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 June 30, 2005
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 80203
(Address of principal executive offices) (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 [ X ]
No [
]
Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act). Yes [X ] No [ ]
Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
As of July 22, 2005, the registrant had 56,446,999 shares of common stock, $0.01 par value, outstanding.
INDEX
Part I.
FINANCIAL INFORMATION
PAGE
Item 1.
Financial Statements (Unaudited)
Consolidated Balance Sheets
June 30, 2005 and December 31, 2004
3
Consolidated Statements of Operations
Three and Six Months Ended June 30, 2005 and 2004
4
Consolidated Statements of Stockholders’ Equity
and Comprehensive Income
5
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2005 and 2004
6
Notes to Consolidated Financial Statements
June 30, 2005
8
Item 2.
Management’s Discussion and Analysis
of Financial Condition and Results
of Operations
22
Item 3.
Quantitative and Qualitative Disclosures
About Market Risk (included within
the content of Item 2)
39
Item 4.
Controls and Procedures
Part II.
OTHER INFORMATION
Legal Proceedings
Unregistered Sales of Equity Securities
and Use of Proceeds
40
Submission of Matters to a Vote of
Security Holders
41
Item 6.
Exhibits
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
June 30,
December 31,
ASSETS
2005
2004
Current assets:
Cash and cash equivalents
$ 10,568
$ 6,418
Short-term investments
1,500
1,412
Accounts receivable
107,128
104,964
Prepaid expenses and other
8,244
5,863
Deferred income taxes
6,017
-
Accrued derivative asset
994
8,270
Other
3,748
Total current assets
138,199
126,927
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties
1,275,536
1,124,810
Less - accumulated depletion, depreciation and amortization
(441,623)
(399,013)
Unproved oil and gas properties, net of impairment allowance
of $9,115 in 2005 and $9,867 in 2004
41,562
41,969
Wells in progress
38,704
35,515
Other property and equipment, net of accumulated depreciation
of $7,187 in 2005 and $6,459 in 2004
5,339
5,244
919,518
808,525
Noncurrent assets:
Goodwill
9,612
Other noncurrent assets
9,722
10,008
Total noncurrent assets
19,334
Total Assets
$ 1,077,051
$ 945,460
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses
$ 119,058
$ 110,117
Accrued derivative liability
18,291
2,502
111
2,273
Total current liabilities
137,460
114,892
Noncurrent liabilities:
Long-term credit facility
51,000
37,000
Convertible notes
99,838
99,791
Asset retirement obligation
43,383
40,911
Net Profits Plan liability
46,957
30,561
161,333
129,830
Other noncurrent liabilities
17,660
8,020
Total noncurrent liabilities
421,171
346,113
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value: authorized - 200,000,000 shares;
issued: 58,019,099 shares in 2005 and 57,458,246 shares in 2004;
outstanding, net of treasury shares: 56,375,215 shares in 2005
and 56,958,246 shares in 2004
580
574
Additional paid-in capital
141,038
127,374
Treasury stock, at cost: 1,643,884 shares in 2005 and 500,000 in 2004
(33,336)
(5,295)
Deferred stock-based compensation
(7,511)
(5,039)
Retained earnings
435,068
364,567
Accumulated other comprehensive income (loss)
(17,419)
2,274
Total stockholders’ equity
518,420
484,455
Total Liabilities and Stockholders’ Equity
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per share amounts)
For the Three Months
For the Six Months
Ended June 30,
Operating revenues:
Oil and gas production revenue
$ 160,421
$ 106,581
$ 298,791
$ 207,787
Oil and gas hedge loss
(2,086)
(11,134)
(526)
(19,733)
Marketed gas revenue
5,551
3,724
8,947
7,297
Gain (loss) on sale of proved properties
(26)
1,581
1,776
Other revenue
714
1,399
1,206
1,506
Total operating revenues
164,574
102,151
308,392
198,633
Operating expenses:
Oil and gas production expense
30,188
21,573
62,347
45,116
Depletion, depreciation, amortization
and abandonment liability accretion
33,907
20,673
63,981
41,299
Exploration
9,699
6,569
16,782
11,200
Impairment of proved properties
494
Abandonment and impairment of unproved properties
1,819
966
3,689
1,888
General and administrative
7,481
5,410
13,467
10,987
Change in Net Profits Plan liability
12,175
4,325
16,396
6,485
Marketed gas operating expense
5,227
3,310
8,352
6,721
Derivative loss
241
1,721
1,370
869
Other expense
1,083
525
1,597
1,110
Total operating expenses
101,820
65,566
187,981
126,169
Income from operations
62,754
36,585
120,411
72,464
Nonoperating income (expense):
Interest income
98
242
180
386
Interest expense
(2,274)
(1,565)
(4,218)
(3,053)
Income before income taxes
60,578
35,262
116,373
69,797
Income tax expense
(22,317)
(13,426)
(43,009)
(26,512)
Net Income
$ 38,261
$ 21,836
$ 73,364
$ 43,285
Basic weighted-average common shares outstanding
56,960
57,167
57,095
58,401
Diluted weighted-average common shares outstanding
66,769
66,121
66,847
67,292
Basic net income per common share
$ 0.67
$ 0.38
$ 1.28
$ 0.74
Diluted net income per common share
$ 0.59
$ 0.34
$ 1.13
- 4 -
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)
Accumulated
Additional
Deferred
Total
Common Stock
Paid-in
Treasury Stock
Stock-Based
Retained
Comprehensive
Stockholders'
Shares
Amount
Capital
Compensation
Earnings
Income (Loss)
Equity
Balances, December 31, 2003
58,490,246
$ 584
$146,070
(2,005,400)
$(16,057)
$ -
$274,937
$ (14,881)
$ 390,653
Comprehensive income, net of tax:
Net income
92,479
Change in derivative instrument fair value
(14,795)
Reclassification to earnings
31,849
Minimum pension liability adjustment
101
Total comprehensive income
109,634
Cash dividends declared, $ 0.05 per share
(2,849)
Repurchase of common stock from Flying J
(19,406)
Treasury stock purchases
(978,600)
(16,336)
Retirement of treasury stock
(2,458,800)
(24)
(26,725)
2,458,800
26,749
Issuance of common stock under
Employee Stock Purchase Plan
27,748
375
Sale of common stock, including income
tax benefit of stock option exercises
1,399,052
14
17,832
17,846
Deferred compensation related to issued
restricted stock unit awards, net of
forfeitures
8,122
(8,122)
Accrued stock-based compensation
1,106
Amortization of deferred stock-based
compensation
3,083
Directors' stock compensation
25,200
349
Balances, December 31, 2004
57,458,246
$ 574
$127,374
(500,000)
$ (5,295)
$ (5,039)
$ 364,567
$ 2,274
$ 484,455
73,364
(20,024)
331
53,671
(2,863)
(1,157,810)
(28,347)
14,401
255
546,452
8,941
3,633
(3,633)
835
1,4672
1,467
Directors’ stock compensation
13,926
306
(306)
Balances, June 30, 2005
58,019,099
$ 580
$141,038
(1,643,884)
$(33,336)
$ (7,511)
$ 435,068
$ (17,419)
$ 518,420
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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
Reconciliation of net income to net cash provided
by operating activities:
Adjustments to reconcile net income to net
cash provided by operating activities:
(Gain) loss on sale of proved properties
26
(1,776)
Exploratory dry hole expense
2,102
1,236
Unrealized derivative loss
Deferred and accrued stock-based compensation
2,301
2,100
Income tax benefit from the exercise of stock options
2,747
2,435
13,090
(319)
(2,588)
Changes in current assets and liabilities:
702
(14,540)
(6,129)
1,639
3,773
3,903
Net cash provided by operating activities
185,576
99,819
Cash flows from investing activities:
Proceeds from sale of oil and gas properties
2,205
Capital expenditures
(134,800)
(81,734)
Acquisition of oil and gas properties, net of cash received
(35,145)
(4,913)
Deposits to short-term investments available-for-sale
(1,502)
(1,470)
Receipts from short-term investments available-for-sale
1,402
12,500
Receipts from restricted cash
10,412
(34)
710
Net cash used in investing activities
(169,978)
(62,290)
Cash flows from financing activities:
Proceeds from credit facility
118,307
90,497
Repayment of credit facility
(105,000)
(101,500)
Proceeds from sale of common stock for exercise of stock options
6,455
7,063
Repurchase of common stock
Dividends paid
(1,429)
Net cash provided by financing activities
(11,448)
(24,775)
Net change in cash and cash equivalents
4,150
12,754
Cash and cash equivalents at beginning of period
6,418
14,827
Cash and cash equivalents at end of period
$ 27,581
- 6 -
(Continued)
Supplemental schedule of additional cash flow information and noncash investing and financing activities:
Cash paid for interest, including amounts capitalized
$ 3,944
$ 4,374
Cash paid for income taxes
$ 22,741
$ 8,157
In May 2005, May 2004 and January 2004, the Company issued 13,926, 16,800 and 8,400 shares, respectively, of common
stock from treasury to its non-employee directors pursuant to the Company’s non-employee director stock compensation plan.
The Company recorded compensation expense related to the issuances of $25,500 and $341,000 for the six-month period
ended June 30, 2005 and June 30, 2004, respectively.
In March 2005 and June 2004 the Company issued 194,508 and 465,722 restricted stock units, respectively, pursuant to the
Company’s restricted stock plan. The total value of the issuances were $4.9 million and $8.3 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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. They do not include all information and notes required by generally accepted accounting principles 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, 2004. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the interim financial information have been included. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
Certain amounts in the 2004 unaudited condensed consolidated financial statements have been reclassified to conform to the 2005 unaudited condensed consolidated financial statement presentation.
Stock Dividend
In March 2005 the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend whereby one additional common share of stock was distributed for each common share outstanding. The stock dividend was distributed on March 31, 2005, to shareholders of record as of the close of business on March 21, 2005. All share and per share amounts for all prior periods presented herein have been restated to reflect this stock split.
