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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2004
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Commission File Number 001-31539
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 41-0518430
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
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 October 29, 2004, the registrant had 28,633,580 shares of common stock,
$0.01 par value, outstanding.
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ST. MARY LAND & EXPLORATION COMPANY
INDEX
Part I. FINANCIAL INFORMATION PAGE
----
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets - September 30, 2004
and December 31, 2003........................................3
Consolidated Statements of
Operations - Three and Nine Months Ended
September 30, 2004 and 2003..................................4
Consolidated Statements of
Cash Flows - Nine Months Ended
September 30, 2004 and 2003..................................5
Consolidated Statements of Stockholders' Equity and
Comprehensive Income - September 30, 2004 and
December 31, 2003............................................7
Notes to Consolidated Financial
Statements - September 30, 2004..............................8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.........................23
Item 3. Quantitative and Qualitative Disclosures About
Market Risk (included within the content of Item 2.)........39
Item 4. Controls and Procedures.....................................39
Part II. OTHER INFORMATION
Item 1. Legal Proceedings...........................................39
Item 2. Unregistered Sales of Equity Securities
and Use of Proceeds.........................................40
Item 5. Other Information...........................................41
Item 6. Exhibits....................................................41
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
September 30, December 31,
-------------------------------
ASSETS 2004 2003
-------------- -------------
Current assets:
Cash and cash equivalents $ 24,688 $ 14,827
Short-term investments 1,431 12,509
Accounts receivable 91,397 65,084
Prepaid expenses and other 4,594 6,020
Deferred income taxes 8,564 8,872
Other 5,226 611
-------------- -------------
Total current assets 135,900 107,923
-------------- -------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 975,710 858,246
Less - accumulated depletion, depreciation and amortization (371,410) (312,719)
Wells in progress 47,403 24,691
Unproved oil and gas properties, net of accumulated impairment
allowance of $11,756 in 2004 and $10,776 in 2003 38,317 36,793
Other property and equipment, net of accumulated depreciation
of $5,557 in 2004 and $4,656 in 2003 6,964 4,276
-------------- -------------
696,984 611,287
-------------- -------------
-------------- -------------
Other noncurrent assets 6,791 16,644
-------------- -------------
-------------- -------------
Total Assets $ 839,675 $ 735,854
============== =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 110,802 $ 81,217
Accrued derivative liability 22,736 23,605
-------------- -------------
Total current liabilities 133,538 104,822
-------------- -------------
Noncurrent liabilities:
Long-term credit facility - 11,000
Convertible notes 99,767 99,696
Asset retirement obligation 27,835 25,485
Net profits interest bonus plan liability 20,175 6,163
Other noncurrent liabilities 6,873 7,088
Deferred income taxes 117,166 90,947
-------------- -------------
Total noncurrent liabilities 271,816 240,379
-------------- -------------
Commitments and contingencies
Temporary equity ( Note 11):
Common stock subject to put and call options, $0.01 par value; issued
and outstanding: -0- shares in 2004 and 3,380,818 shares in 2003 - 71,594
Note receivable from Flying J - (71,594)
-------------- -------------
Total temporary equity - -
-------------- -------------
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares;
issued: 28,552,284 shares in 2004 and 29,245,123 shares in 2003;
outstanding, net of treasury shares: 28,302,284 shares in 2004
and 28,242,423 shares in 2003 286 292
Additional paid-in capital 121,473 146,362
Treasury stock, at cost: 250,000 shares in 2004 and
1,002,700 shares in 2003 (5,295) (16,057)
Deferred stock-based compensation (5,337) -
Retained earnings 337,943 274,937
Accumulated other comprehensive loss (14,749) (14,881)
-------------- -------------
Total stockholders' equity 434,321 390,653
-------------- -------------
Total Liabilities and Stockholders' Equity $ 839,675 $ 735,854
============== =============
The accompanying notes are an integral part of
these consolidated financial statements.
