.27  
Non-vested, at September 30, 2009
500,802   $ 39.57  
 
As of September 30, 2009, a total of 502,035 RSUs were outstanding, of which 1,233 were vested.
 
The Company granted a total of 241,745 RSUs on August 1, 2009, and recorded compensation expense of $360,000 for this grant during the three-month period ended September 30, 2009.  The fair value of this grant was $5.8 million.  Each RSU from this award represents a right to receive one share of the Company’s common stock to be delivered upon settlement of the vested RSUs.  These RSUs vest 1/7th on August 1, 2010, 2/7ths on August 1, 2011, and 4/7ths on August 1, 2012.
 
Stock Option Grants Under the Equity Incentive Compensation Plan
 
The following table summarizes the nine-month activity for stock options outstanding as of September 30, 2009:
 
 
Options
 
Weighted-Average Exercise
Price
 
Weighted Average Remaining Contractual Term
(In years)
 
Aggregate Intrinsic Value
(In thousands)
 
                 
Outstanding, at January 1, 2009
1,509,710   $ 12.69          
Exercised
(33,014 ) $ 9.69          
Forfeited
(45,050 ) $ 13.38          
Outstanding, end of period
1,431,646   $ 12.74   2.97   $ 28,228  
Vested, or expect to vest, at September 30, 2009
1,431,646   $ 12.74   2.97   $ 28,228  
Exercisable, end of period
1,431,646   $ 12.74   2.97   $ 28,228  
 
As of September 30, 2009, there was no unrecognized compensation cost related to unvested stock option awards.
 
Director Shares
 
In May 2009 and 2008 the Company issued 50,094 and 23,113 shares, respectively, of the Company’s common stock from treasury to the Company’s non-employee directors.  The shares were issued pursuant to the Company’s Equity Incentive Compensation Plan.  The Company recorded $26,000 and $119,000 of compensation expense for the three-month periods ended September 30, 2009, and 2008,
 
-13-
 
 
 
 
 
respectively, and $662,000 and $922,000 for the nine-month periods ended September 30, 2009, and 2008, respectively.
 
Employee Stock Purchase Plan
 
Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (the “ESPP” or “the Plan”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation.  The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP are restricted for a period of 18 months from the date issued. Effective January 1, 2010, shares issued under the ESPP will be restricted for a period of six months.  The ESPP is intended to qualify under Section 423 of the Internal Revenue Code.  The Company has set aside 2,000,000 shares of its common stock to be available for issuance under the ESPP, of which 1,504,816 shares are available for issuance as of September 30, 2009.  The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.  There were 49,767 and 17,626 shares issued under the ESPP during the first nine months of 2009 and 2008, respectively.  The Company expensed $153,000 and $85,000 for the three-month periods ended September 30, 2009, and 2008, respectively and $694,000 and $250,000 for the nine-month periods ended September 30, 2009, and 2008, respectively based on the estimated fair values on the respective grant dates.
 
Net Profits Interest Bonus Plan
 
Under the Company’s Net Profits Interest Bonus Plan (“Net Profits Plan”), all oil and gas wells that were completed or acquired during a year were designated within a specific pool.  Key employees of the Company became entitled to payments under the Net Profits Plan based on specific cash flow and cost metrics.  The 2007 Net Profits Plan pool was the last pool established by the Company.
 
Cash payments made under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below:
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(In thousands)
 
                 
General and administrative expense
$ 5,168   $ 9,274   $ 12,942   $ 27,139  
Exploration expense
  239     1,142     1,116     6,360  
Total
$ 5,407   $ 10,416   $ 14,058   $ 33,499  
 
Additionally, the Company made cash payments under the Net Profits Plan of $12.4 million for the nine-month period ended September 30, 2008, as a result of sales proceeds from the Abraxas and Greater Green River Basin divestitures.  The cash payments are accounted for as a reduction in the gain (loss) on divestiture activity in the accompanying consolidated statements of operations.  There were no cash payments made under the Net Profits Plan during the third quarter of 2008 or during the first three quarters of 2009 as a result of divestitures that have been accounted for as a reduction in the gain (loss) on divestiture activity.
 
The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying unaudited consolidated statements of operations.  The change in the estimated liability is recorded as a non-cash expense or benefit in the current period.  The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production.  The table below presents the estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific functional line items based on the current allocation of
 
-14-
 
 
 
 
 
actual distributions made by the Company.  As time progresses, less of the distributions relate to prospective exploration efforts as more of the distributions are made to employees that have terminated employment and do not provide ongoing exploration support.
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(In thousands)
 
                 
General and administrative expense (benefit)
$ 5,807   $ (25,291 ) $ (12,923 ) $ 37,997  
Exploration expense (benefit)
  997     (9,576 )   (1,115 )   8,904  
Total
$ 6,804   $ (34,867 ) $ (14,038 ) $ 46,901  
 
Note 6 – Income Taxes
 
Income tax expense (benefit) for the three-month and nine-month periods ended September 30, 2009, and 2008, differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate to income (loss) before income taxes as a result of the estimated effect of the domestic production activities deduction, percentage depletion, the effect of state income taxes, and other permanent differences.
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(In thousands)
 
Current portion of income tax expense:
               
Federal
$ 2,881   $ 5,415   $ 6,129   $ 24,155  
State
  451     509     1,337     1,475  
Deferred portion of income tax expense (benefit)
  (5,935 )   44,618     (69,082 )   99,380  
Total income tax expense (benefit)
$ (2,603 ) $ 50,542   $ (61,616 ) $ 125,010  
Effective tax rates
  37.1%     36.7%     38.0%     36.8%  
 
A change in the Company’s effective tax rates between reported periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income between state tax jurisdictions resulting from Company activities.  Current low commodity prices and uncertain future pricing are causing the rate to vary from period to period as estimates for the domestic production activities deduction, percentage depletion, the impact of potential permanent state differences, and the impact of net operating loss carrybacks effect the periods presented differently.
 
The Company or its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states.  With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by tax authorities for years before 2006.  The Internal Revenue Service completed its 2005 audit in March 2009 and refunded the Company $278,000 plus interest of $41,000.  Related amended State income tax returns were filed in the second quarter of 2009.  There was no change to the provision for income tax expense as a result of the examination.  The Company received $980,000 in the first quarter of 2008 for income tax refunds and accrued interest resulting from a carry-over of minimum tax credits to its 2003 tax year.
 