Goodwill has been recorded as a result of the acquisition of Agate Petroleum, Inc. in January 2005. Goodwill is reviewed for impairment annually or more frequently if impairment indicators arise.
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, 2004. It is suggested that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes included in the Form 10-K.
- 8 -
Note 3 – Acquisitions
Agate Acquisition
On January 5, 2005, the Company acquired Agate Petroleum, Inc. (“Agate”) in exchange for $39.9 million in cash. The preliminary purchase price has been allocated based on the fair values of the acquired assets and liabilities as estimated at closing. The purchase price allocation will not be finalized until all amounts related to receivables and payables are determined with certainty. The Company expects that this allocation will be completed prior to the end of 2005 and will not result in any material adjustments to the preliminary purchase price. The Company acquired $4.6 million in cash from Agate, and the allocation of the purchase price resulted in the recording of $41.9 million to proved and unproved oil and gas properties, $1.2 million to net current liabilities, $9.6 million to goodwill, a deferred income tax liability of $13.6 million and a $1.4 million asset retirement obligation. The acquisition was accounted for using the purchase method of accounting and was funded with cash on hand and borrowings under the Company’s credit facility. Operating results from the acquired properties have been included in the consolidated statements of operations from the date of closing.
The goodwill and deferred income tax liability resulted from acquiring oil and gas assets in the transaction with a tax basis lower than the allocated fair value book basis because present value considerations cannot be applied to the amounts recorded for deferred income taxes. The strategic benefits to the Company that support the recognition of goodwill in this acquisition include the mix of complementary high-quality assets in two of our existing core areas, lower-risk exploitation opportunities, and increased cash flow from operations available for investing activities.
Southern Rockies Acquisition
In June 2005 the Company signed an agreement to acquire oil and gas properties primarily in the Wind River and Powder River Basins of Wyoming for $39.0 million in cash, subject to customary closing adjustments. The acquisition closed on August 1, 2005, for an adjusted purchase price of approximately $36.7 million. The acquisition was funded from cash on hand and funds available under St. Mary's existing credit facility. The purchase price allocation will not be finalized until all amounts related to receivables and payables are determined with certainty.
Note 4 – Earnings per Share
Basic net income per common share of stock is calculated by dividing net income available to common stockholders by the weighted-average common shares outstanding during each period. Vested restricted stock units are included in the calculation of the weighted-average common shares outstanding. The earnings per share calculations reflect the impact of the Company’s repurchase of shares of its common stock in 2004 and 2005 (see Note 11-Repurchase of Common Stock).
Diluted net income per common share of stock is calculated by dividing adjusted net income by the weighted-average of common shares outstanding, including the effect of potentially dilutive securities. Adjusted net income is used for the if-converted method and is derived by adding interest expense paid on the Company’s 5.75% Senior Convertible Notes due 2022 (the “Convertible Notes”) back to net income and then adjusting for nondiscretionary items that are based on income and that would have changed had the Convertible Notes been converted at the beginning of the period. Potentially dilutive securities of the Company consist of in-the-money outstanding options to purchase the Company’s common stock, shares into which the Convertible Notes may be converted and unvested restricted stock units.
The shares underlying the grants of restricted stock units are excluded from basic and diluted earnings per share until the measurement date for grants made under the Restricted Stock Plan. Upon
- 9 -
measurement, all unvested shares attributable to the restricted stock unit grant are included in the diluted earnings per share calculation. Vested shares are included in both basic and diluted earnings per share.
The dilutive effect of stock options and unvested restricted stock units is considered in the detailed calculation below. There were zero and 1,200,106 anti-dilutive securities related to stock options for the three-month and six-month periods ended June 30, 2004, respectively, and there were no anti-dilutive securities related to stock options for the three-month and six-month periods ended June 30, 2005, respectively. There were no anti-dilutive securities related to restricted stock units for any periods presented.
Shares associated with the conversion feature of the Convertible Notes are accounted for using the if-converted method as described above and are considered in the detailed calculation below. A total of 7,692,307 potentially dilutive shares related to the Convertible Notes were included in the calculation of diluted net income per common share for the three-month and six-month periods ended June 30, 2005, and 2004. The Convertible Notes were issued in March 2002 and can be called in March 2007.
The following table sets forth the calculation of basic and diluted earnings per share:
Adjustments to net income for dilution:
Add: interest expense not incurred if Convertible Notes converted
1,580
3,142
3,160
Less: other adjustments
(16)
(31)
(32)
Less: income tax effect of adjustmentitems
(577)
(596)
(1,150)
(1,188)
Net income adjusted for the effect of dilution
$ 39,248
$ 22,804
$ 75,325
$ 45,225
Add: dilutive effects of stock options and unvested restricted stock units
2,117
1,262
2,060
1,199
Add: dilutive effect of Convertible Notes using if-converted method
7,692
Basic earnings per common share
Diluted earnings per common share
Note 5 – Compensation Plans
Restricted Stock Plan
In May 2004 the Restricted Stock Plan was approved by the Company’s stockholders. This established a long-term incentive program whereby grants of restricted stock or restricted stock units (“RSUs”) may be awarded to eligible employees, consultants, and members of the Board of Directors. Restrictions and vesting periods for the awards are determined at the discretion of the Board of Directors and are set forth in the award agreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified deferral period. The total number of shares of the Company’s common stock reserved for issuance under the Restricted Stock
- 10 -
Plan is 11,200,000. This number is reduced to the extent that stock options are granted under the Company’s stock option plans.
St. Mary issued 194,508 RSUs on March 15, 2005, related to 2004 performance. The total expense associated with this issuance was $4.9 million as measured on the issuance date. The total unvested portion of the measured expense was initially recorded as deferred stock-based compensation and is being charged to compensation expense based on the vesting schedule. The RSU grants vest 25 percent immediately upon issuance and 25 percent on each of the first three anniversary dates. The vested shares underlying the RSU grants will be issued on the third anniversary of the issuance, at which time the shares carry no further restrictions. As of June 30, 2005, there were a total of 643,996 RSUs outstanding, of which 276,746 were vested. Total compensation expense related to the RSUs for the three-month and six-month periods ended June 30, 2005, was $1.2 million and $2.3 million, respectively. These amounts include $455,000 and $835,000 of compensation expense for the three-month and six-month periods ended June 30, 2005, respectively, related to the 2005 plan year for the estimated value of grants expected to be issued in 2006.
Net Profits Plan
Under the Company’s Net Profits Plan, oil and gas wells that are completed or acquired during a year are designated within a specific pool. Key employees designated as participants by the Company’s Compensation Committee of the Board of Directors and employed by the Company on the last day of that year vest and become entitled to bonus payments after the Company has received net cash flows returning 100 percent of all costs and expenses associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs and expenses for the pool, including payments made under the Net Profits Plan at the 10 percent level.
Expense related to current distributions made under the Net Profits Plan for the three-month periods ended June 30, 2005, and 2004, were $4.9 million and $1.5 million, respectively, and expense related to current distributions for the six-month periods ended June 30, 2005, and 2004, were $7.6 million and $3.5 million, respectively. These amounts relate to realized results from oil and gas operations for the associated properties in the respective periods.
In a separate calculation, the Company records the estimated future liability for the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The following table presents the changes in the estimated future liability attributable to the Net Profits Plan:
Beginning liability for Net Profits Plan
$ 34,782
$ 8,323
$ 30,561
$ 6,163
Increase in liability
17,078
5,785
23,964
9,941
Reduction in liability for cash payments made or accrued and recognized as compensation expense under the Net Profits Plan
(4,903)
(1,460)
(7,568)
(3,456)
Ending liability for Net Profits Plan
$ 46,957
$ 12,648
The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate item in the consolidated statements of operations. The change in the estimated
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liability is recorded as an increase or decrease to expense in the current period. The amount recorded as an increase or decrease to expense associated with the change in the estimated liability is not allocated to general and administrative costs or exploration costs because it is an estimate at the current time of the adjustment to the liability that is associated with the future net cash flows from oil and gas properties in the respective pools rather than current period realized performance. The table below presents the estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific line items:
General and administrative expense
$ 5,989
$ 2,725
$ 8,131
$ 3,629
Exploration expense
6,186
1,600
8,265
2,856
$ 12,175
$ 4,325
$ 16,396
$ 6,485
Stock Option Plans
Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” establishes a fair value method of accounting for stock-based compensation through either recognition or disclosure. The Company accounts for stock-based compensation using the intrinsic value recognition and measurement principles prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), and has elected to adopt SFAS No. 123 through compliance with the disclosure requirements set forth in the Statement. Because the exercise price of the Company’s stock options equals the market price of the underlying common stock on the date of grant, no compensation expense is recognized under APB No. 25. The following table illustrates the pro forma effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation for the periods presented.
Net income -
As reported:
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects
783
1,302
1,435
Less: Stock-based employee compensation expense determined under fair value based method for all awards, net of related income tax effects
(1,395)
(2,163)
(2,593)
(3,046)
Pro forma net income
$ 37,649
$ 20,975
$ 72,206
$ 41,541
Basic earnings per share -
As reported
Pro forma
$ 0.66
$ 0.37
$ 1.26
$ 0.71
Diluted earnings per share -
$ 0.58
$ 0.33
$ 1.11
$ 0.64
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For purposes of these pro forma disclosures, the estimated fair values of the options are amortized to expense over the options’ vesting periods. The effects of applying SFAS No. 123 in the pro forma disclosure are not necessarily indicative of actual future amounts.
The fair value of options and employee stock purchases has been measured at the date of grant using the Black-Scholes option-pricing model. The fair value of these awards granted in the three-month and six-month period ended June 30, 2005 and 2004, were estimated using the following weighted-average assumptions. No options were granted during the six-month period ended June 30, 2005.