-3-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per share amounts)
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
---------------------------- ---------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Operating revenues:
Oil and gas production $ 103,191 $ 86,414 $ 291,245 $ 278,236
Gain (loss) on sale of proved properties 738 (343) 2,514 (221)
Marketed gas revenue 3,798 3,911 11,095 11,019
Other oil and gas revenue 261 481 1,723 2,521
Other revenue 935 536 562 4,352
----------- ----------- ----------- -----------
Total operating revenues 108,923 90,999 307,139 295,907
----------- ----------- ----------- -----------
Operating expenses:
Oil and gas production 24,163 23,914 69,279 68,304
Depletion, depreciation, amortization
and abandonment liability accretion 21,470 20,765 62,769 61,251
Exploration 8,871 9,906 20,071 20,332
Impairment of proved properties - - 494 -
Abandonment and impairment of unproved properties 744 2,300 2,632 4,003
General and administrative 5,472 4,803 16,459 15,629
Change in net profits interest bonus plan liability 7,527 709 14,012 2,406
Marketed gas system operating expense 3,493 3,584 10,214 10,041
Other 680 707 2,242 1,202
----------- ----------- ----------- -----------
Total operating expenses 72,420 66,688 198,172 183,168
----------- ----------- ----------- -----------
Income from operations 36,503 24,311 108,967 112,739
Nonoperating income (expense):
Interest income 93 73 479 647
Interest expense (1,471) (1,833) (4,524) (6,416)
----------- ----------- ----------- -----------
Income before income taxes and cumulative
effect of change in accounting principle 35,125 22,551 104,922 106,970
Income tax expense (12,560) (8,765) (39,072) (41,505)
----------- ----------- ----------- -----------
Income before cumulative effect of change in accounting principle 22,565 13,786 65,850 65,465
=========== =========== =========== ===========
Cumulative effect of change in accounting
principle, net of income tax - - - 5,435
----------- ----------- ----------- -----------
Net Income $ 22,565 $ 13,786 $ 65,850 $ 70,900
=========== =========== =========== ===========
Basic weighted average common shares outstanding 28,545 31,529 28,982 31,126
Diluted weighted average common shares outstanding 33,186 35,828 33,486 35,426
Basic earnings per common share:
- --------------------------------
Income before cumulative effect of change in accounting principle $ 0.79 $ 0.44 $ 2.27 $ 2.11
Cumulative effect of change in accounting
principle, net of income tax - - - 0.17
----------- ----------- ----------- -----------
Basic net income per common share $ 0.79 $ 0.44 $ 2.27 $ 2.28
=========== =========== =========== ===========
Diluted earnings per common share:
- ----------------------------------
Income before cumulative effect of change in accounting principle $ 0.71 $ 0.41 $ 2.05 $ 1.93
Cumulative effect of change in accounting
principle, net of income tax - - - 0.15
----------- ----------- ----------- -----------
Diluted net income per common share $ 0.71 $ 0.41 $ 2.05 $ 2.08
=========== =========== =========== ===========
Cash dividends declared per common share $ 0.05 $ - $ 0.10 $ 0.05
=========== =========== =========== ===========
The accompanying notes are an integral part of
these consolidated financial statements.
-4-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
For the Nine Months Ended
September 30,
-------------------------------
2004 2003
-------------- -------------
Reconciliation of net income to net cash provided
by operating activities:
Net income $ 65,850 $ 70,900
Adjustments to reconcile net income to net
cash provided by operating activities:
(Gain) loss on sale of proved properties (2,514) 221
Depletion, depreciation, amortization
and abandonment liability accretion 62,769 61,251
Exploratory dry hole expense 2,530 7,497
Impairment of proved properties 494 -
Abandonment and impairment of unproved properties 2,632 4,003
Unrealized derivative gain (46) (358)
Change in net profits interest bonus plan liability 14,012 2,406
Amortization of deferred stock-based compensation 2,965 -
Income tax benefit from the exercise of stock options 3,002 781
Deferred income taxes 27,205 14,831
Other (3,498) (1,324)
Cumulative effect of change in accounting
principle, net of income tax - (5,435)
-------------- -------------
175,401 154,773
Changes in current assets and liabilities:
Accounts receivable (26,313) (23,346)
Prepaid expenses and other (2,953) 3,741
Accounts payable and accrued expenses 10,997 15,746
-------------- -------------
Net cash provided by operating activities 157,132 150,914
-------------- -------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 2,725 2,717
Capital expenditures (127,344) (81,218)
Acquisition of oil and gas properties, including related
$71,594 loan to Flying J in 2003 (6,588) (75,234)
Deposits to short-term investments available-for-sale (1,470) (1,029)
Receipts from short-term investments available-for-sale 12,500 950
Receipts from restricted cash 10,412 -
Other 712 166
-------------- -------------
Net cash used in investing activities (109,053) (153,648)
-------------- -------------
Cash flows from financing activities:
Proceeds from credit facility 97,497 120,011
Repayment of credit facility (108,500) (122,020)
Costs from issuance of convertible notes - (78)
Proceeds from sale of common stock for exercise of stock options 9,957 2,354
Repurchase of common stock (35,743) -
Dividends paid (1,429) (1,573)
-------------- -------------
Net cash used in financing activities (38,218) (1,306)
-------------- -------------
Net change in cash and cash equivalents 9,861 (4,040)
Cash and cash equivalents at beginning of period 14,827 11,154
-------------- -------------
Cash and cash equivalents at end of period $ 24,688 $ 7,114
============== =============
The accompanying notes are an integral part of
these consolidated financial statements.
-5-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Continued)
Supplemental schedule of additional cash flow information and noncash
investing and financing activities:
For the Nine Months Ended
September 30,
-------------------------------
2004 2003
-------------- -------------
(In thousands)
Cash paid for interest, including amounts capitalized $ 8,070 $ 7,245
Cash paid for income taxes $ 8,800 $ 23,208
In August 2004 the Company closed a transaction whereby it exchanged oil
and gas properties valued at $1.4 million together with $769,000 of cash
for oil and gas properties valued at $2.2 million.