-15-
 
 
 
 
 
Note 7 – Long-term Debt
 
Revolving Credit Facility
 
The Company executed a Third Amended and Restated Credit Agreement on April 14, 2009.  This amended revolving credit facility replaced the previous facility.  The Company incurred $11.1 million of deferred financing costs in association with the amended credit facility.  Borrowings under the facility are secured by a pledge, in favor of the lenders, of collateral that includes the majority of the Company’s oil and gas properties.  The credit facility specifies a maximum loan amount of $1.0 billion and has a maturity date of July 31, 2012.  The authorized borrowing base under the credit facility is subject to regular semi-annual redeterminations.  The borrowing base redetermination process considers the value of St. Mary’s oil and gas properties and other assets, as determined by the bank syndicate.  On September 29, 2009, the lending group redetermined and maintained the Company’s reserve-backed borrowing base under the credit facility at an amount of $900 million.  The Company has an aggregate commitment amount of $678 million under the credit facility.  The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement, including the limitation of the Company’s annual dividend rate to no more than $0.25 per share.  The Company is in compliance with all financial and non-financial covenants under the credit facility as of September 30, 2009, and through the date of this filing.  Interest and commitment fees are accrued based on the borrowing base utilization grid below.  Eurodollar loans accrue interest at the London Interbank Offered Rate (“LIBOR”) plus the applicable margin from the utilization table, and Alternative Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table.  Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying consolidated statements of operations.
 
Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
<25%
>25% <50%
>50% <75%
>75%
Eurodollar Loans
 2.000%
 2.250%
 2.500%
 2.750%
ABR Loans or Swingline Loans
 1.000%
 1.250%
 1.500%
 1.750%
Commitment Fee Rate
 0.500%
 0.500%
 0.500%
 0.500%
 
The Company had $235.0 million and $215.0 million outstanding under its revolving credit agreement as of September 30, 2009, and October 27, 2009, respectively.  The Company had $441.7 million and $462.4 million of available borrowing capacity under this facility as of September 30, 2009, and October 27, 2009, respectively.  The Company has a single letter of credit outstanding in the amount of $1.3 million and $569,000 as of September 30, 2009, and October 27, 2009, respectively.  This letter of credit reduces the amount available under the commitment amount on a dollar-for-dollar basis.
 
New authoritative accounting guidance under FASB ASC Topic 470
 
Effective January 1, 2009, the new authoritative accounting guidance under ASC Topic 470 required issuers of convertible debt that may be settled fully or partially in cash upon conversion to account separately for the liability and equity components of the debt in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods.  ASC Topic 470 applies to the Company’s 3.50% Senior Convertible Notes.  Under the adoption provisions of ASC Topic 470, the Company retrospectively applied its provisions and restated the Company’s consolidated financial statements for prior periods.
 
Under the provisions of ASC Topic 470, $42.0 million of the carrying value of the 3.50% Senior Convertible Notes was recorded as additional paid-in capital as of the April 4, 2007 issuance date.  This amount represents the equity component of the proceeds from the 3.50% Senior Convertible Notes, calculated assuming a 7.0% discount rate, which is the estimate of what the Company’s borrowing rate for a
 
-16-
 
 
 
 
 
similar debt instrument without the conversion feature would have been at the date of the issuance of the 3.50% Senior Convertible Notes.  Upon retrospective application, the adoption resulted in a $6.8 million decrease in the Company’s retained earnings at December 31, 2008, which was comprised of non-cash interest expense of $10.8 million, net of capitalized interest of $2.2 million, less deferred taxes of $4.0 million, for the period from April 4, 2007, through December 31, 2008.  The following table presents the December 31, 2008, consolidated balance sheet line items affected as adjusted and as originally reported:
 
 
December 31, 2008
 
 
As Adjusted
 
As Originally
Reported
 
 
(In thousands)
 
Proved oil and gas properties
$ 2,969,722   $ 2,967,491  
3.50% Senior Convertible Notes
  258,713     287,500  
Noncurrent deferred income taxes
  354,328     358,334  
Additional paid-in capital
  141,283     99,440  
Retained earnings
  957,200     964,019  
 
As of September 30, 2009, and December 31, 2008, the carrying value of the equity component was $42.0 million.  The principal amount of the 3.50% Senior Convertible Notes, the unamortized debt discount, and the net carrying amounts were as follows:
 
 
As of
September 30, 2009
 
As of
December 31, 2008
(Adjusted)
 
 
(In thousands)
 
         
3.50% Senior Convertible Notes
$ 287,500   $ 287,500  
Unamortized debt discount
  (22,716 )   (28,787 )
Net carrying amount of the 3.50% Senior Convertible Notes
$ 264,784   $ 258,713  
 
The Company amortized $2.0 million and $1.9 million of the debt discount for the three months ended September 30, 2009, and 2008, respectively, and $6.0 million and $5.7 million for the nine months ended September 30, 2009, and 2008, respectively.  Accumulated amortization related to the debt discount was $19.1 million as of September 30, 2009.  The remaining unamortized debt discount will be amortized under the interest method over the next 30 months.
 
-17-
 
 
 
 
 
The consolidated statements of operations were retroactively adjusted compared to previously reported amounts as follows:
 

 
For the Three Months
Ended September 30, 2008
 
For the Nine Months
Ended September 30, 2008
 
 
As Adjusted
 
As Originally
Reported
 
As Adjusted
 
As Originally
Reported
 
 
(In thousands except per share amounts)
 
                 
Interest expense
$ 7,026   $ 5,359   $ 20,862   $ 15,858  
Income tax expense
  50,542     51,159     125,010     126,861  
Net income
  86,997     88,047     214,440     217,593  
Basic net income per common share
$ 1.40   $ 1.42   $ 3.44   $ 3.50  
Diluted net income per common share
$ 1.38   $ 1.40   $ 3.39   $ 3.44  
 
Note 8 – Derivative Financial Instruments
 
New authoritative accounting guidance under FASB ASC Topic 815
 
Effective January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires entities to provide greater transparency about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows.
 
Oil and Natural Gas Commodity Hedges
 
To mitigate a portion of the potential exposure to adverse market changes in oil and gas prices and the associated impact on cash flows, the Company has entered into various derivative contracts.  The Company’s derivative contracts in place include swap and collar arrangements for oil, natural gas, and natural gas liquids (“NGL”).  As of September 30, 2009, the Company has hedge contracts in place through the third quarter of 2012 for a total of approximately 7 million Bbls of anticipated crude oil production, 45 million MMBtu of anticipated natural gas production, and 230,000 Bbls of anticipated natural gas liquids production.  As of October 27, 2009, the Company has hedge contracts in place through the third quarter of 2012 for a total of approximately 7 million Bbls of anticipated crude oil production, 57 million MMBtu of anticipated natural gas production, and 946,000 Bbls of anticipated natural gas liquids production.
 