Risk free interest rate
Stock options
*
3.6%
2.1%
Dividend yield
0.3%
0.5%
Volatility factor of the expected market price of the Company’s stock
38.5%
40.5%
16.1%
Expected life of the options (in years)
7.6
0.5
No options were granted under the Stock Option Plan in the first and second quarters of fiscal year 2005 or in the second quarter of fiscal year 2004.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The Company’s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management’s opinion that the valuations afforded by the existing models are different from the value that the options would realize if traded in the market.
In December 2004 the FASB issued SFAS No. 123 (Revised 2004), “Shared-Based Payment” (“SFAS No. 123R”). This statement provides for the accounting for transactions in which an entity exchanges equity instruments or incurs liabilities in exchange for goods or services. The effective date of this Statement was delayed by the Securities and Exchange Commission, and the Company will be required to adopt SFAS No. 123R on January 1, 2006. Under the modified-prospective method, the Company estimates that it will record a total of $2.8 million of compensation expense in periods following the implementation date related to the unvested portion of its stock options issued prior to the effective date. There will be no cumulative effect of change in accounting principle as a result of the adoption of SFAS No. 123R. Recorded compensation expense and pro-forma compensation expense related to stock-based compensation that is subject to accelerated vesting upon retirement are currently recognized over the vesting periods of the awards and are accelerated only upon retirement. Upon adoption of SFAS No. 123R, compensation expense related to accelerated vesting for awards issued on or after January 1, 2006, will be recognized over the period from the issuance of the award through the date on which the employee becomes eligible to retire. The impact of applying this new cost recognition
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method would not have a material effect on the Company’s financial statements or pro forma disclosures for any periods presented herein.
Note 6 - Income Taxes
Income tax expense for the three-month and six-month periods ended June 30, 2005, and 2004, differs from the amounts that would be provided by applying the statutory U.S. Federal income tax rate to income before income taxes primarily due to the effect of state income taxes, percentage depletion, the estimated effect of the domestic production activities deduction from the American Jobs Creation Act of 2004 and other permanent differences.
For the three-month and six-month periods ended June 30, 2005, the Company’s current portion of income tax expense was $14.5 million and $24.9 million, respectively, compared to $7.5 million and $13.4 million, respectively, for the three-month and six-month periods ended June 30, 2004. The Company’s effective tax rates for the three-month and six-month periods ended June 30, 2005, were 36.9 percent and 37.0 percent, respectively, compared to 38.1 percent and 38.0 percent, respectively, for the three-month and six-month periods ended June 30, 2004. The decrease in tax rate reflects a change in the composition of the estimated highest marginal state tax rate as a result of acquisition and drilling activity. It also reflects the Company’s estimate of the effect of the domestic production activities deduction and the possible impact of state tax permanent differences.
Note 7 - Long-term Debt
Revolving Credit Facility
The Company executed an Amended and Restated Credit Agreement on April 7, 2005, to replace the previous credit facility. The new credit facility specifies a maximum loan amount of $500 million and has a maturity date of April 7, 2010. Borrowings under the facility are secured by a pledge in favor of the lenders of collateral that includes certain oil and gas properties and the common stock of the material subsidiaries of the Company. The initial borrowing base under the new credit facility as authorized by the bank group was $400 million, and 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. The Company elected an initial aggregate commitment amount of $200 million under the new credit facility. The Company must comply with certain financial and non-financial covenants. Interest and commitment fees are accrued based on the borrowing base utilization percentage table below. Euro-dollar loans accrue interest at LIBOR plus the applicable margin from the utilization table, and Alternative Base Rate (ABR) 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 consolidated statements of operations.
Borrowing base
utilization percentage
<50%
>50%<75%
>75%<90%
>90%
Euro-dollar loans
1.000%
1.250%
1.500%
1.750%
ABR loans
0.000%
0.250%
0.500%
Commitment fee rate
0.300%
0.375%
At June 30, 2005, the Company’s borrowing base utilization percentage, as defined under the credit agreement, was 26 percent. The Company had $46.0 million in Euro-dollar loans and $5.0 million in ABR loans outstanding under its revolving credit facility as of June 30, 2005.
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5.75% Senior Convertible Notes Due 2022
As of June 30, 2005, the Company also had $100.0 million in outstanding borrowings under the Convertible Notes. The Convertible Notes provide for the payment of contingent interest of up to an additional 0.5 percent during six-month interest periods based on the note trading price before the beginning of the particular six-month period. Under that provision, interest was accrued at a total rate of 6.25 percent for the three-month and six-month periods ended June 30, 2005 and 2004. Based on the trading price of the Convertible Notes over the determination period, the Company will be subject to the contingent interest payments for the period from March 15, 2005, to September 14, 2005.
Weighted-average Interest Rate Paid
The weighted-average interest rates paid for the second quarters of 2005 and 2004 were 6.9 percent and 7.1 percent, respectively, including commitment fees paid on the unused portion of the credit facility aggregate commitment, amortization of deferred financing costs, amortization of the contingent interest embedded derivative and the effects of interest rate swaps. The weighted-average interest rates paid for the six-month periods ended June 30, 2005 and 2004, were 7.0 percent and 6.9 percent, respectively. The Company capitalized interest costs of $445,000 and $842,000 for the three-month and six-month periods ended June 30, 2005, respectively, and capitalized interest costs of $323,000 and $599,000 for the three-month and six-month periods ended June 30, 2004, respectively.
Note 8 – Derivative Financial Instruments
The Company recognized a net loss of $526,000 from its oil and gas derivative contracts for the six months ended June 30, 2005, compared to a net loss of $19.7 million for the same period in 2004. Comparative amounts for the three-month periods ended June 30, 2005, and 2004, were net losses of $2.1 million and $11.1 million, respectively.
The following table summarizes all derivative instrument gain (loss) activity for the periods presented (in thousands):
Derivative contract settlements included in oil and gas hedge loss
$ (2,086)
$ (11,134)
$ (526)
$ (19,733)
Ineffective portion of hedges qualifying for hedge accounting included in derivative gain (loss)
(409)
(1)
(1,023)
Non-qualified derivative contracts included in derivative gain (loss)
168
(1,720)
(347)
(883)
Interest rate derivative contract settlements
28
484
$ (2,327)
$ (12,855)
$ (1,868)
$ (20,118)
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Oil and Gas Commodity Hedges
The Company has in place derivative contracts for the sale of oil and natural gas. The Company attempts to qualify these instruments as cash flow hedges for accounting purposes.
The tables below describe the volumes and average contract prices of hedges currently in place, including contracts entered into after June 30, 2005. The Company’s oil and natural gas derivative contracts include swap and collar arrangements. Gas contracts are indexed to a variety of regional indexes, and oil contracts are primarily indexed to NYMEX. In addition to the NYMEX oil hedges below, the Company has entered into oil swaps indexed to Inside FERC Bow River to hedge certain sour oil production.
Swaps
Gas
Oil
Weighted-Average
Contract Price
Contract Period
Volumes
(Regional Index)
(NYMEX)
(MMBtu)
(per MMBtu)
(Bbl)
(per Bbl)
Quarter Ending:
September 30,
2,805,000
$ 6.43
349,980
$ 47.23
3,050,000
$ 6.84
351,770
$ 49.48
Total 2005
5,855,000
$ 6.64
701,750
$ 48.36
2006
March 31,
2,260,000
$ 7.36
295,366
$ 48.90
1,690,000
$ 6.14
217,976
$ 48.04
1,240,000
$ 6.05
161,372
$ 45.75
620,000
$ 6.25
95,686
$ 40.26
Total 2006
5,810,000
$ 6.61
770,400
$ 46.92
2007
270,000
$ 7.18
81,410
$ 40.27
$ 5.85
79,072
$ 40.14
90,000
$ 5.87
78,684
$ 39.50
75,620
$ 39.17
Total 2007
630,000
$ 6.42
314,786
$ 39.78
2008
15,000
$ 56.73
$ 56.58
5,000
$ 56.48
Total 2008
35,000
$ 56.63
All Contracts
12,295,000
$ 6.62
1,821,936
$ 46.43
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The Company seeks to minimize basis risk and indexes the majority of its oil contracts to NYMEX prices and its gas contracts to various regional index prices associated with pipelines in proximity to the Company’s areas of gas production. Swap natural gas volumes associated with specific Inside FERC (“IF”) regional indexes are as follows:
Regional Index
MMBtu
IF ANR OK
5,965,000
IF CIG
2,510,000
IF Reliant N/S
2,080,000
IF PEPL
1,740,000
Oil Swaps not Indexed to NYMEX
(IF Bow River)
2,000
$ 41.27
3,000
$ 38.40
$ 39.54
24,000
$ 39.16
30,000
$ 40.68
33,000
$ 40.46
$ 37.54
117,000
$ 37.42
34,000
$ 39.74
12,000
$ 39.86
76,000
$ 38.85
198,000
$ 39.25
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Natural Gas Collars
Contract
Floor
Ceiling
Period
Price
Index
$ 5.75
$ 7.30
415,000
$ 6.21
$ 7.99
540,000
$ 6.01
$ 7.69
955,000
$ 8.00
$ 9.15
150,000
$ 6.75
$ 8.20
$ 7.17
$ 8.52
450,000
$ 6.38
$ 7.95
1,405,000
Derivative gain (loss) in the consolidated statements of operations for the six months ended June 30, 2005, and 2004, include a net loss of $1.0 million and a net gain of $14,000, respectively, from ineffectiveness related to oil and natural gas derivative contracts. Comparative amounts for the three-month periods ended June 30, 2005, and 2004, were a net loss of $408,000 and $1,000, respectively. On June 30, 2005, the estimated fair value of oil and natural gas derivative contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a net liability of $28.4 million. If prices remain unchanged from quarter-end levels, the Company would reclassify this amount to oil and gas hedge loss included in operating revenue as the hedged production quantity is produced. As of June 30, 2005, the net amount of unrealized loss net of deferred income taxes to be reclassified from accumulated other comprehensive income to oil and gas production operating revenues in the next twelve months was $10.5 million. The Company anticipates that all forecasted transactions will occur by the end of their originally specified periods.