The Company attempts to qualify its oil and gas derivative instruments as cash flow hedges for accounting purposes under ASC Topic 815.  The Company formally documents all relationships between the derivative instruments and the hedged production, as well as the Company’s risk management objective and strategy for the particular derivative contracts.  This process includes linking all derivatives that are designated as cash flow hedges to the specific forecasted sale of oil or gas at its physical location.  The Company also formally assesses (both at the derivative’s inception and on an ongoing basis) whether the derivatives being utilized have been highly effective in offsetting changes in the cash flows of hedged production and whether those derivatives may be expected to remain highly effective in future periods.  If it is determined that a derivative has ceased to be highly effective as a hedge, the Company will discontinue hedge accounting for that derivative prospectively.  If hedge accounting is discontinued and the derivative remains outstanding, the Company will recognize all subsequent changes in its fair value in the Company’s consolidated statements of operations for the period in which the change occurs.  As of September 30, 2009, all oil and natural gas derivative instruments qualified as cash flow hedges for accounting purposes.  The
 
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Company anticipates that all forecasted transactions will occur by the end of their originally specified periods.  All contracts are entered into for other than trading purposes.
 
The Company’s oil and gas hedges are measured at fair value and are included in the accompanying consolidated balance sheets as accrued derivative assets and liabilities.  The Company derives internal valuation estimates taking into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money.  Those internal valuations are then compared to the counterparties’ mark-to-market statements.  The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing derivative instruments.  The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid.  The oil and gas derivative markets are highly active.  The fair value of oil and natural gas derivative contracts designated and qualifying as cash flow hedges under ASC Topic 815 was a net liability of $25.6 million and a net asset of $105.3 million at September 30, 2009, and December 31, 2008, respectively.
 
The following table details the fair value of derivatives recorded in the consolidated balance sheets, by category:
 
 
Location on Consolidated Balance Sheets
 
Fair Value at
September 30, 2009
 
Fair Value at
December 31, 2008
 
Derivative assets designated as cash flow hedges:
   
(In thousands)
 
Oil, natural gas, and NGL commodity
Current assets
  $ 41,428   $ 111,649  
Oil, natural gas, and NGL commodity
Other noncurrent assets
    4,614     21,541  
Total derivative assets designated as cash flow hedges under ASC Topic 815
    $ 46,042   $ 133,190  
                 
Derivative liabilities designated as cash flow hedges:
               
Oil, natural gas, and NGL commodity
Current liabilities
  $ (25,370 ) $ (501 )
Oil, natural gas, and NGL commodity
Noncurrent liabilities
    (46,315 )   (27,419 )
Total derivative liabilities designated as cash flow hedges under ASC Topic 815
    $ (71,685 ) $ (27,920 )
 
Realized gains or losses from the settlement of oil and gas derivative contracts are reported in the operating revenues and other income section of the accompanying consolidated statements of operations.  The Company realized a net gain of $28.3 million and a net loss of $53.5 million from its oil and natural gas derivative contracts for the three months ended September 30, 2009, and 2008, respectively, and realized a net gain of $127.2 million and a net loss of $145.8 million from its oil and natural gas derivative contracts for the nine months ended September 30, 2009, and 2008, respectively.
 
After-tax changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributed to the hedged risk, are recorded in accumulated other comprehensive income in the accompanying consolidated balance sheets until the hedged item is realized in earnings upon the sale of the associated hedged production.  As of September 30, 2009, the amount of unrealized gain net of deferred income taxes to be reclassified from accumulated other comprehensive income to realized oil and gas hedge gain (loss) in the Company’s accompanying consolidated statements of operations in the next twelve months is $15.7 million.
 
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The Company seeks to minimize ineffectiveness by entering into oil derivative contracts indexed to the New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) index and natural gas derivative contracts indexed to regional index prices associated with pipelines in proximity to the Company’s areas of production.  As the Company’s derivative contracts contain the same index as the Company’s sales contracts, this results in derivative contracts that are highly correlated with the underlying hedged item.
 
The following table details the effect of derivative instruments on other comprehensive income (loss) and the consolidated balance sheets (net of tax):
 
 
Derivatives Qualifying as Cash Flow Hedges
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
     
2009
 
2008
 
2009
 
2008
 
     
(In thousands)
 
Amount of (Gain) Loss on Derivatives Recognized in OCI During the Period (Effective Portion)
Commodity hedges
  $ 958   $ (400,419 $ 12,810   $ 51,474  
Amount of (Gain) Loss Reclassified from AOCI to Realized Oil and Gas Hedge Gain (Loss) (Effective Portion)
        Commodity hedges
  $ (12,485 ) $ (21,522 ) $ (57,979 ) $ 37,176  
 
Any change in fair value resulting from hedge ineffectiveness is recognized currently in unrealized derivative (gain) loss in the accompanying consolidated statements of operations. The following table details the effect of derivative instruments on the consolidated statements of operations:
 
Derivatives Qualifying as Cash Flow Hedges
 
Classification of (Gain) Loss Recognized in Earnings
 
(Gain) Loss Recognized in Earnings
(Ineffective Portion)
 
       
For the Three Months
Ended September 30,
   
For the Nine Months
Ended September 30,
 
       
2009
 
2008
   
2009
   
2008
 
       
(In thousands)
 
Commodity hedges
 
Unrealized derivative (gain) loss
  $ 4,117   $ (4,429 )   $ 17,251     $ 802  
 
Credit Related Contingent Features
 
As of September 30, 2009, only two of the Company’s hedge counterparties were not members of the Company’s credit facility bank syndicate.  Member banks are secured by the Company’s oil and gas assets, and so do not require the Company to post collateral in hedge liability instances.  When the Company is in a liability position with a non-member bank, posting of collateral may be required if the
 
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Company’s liability balance exceeds the limit set forth in the agreement with the non-member bank.  With one of the non-member banks, the Company is subject to financial ratio tests, which determine the liability balance above which the Company has to post cash collateral.  With the other non-member bank, the Company is required to post collateral if the liability balance exceeds $5.0 million.  The Company had $1.1 million of collateral posted with non-member banks as of September 30, 2009.  No collateral was posted as of October 27, 2009.
 
Subsequent to September 30, 2009, the Company novated all of the commodity hedges that it had with one of the non-member banks to a bank that is a member of the Company’s credit facility bank syndicate.  Per the terms of the novation agreement, the non-member bank returned all of the cash that the Company had posted as collateral.
 
Convertible Note Derivative Instruments
 
The contingent interest provision of the 3.50% Senior Convertible Notes is a derivative instrument.  As of September 30, 2009, and December 31, 2008, the value of this derivative was determined to be immaterial.
 
Note 9 – Pension Benefits
 
The Company has a non-contributory pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”).  The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan”).
 