Interest Rate Derivative Contracts
In October 2003 the Company entered into fixed-to-floating interest rate swaps for a total notional amount of $50.0 million through March 20, 2007. Under the swaps, St. Mary will be paid a fixed interest rate of 5.75 percent and will pay a variable interest rate of 235 basis points above the six-month LIBOR rate as determined on the semi-annual settlement date. The payment dates of the swaps match exactly with the interest payment dates of the Convertible Notes. During the six-month periods ended June 30, 2005 and 2004, the Company received payments of $28,000 and $484,000, respectively, under the swap arrangements. These payments have reduced the Company’s interest expense.
The Company entered into a floating-to-fixed interest rate swap on April 13, 2005, for a total notional amount of $50.0 million through March 20, 2007, that effectively offsets the fixed-to-floating interest rate swaps described above. Under the swap, St. Mary will be paid a variable interest rate of 235 basis points above the six-month LIBOR rate as determined on the semi-annual settlement date and will pay a fixed interest rate of 6.85 percent. The payment dates of the swap match exactly with the interest payment dates of the Convertible Notes and the fixed-to-floating interest rate swaps. The impact of this instrument, when combined with the other interest rate swaps, is that the Company has fixed its net liability related to the interest rate swaps and will pay a 1.1 percent interest factor on $50.0 million of notional debt through March 2007.
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The fair value of the interest rate derivatives was a liability of $908,000 as of June 30, 2005. The Company recorded net derivative losses in the consolidated statements of operations of $475,000 for the six-month period ended June 30, 2005, and $790,000 for the six-month period ended June 30, 2004, from mark-to-market adjustments for these derivatives. Comparative amounts for the three-month periods ended June 30, 2005, and 2004, were a net gain of $201,000 and net loss of $1.6 million, respectively. The six-month LIBOR rate on June 30, 2005 was 3.71 percent.
These swaps do not qualify for fair value hedge treatment under SFAS No. 133 and related pronouncements.
Convertible Note Derivative Instrument
The contingent interest provision of the Convertible Notes is considered an embedded equity-related derivative that is not clearly and closely related to the fair value of an equity interest and therefore must be separately accounted for as a derivative instrument. The value of the derivative at issuance of the Convertible Notes in March 2002 was $474,000. This amount was recorded as a decrease to the Convertible Notes payable in the consolidated balance sheets. Interest expense for each of the six-month periods ended June 30, 2005, and 2004, includes $47,000 of amortization of this derivative. Interest expense for each of the three-month periods ended June 30, 2005, and 2004, includes $24,000 of amortization. Derivative gain (loss) in the consolidated statements of operations for the six-month periods ended June 30, 2005, and 2004, includes a net gain of $128,000 and a net loss of $93,000, respectively, from mark-to-market adjustments for this derivative. Comparative amounts for the three-month periods ended June 30, 2005, and 2004, were net losses of $33,000 and $97,000, respectively. The fair value of this derivative at June 30, 2005, was a liability of $692,000.
Note 9 – Pension Benefits
In December 2003 the FASB issued SFAS No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This statement replaces FASB Statement No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits”, and adds certain annual and interim period disclosure requirements. The provisions of this statement do not change the measurement and recognition provisions of SFAS No. 87, “Employers’ Accounting for Pensions”, SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Interim period disclosure requirements have been incorporated herein.
The Company’s employees participate in 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”).
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Components of Net Periodic Benefit Cost
The following table presents the components of the net periodic cost for both the Qualified Pension Plan and the Nonqualified Pension Plan:
Service cost
$ 346
$ 285
$ 693
$ 569
Interest cost
134
122
267
245
Expected return on plan assets
(94)
(74)
(188)
(148)
Amortization of prior service cost
(4)
(8)
Amortization of net actuarial loss
60
55
120
109
Net periodic benefit cost
$ 446
$ 384
$ 892
$ 767
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 10 percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants.
Contributions
St. Mary contributed $1.1 million to the Qualified Pension Plan during the second quarter of 2005. No further contributions are planned for the remainder of 2005.
Note 10 - Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the 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 is 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 consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and gas properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to 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 6.50 percent to 7.25 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.
- 20 -
A reconciliation of the Company's asset retirement obligation liability is as follows:
Beginning asset retirement obligation
$ 43,462
$ 26,036
$ 40,911
$ 25,485
Liabilities incurred
230
505
2,399
668
Liabilities settled
(36)
(150)
(359)
(227)
Accretion expense
727
477
1,432
942
Ending asset retirement obligation
$ 44,383
$ 26,868
Note 11 – Repurchase of Common Stock
Repurchase of Common Stock from Flying J
On February 9, 2004, the Company repurchased 6,671,636 restricted shares of its common stock from Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. (collectively “Flying J”) for a total of $91.0 million. St. Mary originally issued these shares to Flying J on January 29, 2003, in connection with St. Mary's acquisition of certain oil and gas properties. In addition to issuing the shares in the acquisition, St. Mary loaned Flying J $71.6 million. Flying J used the proceeds of the stock repurchase to repay their outstanding loan balance of $71.6 million. Accrued interest, which had not been recorded by the Company for financial reporting purposes due to the non-recourse nature of the loan, was forgiven. The net $19.4 million cash outlay for the repurchase was funded from the Company's existing cash balances and borrowings under its bank credit facility.
Stock Repurchase Program
In August 2004 the Company’s Board of Directors approved an increase in the number of shares that may be repurchased under the original authorization approved in August of 1998 to 6,000,000 as of the effective date of the resolution. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of St. Mary’s existing credit facility agreement and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow and borrowings under the credit facility.
During the second quarter of 2005, the Company repurchased a total of 1,157,810 shares of its common stock under the program at a weighted-average price of $24.48, including the effect of commissions. As of June 30, 2005, the number of shares remaining for which the Company has received Board authorization to repurchase was 3,863,590 shares.
- 21 -
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion contains forward-looking statements. Please refer to the Cautionary Statement about Forward-Looking Statements at the end of this item for an explanation of these types of statements.
Overview of the Company
General Overview
We are an independent energy company focused on the exploration, exploitation, development, acquisition and production of natural gas and crude oil in the United States. We earn our revenues and generate our cash flows from operations primarily from sales at the wellhead of produced natural gas and crude oil. Our oil and gas reserves and operations are concentrated in the Anadarko, Arkoma, Permian, and various Rocky Mountain basins together with the ArkLaTex region and the onshore Gulf Coast and the offshore Gulf of Mexico. We maintain a balanced portfolio of proved reserves, development drilling opportunities and non-conventional gas prospects.
In March 2005 the Board of Directors approved a two-for-one stock split in the form of a stock dividend whereby one additional common share of stock was distributed for each common share outstanding. The stock dividend was distributed on March 31, 2005, to shareholders of record as of the close of business on March 21, 2005. All share and per share amounts for all prior periods presented herein have been restated to reflect this stock split.
Oil and Gas Prices
Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. As 2005 progresses we continue to benefit from high oil and gas prices that are major contributing factors to the record financial results we are reporting. Higher natural gas prices are the result of tightening supply coupled with increasing demand in the United States. Finite storage capacity, changes in production, import capacity, and weather-related effects on domestic demand can impact price volatility. Higher oil prices reflect decreases in worldwide excess production capacity, continuing increases in demand from the global economy, the impact of weather on both supply and demand, and continued instability in the Middle East.
Second Quarter 2005 Highlights
NYMEX prices for the second quarter of 2005 averaged $6.80 per MMBtu and $53.17 per barrel, an increase of eight percent for gas and an increase of seven percent for oil compared to the first quarter of 2005. These prices were 14 percent higher for gas and 39 percent higher for oil than for the comparable period a year ago.
On June 29, 2005 we announced an agreement to acquire oil and gas properties for $39.0 million, subject to customary closing adjustments. The effective date of the acquisition was May 1, 2005. The acquisition closed August 1, 2005, for approximately $36.7 million in cash after normal purchase price adjustments. We acquired an estimated 22.5 BCFE of proved reserves, 72 percent of which are developed. The properties acquired are located primarily in the Wind River and Powder River Basins of Wyoming. At the time we announced the acquisition, the properties were producing an estimated 6,400 MCFE per day. This acquisition was funded using cash on hand and funds available under our existing credit facility.
- 22 -
During the second quarter of 2005 we purchased 1,157,810 shares of our common stock at an average cost of $24.48 per share, after inclusion of commissions. We have 3,863,590 shares available for repurchase out of the 6,000,000 shares authorized under the repurchase program.
On April 7, 2005, we closed a new five-year, $500 million credit facility agreement with Wachovia Bank, Wells Fargo Bank and eight other participating banks. The initial borrowing base for the facility was set as $400 million, and we elected an initial commitment of $200 million. Additional details regarding this facility are included below.
Results for the quarter ended June 30, 2005, reflect record quarterly production and record oil and gas revenues, which resulted in record net income and net cash provided by operating activities. The production results reflect our fourth consecutive quarter of production growth. Net income for the quarter ended June 30, 2005, was $38.3 million or $0.59 per diluted share compared to 2004 results of $21.8 million or $0.34 per diluted share. Net cash provided by operating activities was $93.4 million, up 56 percent from $59.9 million provided in the second quarter of 2004. Production increased 21 percent to 21.8 BCFE on a comparative-quarter basis, and our average realized price increased 38 percent to $7.28 per MCFE and reflects a $9.0 million decrease in oil and gas hedge loss between the two periods. Unit costs increased for the period as total production costs increased $0.18 to $1.38 per MCFE, and DD&A increased $0.41 to $1.56 per MCFE. We discuss these financial results and trends in more detail below.
The following table provides information regarding selected production and financial information for the quarter ended June 30, 2005, and the immediately preceding three quarters ended March 31, 2005, December 31, 2004, and September 30, 2004.
Three Months Ended
(In millions)
Production (MCFE)
21.8
20.6
19.9
19.0
Oil and gas production revenues
$160.4
$138.4
$139.3
$116.5
Oil and gas production expenses
30.2
32.2
26.2
24.2
7.5
6.0
5.5
$38.3
$35.1
$26.6
$22.6
Percentage change from prior quarter:
5%
4%
16%
20%
(6%)
23%
9%
25%
8%
32%
18%
First Six Months 2005 Highlights
NYMEX prices for the first six months of 2005 averaged $6.56 per MMBtu and $51.51 per barrel, an increase of 12 percent for gas and an increase of 40 percent for oil compared to the same period of 2004. As of June 30, 2005, the NYMEX strip price for the remainder of the year was $58.44 per barrel for oil and $7.38 per MMBtu for gas compared to June 30, 2004 NYMEX strip prices of $37.13 per barrel and $6.33 per MMBtu.
On January 5, 2005, we closed the acquisition of Agate Petroleum Inc. for $39.9 million in cash. Based on the preliminary purchase price allocation, we acquired $4.6 million in cash, and purchase accounting resulted in recording approximately $41.9 million to oil and gas properties, $9.6 million to goodwill, $1.2 million to net current liabilities, $13.6 million of deferred income tax liability and a $1.4 million asset retirement obligation.
- 23 -
Net income for the six months ended June 30, 2005, was a six-month record of $73.4 million or $1.13 per diluted share compared to the 2004 results of $43.3 million or $0.67 per diluted share. Production increased 16 percent to another six-month record of 42.4 BCFE. Our average realized price for the period ending June 30, 2005 increased 37 percent to $7.03 per MCFE from $5.15 reported at June 30, 2004, and reflects a $19.2 million decrease in oil and gas hedge loss between the two periods. We are also experiencing record high unit costs associated with our production. Total production unit costs increased $0.23 to $1.47 per MCFE. DD&A unit costs increased $0.38 to $1.51. General and administrative expense increased $0.02 to $0.32 per MCFE. We discuss these financial results and trends in more detail below.
Outlook for the Remainder of 2005
Over the remainder of 2005 we will continue to execute our business plan, including the following:
•
Our capital expenditures forecast has increased to $436 million. Of this amount, $311 million is allocated to drilling. A table of expected budget amounts by core area is detailed under the caption Capital Expenditure Forecast. We have spent approximately $83 million of our $125 million acquisitions budget, and we continue to pursue acquisition activities. The acquisition market has slowed during the summer months, but we anticipate activity will increase as we proceed into the fourth quarter.
Our Hanging Woman Basin coalbed methane project is in full development. In the first six months of 2005 we have completed 22 wells and have drilled an additional 26 wells that are expected to begin production by August 1, 2005, when the infrastructure for those wells is expected to also be completed. We are projecting that we will complete a total of 147 wells for the year. Production for the project continues to be ahead of forecast amounts and was 2,288 MCFE per day as of July 25, 2005.
We plan to participate in drilling 41 wells in the Williston Basin Middle Bakken Play during 2005. We currently have two operated drilling rigs and one operated re-entry rig in the play.
We tentatively plan to drill nine horizontal wells in the Centrahoma field during 2005. We have successfully completed vertical producing wells to the Cromwell formation in 11 sections in this field, and we hold 36,000 gross and 20,000 net contiguous acres in the area. Approximately half of that acreage is held by existing production. In 2005 we have drilled horizontal wells into two producing zones. The Mowdy #1 well was completed in March with an initial rate of 3,000 MCFE per day and had produced approximately 275,000 MCFE through June 30, 2005. During the second quarter we reached total depth on our first horizontal well in the Woodford shale formation. Our current plan is to evaluate this new well, and to drill a second horizontal well in the Cromwell formation before proceeding to drill our first horizontal test well into the Wapanuka limestone formation which has also produced from vertical wells. Our future development plans could ultimately result in approximately four Cromwell horizontal wells drilled per section in the field.
We continue to anticipate that production for 2005 will exceed 2004 reported amounts as a result of acquisitions and success in our drilling programs.
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A quarter and six-month overview of selected production and financial information, including trends:
Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
Three Months
% of Change
Six Months
Between Periods
Net production volumes
Natural gas (Mcf)
13,184
11,070
19%
25,231
22,683
11%
Oil (Bbl)
1,428
1,161
2,862
2,302
24%
MCFE (6:1)
21,754
18,038
21%
42,401
36,494
Average daily production
Natural gas (MMcf per day)
145
139
125
12%
Oil (MBbl per day)
16
13
MMCFE per day (6:1)
239
198
234
201
17%
Oil & gas production revenues(1)
Gas production
$ 89,220
$ 59,701
49%
$ 164,111
$ 120,141
37%
Oil production
69,115
35,746
93%
134,154
67,913
98%
$ 158,335
$ 95,447
66%
$ 298,265
$ 188,054
59%
Oil & gas production expense
Lease operating expenses
$ 19,162
$ 15,452
$ 39,398
$ 30,629
29%
Transportation costs
1,813
1,629
3,693
3,366
10%
Production taxes
9,213
4,492
105%
19,256
11,121
73%
$ 30,188
$ 21,573
40%
$ 62,347
$ 45,116
38%
Average realized sales price(1)
Natural gas (per Mcf)
$ 6.77
$ 5.39
26%
$ 6.50
$ 5.30
Oil (per Bbl)
$ 48.39
$ 30.78
57%
$ 46.88
$ 29.50
Per MCFE Data:
Average net realized price(1)
$ 7.28
$ 5.29
$ 7.03
$ 5.15
Lease operating expense
(0.88)
(0.86)
2%
(0.93)
(0.84)
(0.08)
(0.09)
(11)%
0%
(0.42)
(0.25)
68%
(0.45)
(0.31)
45%
(0.34)
(0.30)
13%
(0.32)
7%
Operating profit
$ 5.56
$ 3.79
47%
$ 5.24
$ 3.61
Depletion, depreciation and amortization
$ 1.56
$ 1.15
36%
$ 1.51
34%
(1) Includes the effects of our hedging activities
- 25 -
Financial Information (In Thousands, Except Per Share Amounts):
December 31, 2004
Working Capital
$ 739
$ 12,035
(94)%
Long-Term Debt
$ 150,838
$ 136,791
Stockholders’ Equity
Basic Net Income Per Common Share
76%
Diluted Net Income Per Common Share
74%
69%
Basic Weighted-Average
Shares Outstanding
--
(2%)
Diluted Weighted-Average
1%
(1%)
We present the preceding table as a summary of information relating to those key indicators of financial condition and operating performance that we believe to be most important. We present per MCFE information since we use this information to evaluate our performance relative to our peers and to measure trends that we believe require analysis. Our period-to-period comparison of financial results presented later provides additional details for the per MCFE differences between reported periods.
We expect oil and gas production expenses for the remainder of 2005 will be in line with the reported results from the first quarter of 2005. Production taxes will be higher as a percentage of revenue in the remainder of 2005 as a result of the increase in pricing that we are experiencing. Lease operating expense will be impacted by competition for scarce resources in the oil and gas service sector. Depreciation, depletion and amortization will increase due to the higher costs associated with finding and acquiring crude oil and natural gas. We expect general and administrative expense per MCFE will continue to increase through 2005 primarily as a result of our incentive compensation plans.
The remaining information in the table relates to information we have provided in operations update press releases and is intended to supplement the discussion above.
Overview of Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to execute our business plans for the foreseeable future.
Sources of Cash
Our primary sources of liquidity are the cash provided by operating activities and debt financing. We believe that we can access capital markets if needed, although we have no current plans to do so.
Our current credit facility. On April 7, 2005, we entered into a new five-year, $500 million credit facility agreement with Wachovia Bank, Wells Fargo Bank and eight other participating banks. This new credit facility replaced our previous $300 million credit facility discussed in Part II, Item 7 of our Form 10-K for the year ended December 31, 2004. The initial borrowing base for the new facility is set at $400 million. We elected an initial commitment amount of $200 million, which results in lower commitment
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fees payable to the bank syndicate. We believe this commitment level is adequate for our near-term liquidity requirements. The credit agreement has a maturity date of April 7, 2010. We must comply with certain financial and non-financial covenants, and we are currently in compliance with all of these covenants. Interest and commitment fees are accrued based on the borrowing base utilization percentage. Euro-dollar loans accrue interest at LIBOR plus the applicable margin from the utilization table, and Alternate Base Rate loans accrue interest at prime plus the applicable margin from the utilization table. This table is located in Note 7 of Part I, Item 1 of this report. Borrowings under the new facility are secured by the majority of our oil and gas properties and a pledge of the common stock of our material subsidiary companies.
Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the consolidated statements of operations. Our loan balance of $51.0 million on June 30, 2005, was comprised of $46.0 million of Euro-dollar based borrowing and $5.0 million of ABR borrowing. As of August 1, 2005, our total outstanding borrowings under the new credit facility had been reduced to $43.0 million of Euro-dollar based borrowing and $1.0 million of ABR borrowing. These amounts outstanding include the borrowings used to close our August 1, 2005, acquisition of oil and gas properties in Wyoming.
We increased our net borrowings by $14.0 million to $150.8 million in the first six months of 2005 primarily to fund our purchase of Agate Petroleum and to repurchase shares of our common stock. Our weighted-average interest rate paid in the first six months of 2005 was 7.0 percent and included commitment fees paid on the unused portion of the credit facility borrowing base, amortization of deferred financing costs, amortization of the contingent interest embedded derivative associated with the convertible notes, and the effects of interest rate swaps.