Components of Net Periodic Benefit Cost for Both Plans
 
The following table presents the total components of the net periodic cost for both the Qualified Pension Plan and the Nonqualified Pension Plan:
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(In thousands)
 
Service cost
$ 625   $ 460   $ 1,875   $ 1,379  
Interest cost
  234     222     701     665  
Expected return on plan assets
  (108 )   (168 )   (323 )   (503 )
Amortization of net actuarial loss
  93     40     279     121  
Net periodic benefit cost
$ 844   $ 554   $ 2,532   $ 1,662  
 
Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants.  Gains and losses in excess of ten percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.
 
Contributions
 
Under the Pension Protection Act of 2006 St. Mary is required to contribute at least $380,000 to the Pension Plans in 2009.  However, the Company contributed $1.9 million in September 2009 based upon the preliminary funding results analysis completed in April 2009 to maintain an adequate funding level to provide retirement benefits to current and future plan participants and maintain an adequate funding level to provide lump sum payments if elected by a participant.
 
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Note 10 – Asset Retirement Obligations
 
The Company recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and gas properties.  A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired.  The increase in carrying value is included in proved oil and gas properties in the accompanying consolidated balance sheets.  The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties.  Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying consolidated statements of cash flows.
 
The Company’s estimated asset retirement obligation liability is based on estimated economic lives, historical experience in plugging and abandoning wells, estimated cost to plug and abandon the wells in the future, and federal and state regulatory requirements.  The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.  The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 6.5 percent to 12.0 percent.  Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.
 
A reconciliation of the Company’s asset retirement obligation liability is as follows:
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(In thousands)
 
                 
Beginning asset retirement obligation
$ 123,251   $ 106,486   $ 116,274   $ 108,284  
Liabilities incurred
  167     1,073     707     7,162  
Liabilities settled
  (974 )   (4,039 )   (6,150 )   (16,509 )
Accretion expense
  2,460     1,954     6,970     5,337  
Revision to estimated cash flow
  2,617     6,373     9,720     7,573  
Ending asset retirement obligation
$ 127,521   $ 111,847   $ 127,521   $ 111,847  
 
As of September 30, 2009, the Company had $23.7 million of asset retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the Company’s accompanying consolidated balance sheets.  Additionally, as of September 30, 2009, accounts payable and accrued expenses contained $35.1 million related to the Company’s current asset retirement obligation liability associated with the estimated retirement of some of the Company’s offshore platforms.
 
 
The Company recorded a loss related to hurricanes, included in the other expense line item within the accompanying consolidated statements of operations, of $1.2 million and $7.0 million for the three-month periods ended September 30, 2009, and 2008, respectively, and $8.3 million and $7.0 million for the nine-month periods ended September 30, 2009, and 2008, respectively.  The loss primarily relates to the Vermilion 281 platform that was lost in Hurricane Ike.
 
Note 11 – Fair Value Measurements
 
On January 1, 2008, the Company partially applied new authoritative accounting guidance under FASB ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”) for all financial assets and liabilities measured at fair value on a recurring basis.  The topic establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements.  ASC Topic 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.  The topic establishes
 
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market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs.  The topic establishes a hierarchy for grouping these assets and liabilities, based on the significance level of the following inputs:
 
·      
Level 1 – Quoted prices in active markets for identical assets or liabilities
 
 
·      
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
 
 
·      
Level 3 – Significant inputs to the valuation model are unobservable
 
On January 1, 2009, the Company applied ASC Topic 820 for all nonfinancial assets and liabilities measured at fair value on a nonrecurring basis, including long-lived assets and assets held for sale measured at fair value under FASB ASC Topic 360, “Property, Plant, and Equipment” (“ASC Topic 360”) and asset retirement obligations initially measured at fair value under FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“ASC Topic 410”).  The adoption of ASC Topic 820 for nonfinancial assets and liabilities did not have a material impact on the Company’s financial statements.
 
There were no nonfinancial assets or liabilities measured at fair value as of September 30, 2009.  The following is a listing of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of September 30, 2009:
 
 
Level 1
 
Level 2
 
Level 3
 
 
(In thousands)
 
Assets:
           
Accrued derivative
$ -   $ 46,042   $ -  
Liabilities:
                 
Accrued derivative
$ -   $ 71,685   $ -  
Net Profits Plan
$ -   $ -   $ 163,328  
 
The following is a listing of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2008:
 
 
Level 1
 
Level 2
 
Level 3
 
 
(In thousands)
 
Assets:
           
Accrued derivative
$ -   $ 133,190   $ -  
Liabilities:
                 
Accrued derivative
$ -   $ 27,920   $ -  
Net Profits Plan
$ -   $ -   $ 177,366  
 
Both financial and nonfinancial assets and liabilities are categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement.  The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the hierarchy.
 
Derivatives
 
The Company uses Level 2 inputs to measure the fair value of oil and gas hedges.  Fair values are based upon interpolated data.  The Company calculates internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money.  
 
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These valuations are then compared to the respective counterparties’ mark-to-market statements.  The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments.
 
Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality.  However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument.  The Company monitors the credit ratings of its counterparties and may ask counterparties to post collateral if their ratings deteriorate.  In some instances the Company will attempt to novate the trade to a more stable counterparty.
 
Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any liability position with a counterparty.  This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties.  The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.  The majority of the Company’s derivative counterparties are members of St. Mary’s credit facility bank syndicate.
 
The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows.  While the Company believes that the valuation methods utilized are appropriate and consistent with the requirements of ASC Topic 820 and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.
 
Net Profits Plan
 
The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants.  The inputs available for this instrument are unobservable, and therefore classified as Level 3 inputs.  The Company employs the income approach, which converts expected future cash flow amounts to a single present value amount.  This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value.  There is a direct correlation between realized oil and gas commodity prices driving net cash flows and the Net Profits Plan liability.  If commodity prices fall, the liability is reduced or eliminated.
 
The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool.  The calculation of this liability is a significant management estimate.  For a predominate number of the pools, a discount rate of 12 percent is used to calculate this liability.  This rate is intended to represent the best estimate of the present value of expected future payments under the Net Profits Plan.
 
The Company’s estimate of its liability is highly dependent on commodity price and cost assumptions and the discount rates used in the calculations.  The commodity price assumptions are formulated by applying the price that is derived from a rolling average of actual prices realized during the prior 24 months together with adjusted NYMEX strip prices for the ensuing 12 months.  This average price is adjusted to include the effect of hedge prices for the percentage of forecasted production hedged in the relevant periods.  The forecasted non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the crude oil and natural gas commodity markets.  The Company continually evaluates the assumptions used in this calculation in order to consider the current market environment for oil and gas prices, costs, discount rate, and overall market conditions.
 
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If the commodity prices used in the calculation changed by five percent, the liability recorded at September 30, 2009, would differ by approximately $13 million.  A one percentage point decrease in the discount rate would result in an increase to the liability of approximately $8 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of approximately $7 million.  Actual cash payments to be made to participants in future periods are dependent on actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan.  Consequently, actual cash payments are inherently different from the amounts estimated.
 
No published market quotes exist on which to base the Company’s estimate of fair value of the Net Profits Plan liability.  As such, the recorded fair value is based entirely on management estimates as described within this footnote.  While some inputs to the Company’s calculation of fair value on Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates.  The following table reflects the activity for the liabilities measured at fair value using Level 3 inputs for the three-month and nine-month periods ended September 30, 2009, and 2008, respectively.
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(In thousands)
 
                 
Beginning balance
$ 156,524   $ 293,174   $ 177,366   $ 211,406  
Net increase (decrease) in liability (a)
  12,211     (24,451 )   20     92,832  
Net settlements (a)(b)
  (5,407 )   (10,416 )   (14,058 )   (45,931 )
Transfers in (out) of Level 3
  -     -     -     -  
Ending balance
$ 163,328   $ 258,307   $ 163,328   $ 258,307  
(a)    Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying consolidated statements of operations.
(b)    Settlements represent cash payments made or accrued under the Net Profits Plan.
 
3.50% Senior Convertible Notes Due 2027
 
Based on the market price of the 3.50% Senior Convertible Notes, the estimated fair value of the notes was approximately $284.6 million and $204.0 million as of September 30, 2009, and December 31, 2008, respectively.
 
Proved Oil and Gas Properties
 
Proved oil and gas property costs are evaluated for impairment and reduced to fair value if the sum of the expected undiscounted future cash flows is less than net book value pursuant to ASC Topic 360.  The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management.  The discount rate is a rate that management believes is representative of current market conditions and includes the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk.  The price forecast is based on NYMEX strip pricing, adjusted for basis differentials, for the first five years.  Future operating costs are also adjusted as deemed appropriate for these estimates.
 
There were no long-lived assets measured at fair value within the accompanying consolidated balance sheets at September 30, 2009.  The provisions under ASC Topic 820 were applied to nonfinancial assets and liabilities, as previously discussed above, on January 1, 2009.
 
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Asset Retirement Obligations
 
The Company estimates asset retirement obligations pursuant to the provisions of ASC Topic 410.  The income valuation technique is utilized by the Company to determine the fair value of the liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows.  Given the unobservable nature of the inputs the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.  There were no asset retirement obligations measured at fair value within the accompanying consolidated balance sheets at September 30, 2009.  The provisions under ASC Topic 820 were applied to nonfinancial assets and liabilities, as previously discussed above, on January 1, 2009.
 
Refer to Note 8 – Derivative Financial Instruments and Note 10 – Asset Retirement Obligations for more information regarding the Company’s hedging instruments and asset retirement obligations.
 
Note 12 – Impairment of Proved and Unproved Properties
 
The Company recorded $153.2 million of proved property impairments during the first nine months of 2009.  The Company recorded $147.0 million of proved property impairments during the first quarter of 2009.  A significant decrease in the market price for natural gas, including differentials in effect at March 31, 2009, caused the majority of this non-cash impairment of proved properties in the first quarter.  The largest portion of the impairment was $97.3 million related to assets located in the Mid-Continent region which were impacted by wider than normal differentials for that period.  During the second quarter of 2009, the Company incurred an additional impairment on proved properties of $6.0 million related to the write-down of certain assets located in the Gulf of Mexico in which the Company is relinquishing its ownership interests.  The Company recorded $564,000 and $10.1 million of proved property impairments, respectively, for the three-month and nine-month periods ended September 30, 2008, the latter of which included $9.6 million related to the write-down of assets located in the Apple Springs Field in Louisiana.
 
The Company recorded $4.8 million and $20.3 million of abandonment and impairment of unproved properties during the three-month and nine-month periods ended September 30, 2009, respectively. The largest portion of this impairment related to the Floyd Shale acreage located in Mississippi.  The Company recorded $1.2 million and $4.3 million of abandonment and impairment of unproved properties for the three-month and nine-month periods ended September 30, 2008, respectively.
 
Note 13 – Assets Held for Sale
 
In accordance with ASC Topic 360, assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year.  Upon classification as held-for-sale, long-lived assets are no longer depreciated or depleted and a measurement for impairment is performed to expense any excess of carrying value over fair value less costs to sell.  Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale if the fair value is determined to be less than the carrying value of the assets.
 
As of September 30, 2009, the accompanying consolidated balance sheets present $148.9 million in book value of assets held for sale, net of accumulated depletion, depreciation, and amortization.  The corresponding asset retirement obligation liability of $23.7 million is also separately presented.  The Company determined that these sales do not qualify for discontinued operations accounting.  The above assets held for sale and asset retirement obligation liability amounts include a new package of certain non-core properties located primarily in the Rocky Mountain region that the Company began marketing in the third quarter of 2009.
 
In the third quarter of 2009, St. Mary reclassified a portion of the assets previously classified as held for sale to assets held and used, as these assets were no longer being actively marketed.  In accordance with 
 
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ASC Topic 360, the Company must measure the assets at the lower of the assets carrying amount before the assets were classified as held for sale, adjusted for any depreciation and depletion expense that would have been recognized had the assets been continuously classified as held and used, or the assets fair value at the subsequent date that the decision not to actively market the assets was determined.  As a result of this measurement the Company recognized a $9.8 million loss on unsuccessful sale of properties, which is included within the gain (loss) on divestiture activity line item within the accompanying consolidated statements of operations.
 
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
This discussion and analysis contains forward-looking statements.  Refer to “Cautionary Information about Forward-Looking Statements” at the end of this item for an explanation of these types of statements.  The prior year balances within the accompanying financial statements and notes have been adjusted to reflect the accounting required under ASC Topic 470.  Please refer to Note 7 – Long-term Debt within Part I, Item 1 of this report for additional discussion.
 
Overview of the Company, Highlights, and Outlook
 
General Overview
 
We are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil in North America.  We generate nearly all our revenues and cash flows from the sale of produced natural gas and crude oil.  Our oil and gas reserves and operations are concentrated primarily in various Rocky Mountain basins, including the Williston, Big Horn, Wind River, Powder River, and Greater Green River basins; the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; the productive formations of East Texas and North Louisiana; the Maverick Basin in South Texas; and the onshore Gulf Coast.  We have developed a balanced and diverse portfolio of proved reserves, development drilling opportunities, and potential resource plays.
 