Interest rate market risk. Market risk is estimated as the potential change in fair value resulting from an immediate hypothetical one-percentage point parallel shift in the yield curve. We entered into a floating-to-fixed interest rate swap on April 13, 2005, for a total notional amount of $50.0 million through March 20, 2007, in order to effectively offset our fixed-to-floating interest rate swaps. Under the floating-to-fixed interest rate swap, we will be paid a variable interest rate of 235 basis points above the six-month LIBOR rate as determined on the semi-annual settlement date and will pay a fixed interest rate of 6.85 percent. The impact of this instrument, when combined with the other interest rate swaps, is that we have fixed our net liability related to the interest rate swaps, and we will pay a 1.1 percent interest factor on $50.0 million of notional debt through March 2007. The payment dates of the swap match exactly with the interest payment dates of the convertible notes and the fixed-to-floating interest rate swaps. We anticipate that increasing interest rates will result in higher interest expense for us in 2005 compared to last year.
For fixed-rate debt, interest rate changes affect the fair market value but do not impact results of operations or cash flows. Conversely, interest rate changes for floating-rate debt generally do not affect the fair market value but do impact future results of operations and cash flows, assuming other factors are held constant. The carrying amount of our floating-rate debt approximates its fair value. Giving consideration to the interest rate swaps in effect on June 30, 2005, we had floating-rate debt of $51.0 million and fixed-rate debt of $100.0 million as of that date. Assuming constant debt levels, the cash flow impact for the remainder of the year resulting from a one-percentage point change in interest rates would be approximately $257,000 before taxes. The results of operations impact might be less than this amount as a direct effect of the capitalization of interest to wells drilled during the year. In prior years when our debt amount was at a reduced level we capitalized a larger percentage of our interest expense. Since we cannot predict the exact amount that would be capitalized, we cannot predict the exact effect that a one-percentage point shift would have on the results of operations.
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Uses of Cash
We use cash for the acquisition, exploration and development of oil and gas properties and for the payment of debt obligations, trade payables, common stock repurchases and stockholder dividends. In the first six months of 2005 we spent $169.9 million on capital development and $28.3 million to acquire shares of our common stock using cash flows from operations and debt financing. We also made cash payments for income taxes of $22.7 million.
We have Board authorization to repurchase up to an additional 3,863,590 shares of our common stock under our stock repurchase program. These shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our existing bank credit facility agreement and compliance with securities laws.
In connection with our two-for-one stock split in March 2005, we announced that the semi-annual dividend rate would remain at $0.05 per share. This effectively doubles our cash dividend payments from 2004.
The following table presents amounts, in thousands, and percentage changes in cash flows between the six-month periods ending June 30, 2005, and 2004. The analysis following the table should be read in conjunction with our consolidated statements of cash flows in Part I, Item 1 of this report.
Six Months Ended
Percent
Change
85,757
86%
107,688
173%
Net cash used in financing activities
(13,327)
(54%)
Analysis of cash flow changes between the six months ended June 30, 2005 and June 30, 2004
Operating activities. Sources of cash flow from oil and gas sales, net of the effects of hedging, increased $112.9 million between the six-month periods ended June 30, 2005, and 2004. This was the result of a 37 percent increase in our realized prices and a 16 percent increase in production between the two periods. Cash expenditures for oil and gas production expenses, exploration expenses and administrative expenses increased by $20.1 million between the two comparable periods. This net increase of $92.8 million was partially offset by changes in income tax payments and by changes in current assets and liabilities.
Investing activities. Total 2005 capital expenditures, including acquisitions of oil and gas properties, increased $83.3 million or 96 percent to $169.9 million compared to $86.6 million in 2004. This increase reflects increased drilling expenditures and net cash paid for the acquisition of Agate in 2005. The six-month period ending June 30, 2004, reflects $22.9 million cash received from short-term investments and the expiration of the restriction period for funds held for tax-deferred exchange of oil and gas properties.
Financing activities. Net borrowings against our credit facility were $13.3 million for the six months ended June 30, 2005, versus net repayments of $11.0 million for the same period of 2004. We spent $28.3 million to acquire shares of our common stock under our stock repurchase program in 2005, compared to $19.4 million paid in 2004 to repurchase shares of our common stock from Flying J and settle the loan receivable from Flying J. Cash paid for dividends was $2.9 million in 2005, which is double the $1.4 million paid in 2004.
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St. Mary had $10.6 million in cash and cash equivalents and had working capital of $739,000 as of June 30, 2005, compared to $6.4 million in cash and cash equivalents and working capital of $12.0 million as of December 31, 2004.
Capital Expenditure Forecast
We use our resources primarily for the exploration and development of oil and gas properties and for acquisitions. We anticipate spending approximately $436 million for capital and exploration expenditures in 2005 with $125 million allocated for acquisitions of producing properties. Anticipated ongoing exploration and development expenditures and budgeted gross wells for each of our core areas are as follows. The timing of drilling and completion of wells is variable and will differ from these estimates.
Exploration and
Development
Expenditures
Gross
Well Count
Rocky Mountain region
$ 103
144
Mid-Continent region
95
90
Gulf Coast region
11
ArkLaTex region
36
81
Coalbed Methane
175
Permian Basin region
9
25
$ 311
526
We regularly review our capital expenditure budget to reflect changes in current and projected cash flow, acquisition opportunities, drilling opportunities, debt requirements and other factors. The above allocations are subject to change based on these factors.
The following table sets forth certain information regarding the costs incurred by us in our oil and gas property acquisition, exploration and development activities, whether capitalized or expensed.
Development costs
$ 112,338
$ 67,850
Exploration costs
31,346
15,186
Acquisitions:
Proved
39,563
4,912
Unproved
2,178
Leasing activity
7,596
4,890
Total including asset retirement obligation
$ 193,021
$ 92,851
Our costs incurred for capital and exploration activities for the six months ended June 30, 2005, increased $100.2 million or 108 percent compared to the same period in 2004. This increase reflects our 2005 acquisition of Agate and planned increases in our drilling activity budget.
We continue to develop the coalbed methane reserves in our Hanging Woman Basin project. We completed 22 wells during the first six months and have an additional 26 wells drilled and awaiting
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completion of field infrastructure. Permitting is on schedule to complete approximately 147 wells for the year. We have 154,000 net lease acres in the basin and are concentrating our initial development on 80,000 net acres located in Wyoming. Outstanding legal challenges filed by environmental public interest groups affect our 47,000 net acres of federal land in Montana relating to this project. These challenges may delay our development of the Montana portion of our project as the federal district court has remanded to the BLM the environmental impact statement prepared for the development of coalbed methane projects in southern Montana so that the BLM may further study the effect of phased development. The term of our federal leases will be extended for the time it takes to resolve these legal challenges. Neither St. Mary nor any of its affiliates is a named party in any of these legal challenges.
We believe that internally generated cash flows, together with our credit facility, will be sufficient to fund our expected operational, drilling and acquisition expenditures for the foreseeable future. The amount and allocation of future capital and exploration expenditures will depend upon a number of factors, including the number and size of available acquisition opportunities, whether we can make an economic acquisition, and our ability to assimilate acquisitions we make. Also, the impact of oil and gas prices on investment opportunities, the availability of capital and borrowing facilities and the success of our development and exploratory activities could lead to increased funding requirements for further development.
Financing alternatives
The debt and equity financing capital markets remain attractive to energy companies that operate in the exploration and production segment. This is a result of strong commodity prices and the general strength reflected in the balance sheets of the companies in this segment. As our cash balance and availability under our existing credit facility are significant, we are not currently considering accessing the capital markets in 2005. If additional development or attractive acquisition opportunities arise that exceed our currently available resources, we may consider other forms of financing, including the public offering or private placement of equity or debt securities.
Sensitivity Analysis
We are exposed to market risk, including the effects of changes in oil and gas commodity prices and changes in interest rates as discussed below and under the caption “Interest rate market risk.” Since we produce and sell natural gas and crude oil, our financial results can be affected when prices for these commodities fluctuate. In order to reduce the impact of fluctuations in commodity prices, we enter into hedging transactions as discussed below. Changes in interest rates can affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility. Changes in interest rates do not affect the interest we pay on our fixed rate convertible notes, but do affect the fair value of that debt.
Note 8 of Part I, Item 1 of this report contains important information about our oil and gas derivative contracts, including the volumes and average contract prices of hedges we currently have in place and have entered into through August 1, 2005, and our interest rate derivative contracts. We anticipate that all hedge and derivative contract transactions will occur as expected.
There has been no material change to the natural gas and crude oil price sensitivity analysis previously disclosed. Please see the corresponding section under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004.
Summary of Oil and Gas Production Hedges in Place
Our net realized oil and gas prices are impacted by hedges we have placed on future forecasted transactions. We have historically entered into hedges of existing production around the time we make
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acquisitions of producing oil and gas properties. Our intent is to lock in a significant portion of an equivalent amount of existing production to the prices we used to evaluate the risked economics of our acquisition. We also hedge a small percentage of our forecasted production on a discretionary basis.
For swap contracts in place on June 30, 2005, a hypothetical increase of 10 percent in future gas strip prices, as of June 30, 2005, representing a $0.71 weighted-average increase per MMBtu applied to a notional amount of 11.7 million MMBtu covered by natural gas swaps would cause a decrease in the value of the derivative instruments of $8.3 million. A hypothetical increase of 10 percent in the future NYMEX strip oil prices, as of June 30, 2005, representing a $5.64 weighted-average increase per Bbl applied to a notional amount of 2.0 MMBbl covered by crude oil swaps would cause a decrease in the value of the derivative instruments of $11.1 million.
For collar contracts in place on June 30, 2005, a hypothetical increase of 10 percent in future gas strip prices, as of June 30, 2005, representing a $0.68 weighted-average increase per MMBtu applied to a notional amount of 805,000 MMBtu covered by natural gas collars would cause a decrease in the value of the derivative instruments of $261,000.