Our mission is to deliver outstanding net asset value per share growth to our investors via attractive oil and gas investments.  Historically, we relied on a strategy of growing through niche acquisitions focused in the continental United States.  Over the last few years, we have shifted our strategy to focus on capturing potential resource plays earlier and at a lower cost of entry.  This shift was due to the fact that, as we grew, the universe of potential niche acquisition targets became smaller, more expensive, and less impactful to our growth.  We believe this shift will allow for more stable and predictable production and proved reserve growth.  Going forward, we will focus on continuing to acquire significant leasehold positions in existing and emerging resource plays in North America.  Our strategy can be summarized as follows:
 
·      
Acquire significant leasehold positions in new and emerging North American resource plays
 
·      
Leverage our core competencies in drilling, completing, and acquiring oil and gas assets
 
·      
Exploit our significant legacy asset production and optimize our asset base through divestitures of non-core assets when appropriate
 
·      
Maintain a strong balance sheet while funding the growth of the enterprise.
 
Financial Standing and Liquidity
 
During and subsequent to the third quarter of 2008, specific issues related to the financial sector rippled through the broader economy.  The failure or takeovers of several large financial institutions adversely impacted the wider equity, debt, and credit markets.  Financial strength and liquidity became increasingly important as investors considered the ability of companies to fund their planned levels of activity and to service their debt obligations.  In addition, fears of prolonged weakness in the global economy leading to anemic energy demand resulted in a significant decline in oil and natural gas prices.  As a result of these events, we entered 2009 with a business plan designed to operate within our operating cash flow.  We have maintained a disciplined approach with our capital investments during the year, which, combined with higher operating cash flows than we anticipated originally, have allowed us to maintain our strong financial position and pay down borrowings under our credit facility.  We expect our 2009 exploration and development program budget will be at or near our 2009 operating cash flows.  Accordingly, we do not anticipate accessing the equity or public debt markets for the remainder of 2009.  
 
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We continue to believe we have adequate liquidity available to us through our credit facility as discussed below under the caption Overview of Liquidity and Capital Resources.
 
Oil and Gas Prices
 
Our financial condition and the results of our operations are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically.  We sell a majority of our natural gas under contracts that use first of the month index pricing, which means that gas produced in a given month is sold at the first of the month price regardless of the spot price on the day the gas is produced.  Our crude oil is sold using contracts that pay us either the average of the NYMEX West Texas Intermediate daily settlement or the average of alternative posted prices for the periods in which the crude oil is produced, adjusted for quality, transportation, and location differentials.  The following table is a summary of commodity price data for the third quarters of 2009 and 2008 and the second quarter of 2009:
 
 
For the Three Months Ended
 
 
September 30, 2009
 
June 30, 2009
 
September 30, 2008
 
Crude Oil (per Bbl):
           
Average NYMEX price
$ 68.30   $ 59.62   $ 117.98  
Realized price, before the effects of hedging
$ 61.93   $ 53.96   $ 111.97  
Net realized price, including the effects of hedging
$ 62.65   $ 56.72   $ 83.30  
                   
Natural Gas (per Mcf):
                 
Average NYMEX price
$ 3.41   $ 3.72   $ 10.09  
Realized price, before the effects of hedging
$ 3.37   $ 3.07   $ 9.96  
Net realized price, including the effects of hedging
$ 4.95   $ 5.19   $ 9.51  
 
Average quarterly NYMEX crude oil prices increased 15 percent from the second quarter of 2009 to the third quarter of 2009 from $59.62 per barrel to $68.30 per barrel.  The 36-month forward strip price for crude oil was $76.20 per barrel at the end of the third quarter of 2009 compared with $76.46 per barrel at the end of the second quarter of 2009.  On October 27, 2009, the 36-month forward strip price had increased from the end of the third quarter 2009 by 12 percent to $85.08 per barrel.  At the same time, the near month price was $79.55 per barrel, which was 13 percent higher than the September 30, 2009, near month price of $70.61 per barrel.
 
Average quarterly NYMEX natural gas prices decreased eight percent from the second quarter of 2009 to the third quarter of 2009 from $3.72 per Mcf to $3.41 per Mcf.  Natural gas prices have been under downward pressure due to concerns regarding high levels of natural gas in storage and concerns of a perpetual amount of excess supply in the market, as well as declining U.S. demand for natural gas.  The 36-month forward strip price for natural gas increased four percent to $6.58 per MMBtu at the end of the third quarter of 2009 compared with $6.33 per MMBtu at the end of the second quarter of 2009, largely due to improving sentiment regarding the economic outlook in the U.S. economy.  As of October 27, 2009, the 36-month forward strip price had decreased three percent to $6.40 per MMBtu.  At the same time, the near month price had decreased from the September 30, 2009, near month price of $4.84 per MMBtu by an additional six percent to $4.56 per MMBtu.
 
While changes in quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the price we receive for oil and natural gas is affected by quality, energy content, location, and transportation differentials for these products.  We refer to this price as our realized price, which excludes the effects of hedging.  Our realized price is further impacted by the results of our hedging arrangements that are settled in the respective periods.  We refer to this price as our net realized
 
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price.  Our net natural gas and oil price realizations for the three months ended September 30, 2009, were positively impacted by $27.2 million and $1.1 million of realized hedge gains, respectively.  Net natural gas and oil price realizations for the nine months ended September 30, 2009, were positively impacted by $105.6 million and $21.6 million of realized hedge gains, respectively.
 
Hedging Activities
 
Hedging is an important part of our financial risk management program.  The amount of production we hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital commitments and long-term obligations we have in place.  In the case of a significant acquisition of producing properties, we will consider hedging a portion of the acquired production in order to protect the economics assumed in the acquisition.  With the hedges we have in place, we believe we have established a base cash flow stream for our future operations, and our use of collars for a portion of the hedges allows us to participate in upward movements in oil and gas prices.  Please see Note 8 – Derivative Financial Instruments of Part I, Item 1 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section.
 
We attempt to qualify our oil and gas derivative instruments as cash flow hedges for accounting purposes under ASC Topic 815.  Changes in the value of our hedge positions are primarily reflected in our consolidated balance sheets.  A portion of the change in the value of our hedge positions is recognized in our consolidated statements of operations due to the hedges being partially ineffective.  We recognized $4.1 million in non-cash derivative loss in the third quarter of 2009.  This was primarily caused by increases in the price of oil causing what had previously been hedge assets to become hedge liabilities, which in turn resulted in ineffectiveness losses from these hedge liabilities.
 
The U.S. Congress is currently considering recent proposals to increase the regulatory oversight of the over-the-counter derivatives markets in order to promote more transparency in those markets.  Although we cannot predict the ultimate outcome of these proposals, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to swings in oil and gas commodity prices.
 
Third Quarter 2009 Highlights
 
Developments in emerging resource plays.  During 2008, the Haynesville shale, the Eagle Ford shale, and the Marcellus shale resource plays emerged as significant new sources of gas supply for the exploration and production industry.  We have exposure to each of these plays that, if successful, could provide for significant future organic growth in reserves and production.  The Haynesville shale emerged early in 2008 in northern Louisiana and eastern Texas and quickly became the most active resource play in the country.  Our position was built as a result of earlier leasing activity targeting the James Lime and Cotton Valley formations.  Our Eagle Ford shale position in the Maverick Basin in South Texas was built from 2007 through 2009 through a combination of property acquisitions, leasing activity, and participation in a joint venture with industry partners.  Late in 2008 we entered into arrangements that allow us to earn or purchase acreage in the Marcellus shale in north central Pennsylvania.
 
During the third quarter of 2009, we announced we would be increasing the number of wells planned for the Eagle Ford shale from four wells to ten wells on our operated high working interest acreage.  Results from the completed wells to date have been positive.  As of the date of this filing, we have publicly reported production information related to our first four wells across our high working interest leasehold position and these initial production rates have been encouraging to us.  We are proceeding with our previously announced program and will be adding a second operated rig to drill on this high working interest acreage in the fourth quarter of 2009.  Our expectation is that we will operate two rigs in this part of the play for the foreseeable future.  Also during the third quarter, we drilled and completed three wells on joint venture acreage where we have two industry partners.  There is a shortage of sales infrastructure in this area which we believe has limited the ability to fully evaluate these wells at this time.  We continue to
 
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work with our partners in the play and are committed to participating in the joint venture going forward.  Between the joint venture and our other acreage holding, we currently have a total of approximately 225,000 net acres with potential for the Eagle Ford shale in Dimmitt, LaSalle, Maverick, and Webb counties in Texas.  We continue to evaluate ways to increase our leasehold position across the play.
 
During the quarter, we completed our second well targeting the Haynesville shale in northern San Augustine County, Texas.  The well was cored and logged, then completed vertically.  We view the production rate and core data from this well positively since we think it could have favorable implications to the horizontal development in this part of the Haynesville shale trend.  In addition, offsetting industry activity in this part of East Texas appears encouraging.  We are drilling our second well in the area, in southern Shelby County, Texas, and we plan to complete this well vertically.  We have an ongoing program to shoot, acquire, and interpret 3D seismic data over a large part of our East Texas acreage, which we expect will be completed in the first quarter of 2010.  We think seismic data will be important to the successful horizontal development of this play.  We continue to participate with partners in non-operated wells in northern Louisiana.  We have a total of 50,000 net acres with Haynesville potential in East Texas and Louisiana.
 
In the Marcellus shale program in Pennsylvania, we drilled and completed our first horizontal well in McKean County, Pennsylvania during the third quarter.  At quarter end, we were in the process of drilling and completing our second horizontal well, which is also in McKean County.  We are moving ahead with the construction of a sales line for this portion of our acreage.  We currently have over 40,000 net acres in north central Pennsylvania with potential for the Marcellus shale.
 
Shift toward oil-weighted projects.  As a result of continued downward pressure on natural gas prices and an increase in oil prices, we began shifting capital investment dollars toward oil-weighted projects during the third quarter.  We saw an increase in activity in our Permian and Rocky Mountain regions as a result of this shift in capital.
 
Borrowing base on credit facility maintained.  On September 29, 2009, the borrowing base on our credit facility was redetermined and maintained by our bank group at a value of $900 million.
 
Marketing of non-core properties.  In the third quarter of 2009, we began marketing a new package of certain non-core properties located primarily in the Rocky Mountain region.  Please refer to Note 13 – Assets Held for Sale, in Part I, Item 1 of this report for additional information.
 
Production results.  The table below details the regional breakdown of our third quarter 2009 production:
 
 
Mid-
Continent
 
ArkLaTex
 
Gulf Coast
 
Permian
 
Rocky
Mountain
 
Total (1)
 
Third Quarter 2009 Production:
                       
Oil (MBbl)
65.4   29.4   90.5   414.3   928.1   1,527.7  
Gas (MMcf)
8,483.2   3,420.5   1,495.6   1,023.8   2,787.9   17,211.0  
Equivalent (MMCFE)
8,875.7   3,596.8   2,038.4   3,509.7   8,356.8   26,377.4  
Avg. Daily Equivalents (MMCFE/d)
96.5   39.1   22.2   38.1   90.8   286.7  
Relative percentage
34%   13%   8%   13%   32%   100%  
(1)    Totals may not add due to rounding
 
For the third quarter of 2009 our oil and gas production was in-line with our expectations and higher than our original budget estimates from the beginning of the year.  Production has declined over the last three quarters as a result of lower levels of capital investment.  Our ability to fund the
 
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capital investments necessary to grow our production is influenced significantly by the price we receive for produced oil and natural gas.  Market prices for natural gas and oil during the first several months of the year limited the amount of capital available to invest.  We also deferred some of our capital investments due to our view that drilling and completion costs would decrease throughout the year as a result of lower levels of industry activity.  Our expectation is that the deferral will provide a better economic return.
 
Equity Compensation.  On August 1, 2009, we granted awards of performance shares and restricted stock units pursuant to our long term incentive program to various employees of the Company eligible to participate in the LTIP.  The fair value associated with this grant was $31.6 million.  Please refer to Note 5 – Compensation Plans within Part I, Item 1 of this report for additional discussion.
 
First Nine Months 2009 Highlights
 
Impairments.  We recognized significant non-cash impairments during the first nine months of 2009.  We recorded $147.0 million of proved property impairments during the first quarter of 2009, and our total impairment of proved properties for the nine months ended September 30, 2009, totaled $153.2 million.  A significant decrease in the market price for natural gas, including differentials in effect at March 31, 2009, caused the majority of the non-cash impairment of proved properties in that period.  The largest portion of the impairment was $97.3 million related to assets located in the Mid-Continent region which were significantly impacted by wider than normal differentials at that time.  During the second quarter of 2009, we incurred a $6.0 million impairment on proved properties related to the write-down of certain assets located in the Gulf of Mexico in which we are relinquishing our ownership interests.
 
During the first nine months of 2009, we recognized a charge of $20.3 million for the abandonment and impairment of unproved properties.  The largest component of the abandonment and impairment of unproved properties was associated with our Floyd shale leasehold in Mississippi that was recognized during the second quarter of 2009.
 
Lastly, we incurred inventory write-downs of $13.4 million for the nine-month period ended September 30, 2009, as a result of the decrease in the market value of tubular goods and other inventory items that were purchased in 2008 when prices for these goods were considerably higher.
 