The effect of the price increase would impact the hedge gain or loss amounts. However, these are cash flow hedges with high correlation, and the price we receive on the underlying production would be higher by approximately the same amount. As a result, the effect on our net results of operations would be minimal.
Please see Note 8 – Derivative Financial Instruments in Part I, Item I of this report for additional information regarding our oil and gas hedges.
Summary of Interest Rate Hedges in Place
We entered into fixed-rate to floating-rate interest rate swaps on $50.0 million of convertible notes on October 3, 2003. Due to continuing increases in interest rates, we entered into a floating-to-fixed interest rate swap on April 13, 2005, through March 20, 2007, on this same notional amount of $50.0 million in order to effectively offset our fixed-to-floating interest rate swaps. Details of the floating-to-fixed interest rate swap are included under the caption “Interest rate market risk” above.
We anticipate that interest expense in 2005 will be higher than in 2004. Please see Note 8 of Part I, Item I of this report for additional information regarding our interest rate swaps.
Schedule of Contractual Obligations
The following table summarizes our future estimated principal payments and minimum lease payments for the periods specified (in millions):
Less than 1 year
More than 5 years
Contractual Obligations
1-3 years
3-5 years
$ 151.0
$ 100.0
$ 51.0
Operating Leases
10.2
2.6
4.2
2.4
1.0
Other Long-Term Liabilities
20.3
2.1
15.5
1.4
1.3
$ 181.5
$ 4.7
$ 119.7
$ 54.8
$ 2.3
This table includes our 2006 estimated pension liability payment of approximately $1.3 million, but excludes the remaining unfunded portion of our estimated pension liability of $1.0 million, as we cannot determine with accuracy the timing of future payments. The table does not include estimated payments associated with our Net Profits Plan. We record a liability for the estimated future payments. However,
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predicting the precise timing when the liability will be paid is contingent upon estimates of appropriate discount factors adjusting for risk and time-value and upon a number of factors that we cannot control. We have excluded asset retirement obligations because we are not able to precisely predict the timing for these amounts. The net profits plan, pension liabilities and asset retirement obligations are discussed in Note 7, Note 8 and Note 9, respectively, of Part IV Item 15 of our Form 10-K for the year ended December 31, 2004, and also in Note 5, Note 9 and Note 10, respectively, of Part I Item 1 of this report.
Three leases for office space will expire in year two and one office space lease will expire in year three. Estimated costs to replace these leases are not included in the table above. For purposes of the table we assume that the holders of our convertible notes will not exercise the conversion feature. If the holders do exercise their conversion feature, we will not have to repay the $100 million, and our common shares outstanding would increase by 7,692,307 shares.
We have announced that we have effectively doubled our dividend from prior years, and we believe that we will continue to pay the semi-annual dividend of $0.05 per share. We anticipate having sufficient cash to make payments for income taxes, dependent on net income and capital spending.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing other than operating leases, nor do we have any unconsolidated subsidiaries.
Critical Accounting Policies and Estimates
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004.
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Additional Comparative Data in Tabular Form:
Change Between the
June 30, 2005 and 2004
Increase in oil and gas production revenues, net of hedging (in thousands)
$ 62,888
$ 110,211
Components of Revenue Increases (Decreases):
Natural Gas
Realized price change per Mcf
$ 1.38
$ 1.20
Realized price percentage change
Production change (MMcf)
2,114
2,548
Production percentage change
Realized price change per Bbl
$ 17.61
$ 17.38
Production change (MBbl)
560
Our Product Mix as a Percentage of Total Oil and Gas Revenue and Production:
Revenue
Natural gas
56%
63%
55%
64%
44%
Production
61%
60%
62%
39%
Information Regarding the Components of Exploration Expense:
Summary of Exploration Expense (in millions)
Geological and geophysical expenses
$ 1.5
$ 1.4
$ 3.5
$ 2.2
1.9
1.1
1.2
Overhead and other expenses
6.3
4.1
11.2
7.8
$ 9.7
$ 6.6
$ 16.8
$ 11.2
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Information Regarding the Effects of Oil and Gas Hedging Activity:
Natural Gas Hedging
Percentage of gas production hedged
Natural gas MMBtu hedged
3.0 million
2.5 million
5.8 million
6.5 million
Increase (decrease) in gas revenue
$ (112,000)
$ (4.0 million)
$ 3.7 million
$ (7.1 million)
Average realized gas price per Mcf before hedging
$ 6.78
$ 6.36
$ 5.61
Average realized gas price per Mcf after hedging
Oil Hedging
Percentage of oil production hedged
43%
Oil volumes hedged (MBbl)
266
519
518
982
Decrease in oil revenue
$ (2.0 million)
$ (7.2 million)
$ (4.2 million)
$(12.6 million)
Average realized oil price per Bbl before hedging
$ 49.77
$ 36.96
$ 48.35
$ 34.99
Average realized oil price per Bbl after hedging
Comparison of Financial Results and Trends between the Quarters ended June 30, 2005 and 2004
Oil and gas production revenue. Average net daily production increased 21 percent to a record 239.1 MMCFE for the quarter ended June 30, 2005, compared with 198.2 MMCFE for the quarter ended June 30, 2004. The following table presents specific components that contributed to the increase in revenue between the two quarters:
Average Net Daily Production
Added (MMCFE)
Oil and Gas
Revenue Added (Millions)
Costs Added (Millions)
Paggi-Broussard 1 (SM 40%)
12.8
$ 9.3
$ (0.3)
Williston Basin Middle Bakken Play
12.6
10.5
(0.3)
Other wells completed in 2004 and 2005
24.1
22.8
Goldmark acquisition
0.9
Border acquisition
3.2
0.1
Agate acquisition
5.0
4.0
Other acquisitions
0.8
0.2
64.2
$ 51.2
$ 6.3
The increases in this table also reflect the difference in oil and gas prices received between the comparable periods. These increases are offset by natural declines in production from older properties to result in the net increase in production between the quarters presented. Additional production costs reflect increases resulting from inflation and competition for resources.
Oil and gas production expense. Total production costs increased $8.6 million, or 40 percent, to $30.2 million for the second quarter of 2005 from $21.6 million in the comparable period of 2004. As noted in the table above, completed wells and acquisitions in 2004 and 2005 have
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added $6.3 million of incremental production costs in 2005. Additionally, we experienced an increase in value-based production taxes consistent with an increase in revenue from crude oil and natural gas due to both higher prices and accrued Oklahoma severance tax incentives in 2004 that were not allowed in 2005.
Total oil and gas production costs per MCFE increased $0.18 to $1.38 for 2005, compared with $1.20 for 2004. This increase is comprised of the following:
A $0.14 increase in production taxes in our Mid-Continent region resulting from higher natural gas revenues and the disallowance of Oklahoma severance tax incentives in 2005 due to average natural gas prices in excess of price caps;
A $0.04 increase in production taxes due to higher revenue from crude oil in our Rocky Mountain and Permian regions;
A $0.01 decrease in production taxes in our ArkLaTex region reflecting additional benefits from severance tax incentive credits received from Louisiana and Texas;
A $0.01 decrease in transportation cost;
A $0.07 increase in LOE reflecting a general 7 percent increase that we had forecast in our budget process that was caused by competition for resources;
A $0.03 increase due to the start-up activity in our Hanging Woman Basin coalbed methane project; and
An $0.08 overall decrease in LOE relating to workover charges.
General and administrative. General and administrative expenses increased $2.1 million or 38 percent to $7.5 million for the quarter ended June 30, 2005, compared with $5.4 million for the comparable period of 2004. G&A increased $0.04 to $0.34 per MCFE for the second quarter of 2005 compared to $0.30 per MCFE for the same three-month period in 2004 as G&A grew at a faster rate than the 21 percent increase in production.
As we grow, our employee count increases. This has resulted in an increase in base employee compensation of $869,000 between the second quarter of 2005 and the second quarter of 2004. Oil and gas price increases have triggered additional Net Profits Plan payouts and have increased the amounts payable to plan participants. Consequently, the current period realized expense associated with the Net Profits Plan has increased by $3.4 million to $4.9 million in 2005 as compared to $1.5 million in 2004. This increase combined with a net $809,000 increase in other compensation expense was mostly offset by COPAS overhead reimbursements and allocation of G&A to exploration expense. COPAS overhead reimbursement from operations increased $893,000 due to an increase in operated well count resulting from our drilling and acquisition programs. The amount of G&A we allocated to exploration expense increased $2.1 million due to incentive plan payment increases and increases in our technical exploration staff.
Change in Net Profits Plan liability. For the quarter ended June 30, 2005, this expense increased $7.9 million to $12.2 million from $4.3 million for 2004. This increase reflects our estimation of the effect of a sustained higher price environment on the performance of individual pools. The 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. We believe these factors will result in this expense continuing to be higher in 2005 than in 2004.
Interest expense. Interest expense increased by $709,000 to $2.3 million for 2005 compared to $1.6 million for 2004. The increase reflects an overall increase in our outstanding borrowings and interest rates on a comparative basis.
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Income taxes. Income tax expense totaled $22.3 million for the second quarter of 2005 and $13.4 million for the second quarter of 2004 resulting in effective tax rates of 36.9 percent and 38.1 percent, respectively. The effective rate change from 2004 reflects changes in the mix of the highest marginal state tax rates as a result of acquisition and drilling activity and also reflects other permanent differences including the estimated effect of the domestic production activities deduction from the American Jobs Creation Act of 2004.
Comparison of Financial Results and Trends between the six months ended June 30, 2005 and 2004
Oil and gas production revenue. Average net daily production increased 17 percent to 234.3 MMCFE for the six months ended June 30, 2005, compared with 200.5 MMCFE for the six months ended June 30, 2004. The following table presents specific components that contributed to the increase in revenue between the two periods:
11.9
$ 16.1
$ 0.2
11.1
18.1
0.6
29.9
43.1
3.4
3.1
2.2
5.4
5.2
6.4
2.3
0.4
67.9
$ 93.5
$ 12.8
Oil and gas production expense. Total production costs increased $17.2 million, or 38 percent, to $62.3 million in 2005 from $45.1 million in 2004. As noted in the table above, completed wells and acquisitions in 2004 and 2005 have added $12.8 million of incremental production costs in 2005. Additionally, we experienced an increase in value-based production taxes consistent with an increase in revenue from crude oil and natural gas due to higher prices, and we benefited from accrued Oklahoma severance tax incentives in 2004 that were not allowed in 2005.