Net Profits Plan.  For the nine months ended September 30, 2009, the change in the value of this liability resulted in a non-cash benefit of $14.0 million compared to non-cash expense of $46.9 million for the same period in 2008.  Significant decreases in oil and gas commodity prices have decreased the estimated liability for the future amounts to be paid to plan participants.  This liability is a significant management estimate.  Adjustments to the liability are subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, tax rates, and production costs.
 
Payments made or accrued for current year distributions under the Net Profits Plan totaled $14.1 million and $45.9 million for the nine months ended September 30, 2009, and 2008, respectively.  The actual cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool.  Actual cash payments will be inherently different from the estimated liability amounts.  More detailed discussion is included in the Comparison of Financial Results and Trends sections below and in Note 11 – Fair Value Measurements and Note 5 – Compensation Plans in Part I, Item 1.  An increasing percentage of the costs associated with the payments from the Net Profits Plan are now being categorized as general and administrative expense as compared to exploration expense.  This is a function of the normal departure of employees who previously contributed to our exploration efforts.  In December 2007, our Board approved an incentive compensation plan restructuring, whereby the Net Profits Plan was replaced with a long-term incentive program utilizing equity awards.  As a result, the 2007 Net Profits Plan pool was the last pool established.
 
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The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions.  For example, if we changed the commodity prices in our calculation by five percent, the liability recorded on the balance sheet at September 30, 2009, would differ by approximately $13 million.  A one percentage point decrease in the discount rate would result in an increase to the liability of approximately $8 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of approximately $7 million.  We frequently re-evaluate the assumptions used in our calculations and consider the possible impacts stemming from the current market environment including current and future oil and gas prices, discount rates, and overall market conditions.
 
Production results.  The table below details the regional breakdown of our first nine months of 2009 production:
 
 
Mid-
Continent
 
ArkLaTex
 
Gulf Coast
 
Permian
 
Rocky
Mountain
 
Total (1)
 
First nine months of 2009 Production:
                       
Oil (MBbl)
213.3   103.0   288.2   1,419.4   2,792.0   4,815.8  
Gas (MMcf)
26,247.5   11,231.0   5,156.4   3,093.7   8,326.9   54,055.5  
Equivalent (MMCFE)
27,527.5   11,848.7   6,885.4   11,610.3   25,078.7   82,950.6  
Avg. Daily Equivalents (MMCFE/d)
100.8   43.4   25.2   42.5   91.9   303.8  
Relative percentage
34%   14%   8%   14%   30%   100 %
(1)   Totals may not add due to rounding
 
For the first nine months of 2009 our production and oil and gas production revenues have outperformed our initial budget for 2009 due to stronger than anticipated production results from our Mid-Continent and Permian regions.
 
Outlook for the Remainder of 2009 and 2010
 
Unlike prior years, we entered 2009 without a specific capital budget for exploration and development activities.  Our plan for 2009 was to make capital investments for exploration and development activities at a level at or near our operating cash flows.  We established a flexible capital program that could be quickly adjusted rather than setting a fixed budget for the year.  We have maintained our discipline and have kept our investing activities within operating cash flow throughout the year.
 
With respect to oil-weighted and liquids-weighted projects, we believe we are at the appropriate point in the commodity price cycle where increased levels of capital investment should be made.  In recent months we have been increasing our activity in the oilier parts of our portfolio, specifically the Permian and Rocky Mountain regions.  We currently anticipate that we will maintain or increase this level of oil-weighted activity through 2010.  Generally, we do not believe that current natural gas prices support capital investment development projects at this time.  We plan to continue to drill wells in certain exploratory projects that have the potential to add significant amounts of proved reserves and resource to our inventory.  An example of this is our drilling in what appears to be the natural gas window in the Eagle Ford shale play.  We also plan to drill some natural gas wells in order to preserve certain strategic acreage positions that would otherwise expire.
 
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Financial Results of Operations and Additional Comparative Data
 
We recorded a net loss of $4.4 million or $0.07 per diluted share for the three months ended September 30, 2009, compared to third quarter 2008 results of net income of $87.0 million or $1.38 per diluted share.
 
The table below provides information regarding selected production and financial information for the quarter ended September 30, 2009, and the immediately preceding three quarters.  Additional details of per MCFE costs are contained later in this section.
 
 
For the Three Months Ended
 
 
September 30,
 
June 30,
 
March 31,
 
December 31,
 
 
2009
 
2009
 
2009
 
2008
 
 
(In millions, except production sales data)
 
Production (BCFE)
  26.4     28.2     28.4     30.0  
Oil and gas production revenue, excluding the effects of hedging
$ 152.7   $ 145.3   $ 130.4   $ 190.5  
Realized oil and gas hedge gain
$ 28.3   $ 43.3   $ 55.6   $ 44.8  
Gain (loss) on divestiture activity
$ (11.3 ) $ 1.3   $ (0.6 ) $ 9.5  
Lease operating expense
$ 34.3   $ 35.6   $ 41.2   $ 47.7  
Transportation costs
$ 5.3   $ 4.6   $ 5.5   $ 6.1  
Production taxes
$ 9.0   $ 9.3   $ 9.1   $ 11.8  
DD&A
$ 67.0   $ 70.4   $ 91.7   $ 95.1  
Exploration
$ 15.7   $ 19.5   $ 13.6   $ 17.7  
Impairment of proved properties
$ 0.1   $ 6.0   $ 147.0   $ 292.1  
Abandonment and impairment of unproved properties
$ 4.8   $ 11.6   $ 3.9   $ 34.7  
Impairment of materials inventory
$ 2.1   $ 2.7   $ 8.6   $ -  
Impairment of goodwill
$ -   $ -   $ -   $ 9.5  
General and administrative
$ 20.8   $ 18.2   $ 16.4   $ 12.4  
Bad debt expense
$ -   $ -   $ -   $ -  
Change in Net Profits Plan liability
$ 6.8   $ 2.4   $ (23.3 ) $ (80.9 )
Unrealized derivative (gain) loss
$ 4.1   $ 11.3   $ 1.8   $ (12.0 )
Net income (loss)
$ (4.4 ) $ (8.3 ) $ (87.6 ) $ (127.1 )
                         
Percentage change from previous quarter:
                       
Production (BCFE)
  (6)%     (1)%     (5)%     8%  
Oil and gas production revenue, excluding the effects of hedging
  5%     11%     (32)%     (47)%  
Realized oil and gas hedge gain
  (35)%     (22)%     24%     (184)%  
Gain (loss) on divestiture activity
  (969)%     317%     (106)%     290%  
Lease operating expense
  (4)%