Total oil and gas production costs per MCFE increased $0.23 to $1.47 for 2005, compared with $1.24 for 2004. This increase is comprised of the following:
An $0.08 increase in production taxes in our Mid-Continent region resulting from higher natural gas revenues and the disallowance of Oklahoma severance tax incentives in 2005 due to average natural gas prices in excess of price caps;
A $0.07 increase in production taxes due to higher revenue from crude oil in our Rocky Mountain and Permian regions;
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A $0.02 overall decrease in LOE relating to workover charges.
General and administrative. General and administrative expenses increased $2.5 million or 23 percent to $13.5 million for the six months ended June 30, 2005, compared with $11.0 million for the six months ended June 30, 2004. G&A increased $0.02 to $0.32 per MCFE for the six-month period of 2005 compared to $0.30 per MCFE for the six-month period of 2004 as the percentage increase in G&A was greater than the 16 percent increase in production.
The increase in employee count has resulted in an increase in general and administrative expenses of $1.7 million between the first six months of 2005 and the first six months of 2003. Accounting fees increased $158,000 between the same periods. The current period realized expense associated with the Net Profits Plan has increased by $4.1 million to $7.6 million in 2005 as compared to $3.5 million 2004. This increase plus a $1.3 million increase in expense associated with our other incentive compensation plans was mostly offset by COPAS overhead reimbursements and allocation of G&A to exploration expense. COPAS overhead reimbursement from operations increased $1.4 due to an increase in operated well count resulting from our drilling and acquisition programs. The amount of G&A we allocated to exploration expense increased $3.3 million due to incentive plan payment increases and increases in our technical exploration staff.
Change in Net Profits Plan liability. This expense increased $9.9 million to $16.4 million for the six months ended June 30, 2005, compared to $6.5 million for the six months ended June 30, 2004. The increase reflects sustained higher oil and gas prices.
Interest expense. Interest expense increased by $1.2 million to $4.2 million for 2005 compared to $3.1 million for 2004. The increase reflects an overall increase in our outstanding borrowings and interest rates on a comparative basis. Additionally, we received benefits from fixed-to-floating interest rate swaps in effect during 2004 that were effectively offset by floating-rate-to-fixed-rate interest rate swaps we entered into in April 2005.
Income taxes. Income tax expense totaled $43.0 million for the second quarter of 2005 and $26.5 million for the second quarter of 2004, resulting in effective tax rates of 37.0 percent and 37.9 percent, respectively. The effective rate change from 2004 reflects changes in the mix of the highest marginal state tax rates as a result of acquisition and drilling activity and also reflects other permanent differences including the estimated effect of the domestic production activities deduction from the American Jobs Creation Act of 2004.
The current portion of the income tax expense in 2005 is $24.9 million compared to $13.4 million in 2004. These amounts are 58 percent and 51 percent of the total tax for the respective periods. Although we increased our 2005 budget for drilling expenditures over 2004 amounts, our projections are for even larger increases in revenue due to anticipated production and pricing. As a result, we continue to believe that current taxable income and the resulting current portion of income tax as a percentage of total income tax will be higher in 2005 than it was in 2004.
Accounting Matters
We refer you to Note 2 and Note 5 of Part I, Item 1 of this report for information regarding accounting matters.
Environmental
St. Mary’s compliance with applicable environmental regulations has not resulted in any significant capital expenditures or materially adverse effects on our liquidity or results of operations. We believe that we are in substantial compliance with environmental regulations, and we do not currently expect that any
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material expenditure will be required in the foreseeable future. However, we are unable to predict the impact that future compliance with regulations may have on future capital expenditures, liquidity and results of operations.
Cautionary Statement About Forward - Looking Statements
This Quarterly Report on Form 10-Q includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that St. Mary’s management expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “will,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” and similar expressions are intended to identify forward - looking statements, although not all forward - looking statements contain such identifying words. Examples of forward-looking statements may include discussion of such matters as:
the amount and nature of future capital, development and exploration expenditures,
the drilling of wells,
reserve estimates and the estimates of both future net revenues and the present value of future net revenues that are included in their calculation,
future oil and gas production estimates,
repayment of debt,
business strategies,
expansion and growth of operations,
recent legal developments, and
other similar matters.
These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, including such factors as the volatility and level of oil and natural gas prices, unexpected drilling conditions and results, production rates and reserve replacement, the imprecise nature of oil and gas reserve estimates, drilling and operating service availability and risks, uncertainties in cash flow, the financial strength of hedge contract counterparties, the availability of attractive exploration, development and property acquisition opportunities, financing requirements, expected acquisition benefits, competition, litigation, environmental matters, the potential impact of government regulations, and other matters discussed in the “Risk Factors” section of our 2004 Annual Report on Form 10-K. Readers are cautioned that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those expressed or implied in the forward-looking statements. Although we may from time to time voluntarily update our prior forward - looking statements, we disclaim any commitment to do so except as required by securities laws.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions “Interest Rate Market Risk” and “Sensitivity Analysis” in Item 2 above and is incorporated herein by reference.
ITEM 4. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective for the purposes discussed above as of the end of the period covered by this Quarterly Report on Form 10-Q. There was no significant change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a material adverse effect upon our financial condition or results of operations.
The previously reported litigation in which our subsidiary, Nance Petroleum Corporation, was named a party has been fully and finally resolved. The federal leases held by Nance Petroleum Corporation that were subject to this litigation are currently valid.
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ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(a)
In May 2005 St. Mary issued a total of 13,926 restricted shares of common stock valued at $306,000 from treasury to non-employee directors pursuant to the Company’s non-employee director stock compensation plan. These shares were not registered under the Securities Act of 1933 in reliance on Rule 506 of Regulation D promulgated under the Securities Act, since the directors are accredited investors and certificates representing the shares bear a legend restricting the transfer of those shares.
(c)
The following table provides information about purchases by the Company during the quarter ended June 30, 2005, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act.
ISSUER PURCHASES OF EQUITY SECURITIES
Total Number of Shares Purchased
(b)
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Program (1)
(d)
Maximum Number of Shares that May Yet Be Purchased Under the Program (1)
04/01/05 – 04/30/05
- 0 -
$ - 0 -
5,021,400
05/01/05 – 05/31/05
1,157,810
$ 24.48
3,863,590
06/01/05 – 06/30/05
Total:
In August 2004 the Company’s Board of Directors approved an increase in the number of shares that may be repurchased under the original authorization approved in August of 1998 to 6,000,000 as of the effective date of the resolution. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of St. Mary’s existing bank credit facility agreement and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow and borrowings under St. Mary’s bank credit facility. The stock repurchase program may be suspended or discontinued at any time.
The payment of dividends and stock repurchases are subject to covenants in our bank credit facility, including the requirement that we maintain certain levels of stockholders’ equity and the limitation of our annual dividend rate to no more than $0.25 per share.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Company’s annual stockholders’ meeting on May 25, 2005, the stockholders elected management’s current slate of directors. Each director was elected by a majority vote. The directors elected and the vote tabulation for each director is as follows:
Director
For
Withheld
Barbara M. Baumann
49,278,216
298,386
Larry W. Bickle
49,410,242
166,360
Thomas E. Congdon
49,322,876
253,726
William J. Gardiner
48,812,827
763,775
Mark A. Hellerstein
49,341,472
235,130
John M. Seidl
49,224,696
351,906
William D. Sullivan
49,436,428
140,174
Also at the Company’s annual stockholders’ meeting on May 25, 2005, the stockholders approved an amendment to the certificate of incorporation to increase the number of authorized shares of common stock from 100,000,000 to 200,000,000. The amendment was approved by a majority vote. The tabulation of votes for that proposal is as follows:
44,969,546
Against
4,564,069
Abstain
36,187
Not Voted
6,801
ITEM 6. EXHIBITS
The following exhibits are furnished as part of this report:
Exhibit
Description
3.1*
Restated Certificate of Incorporation of St. Mary Land & Exploration Company as amended on May 25, 2005
3.2*
Certificate of Amendment to Restated Certificate of Incorporation of St. Mary Land & Exploration Company dated May 25, 2005
10.1
Amended and Restated Credit Agreement dated April 7, 2005 among St. Mary Land & Exploration Company, Wachovia Bank, National Association as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
Amended and Restated Guaranty Agreement by St. Mary Energy Company in favor of Wachovia Bank, National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
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10.3
Amended and Restated Guaranty Agreement by Nance Petroleum Corporation in favor of Wachovia Bank, National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
10.4
Amended and Restated Guaranty Agreement by NPC Inc. in favor of Wachovia Bank, National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
Amended and Restated Pledge and Security Agreement between St. Mary Land & Exploration Company and Wachovia Bank, National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
10.6
Amended and Restated Pledge and Security Agreement between Nance Petroleum Corporation and Wachovia Bank, National Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
10.7
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
10.8
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March, 31, 2005, and incorporated herein by reference)
10.9*
Amendment to Form of Change of Control Severance Agreement
31.1*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
32.1*
Certification pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002
_________________________
Filed with this Form 10-Q.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
August 4, 2005
By:
/s/ MARK A. HELLERSTEIN
President and Chief Executive Officer
/s/ DAVID W. HONEYFIELD
David W. Honeyfield
Vice President - Chief Financial Officer,
Secretary and Treasurer
/s/ GARRY A. WILKENING
Garry A. Wilkening
Vice President - Administration and
Controller
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