In June 2004 the Company issued 232,861 restricted stock units pursuant to
the Company's restricted stock plan. The total value of the grant was $8.3
million. The Company has recorded compensation expense of $3.0 million for
the nine-month period ended September 30, 2004.
In January 2004 and May 2004 the Company issued 4,200 shares 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 of $341,000
for the nine-month period ended September 30, 2004.
In January 2003 the Company issued 7,200 shares of common stock from
treasury to its non-employee directors and recorded compensation expense of
$153,000.
In January 2003 the Company issued 3,380,818 restricted shares of common
stock to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
(collectively, "Flying J") and entered into a put and call option
agreement, valued at $995,000 for financial reporting purposes, with Flying
J with respect to those shares in connection with the acquisition of oil
and gas properties and related assets and liabilities.
The accompanying notes are an integral part of
these consolidated financial statements.
-6-
ST. MARY LAND & EXPLORATION COMPANY
AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS'
EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock Deferred Other Total
----------------- Paid-in --------------------- Stock-Based Retained Comprehensive Stockholders'
Shares Amount Capital Shares Amount Compensation Earnings Income (Loss) Equity
---------- ------ -------- ----------- --------- ------------- -------- ------------- -------------
Balances, December 31, 2002 28,983,110 $ 290 $140,688 (1,009,900) $(16,210) $ - $182,512 $ (7,767) $ 299,513
Comprehensive income:
Net income - - - - - - 95,575 - 95,575
Unrealized net gain on
marketable equity securities
available for sale - - - - - - - 716 716
Change in derivative instrument
fair value - - - - - - - (21,873) (21,873)
Reclassification to earnings - - - - - - - 13,846 13,846
Minimum pension liability
adjustment - - - - - - - 197 197
-------------
Total comprehensive income 88,461
-------------
Cash dividends, $ 0.10 per share - - - - - - (3,150) - (3,150)
Issuance of common stock under
Employee Stock Purchase Plan 16,994 - 375 - - - - - 375
Value of option right granted to
Flying J - - 995 - - - - - 995
Sale of common stock, including
income tax benefit of stock
option exercises 245,019 2 4,304 - - - - - 4,306
Directors' stock compensation - - - 7,200 153 - - - 153
---------- ------ -------- ----------- --------- ------------- -------- ------------- -------------
Balances, December 31, 2003 29,245,123 $ 292 $146,362 (1,002,700) $(16,057) $ - $274,937 $ (14,881) $ 390,653
---------- ------ -------- ----------- --------- ------------- -------- ------------- -------------
Comprehensive income:
Net income - - - - - - 65,850 - 65,850
Change in derivative instrument
fair value - - - - - - - (20,613) (20,613)
Reclassification to earnings - - - - - - - 20,745 20,745
-------------
Total comprehensive income 65,982
-------------
Cash dividends declared,
$ 0.10 per share - - - - - - (2,844) - (2,844)
Treasury stock purchases - - - (489,300) (16,336) - - - (16,336)
Retirement of treasury stock (1,229,400) (12) (26,737) 1,229,400 26,479 - - - -
Issuanceof common stock under
Employee Stock Purchase Plan 7,412 - 180 - - - - - 180
Repurchase of common stock from
Flying J - - (19,406) - - - - - (19,406)
Sale of common stock, including
income tax benefit of stock
option exercises 529,149 6 12,773 - - - - - 12,779
Deferred compensation related to
restricted stock unit awards - - 8,301 - - (8,301) - - -
Amortization of deffered stock-
based compensation - - - - - 2,964 - - 2,964
Directors' stock compensation - - - 12,600 349 - - - 349
---------- ------ -------- ----------- --------- ------------- -------- ------------- -------------
Balances, September 30, 2004 28,552,284 $ 286 $121,473 (250,000) $ (5,295) $ (5,337) $337,943 $ (14,749) $ 434,321
========== ====== ======== =========== ========= ============= ======== ============= =============
The accompanying notes are an integral part of
these consolidated financial statements.
-7-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
----------------------------
September 30, 2004
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
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, 2003. 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.
The significant accounting policies followed by the Company are
summarized in Note 1 to the Company's consolidated financial statements in the
Form 10-K for the year ended December 31, 2003. 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.
The Company records the estimated liability of future payments under
its Net Profits Interest Bonus Plan (the "Net Profits Plan") because it is a
vested employee benefit. The estimated liability is calculated based on a number
of assumptions, including oil and gas reserves, recurring and workover lease
operating expense, present value discount factors and certain pricing
assumptions. The estimates the Company uses in calculating the liability are
modified from period to period based on new information attributable to the
underlying assumptions. Changes in the estimated liability of future payments
associated with the Net Profits Plan are recorded as increases or decreases to
expense in the current period as a separate item in the consolidated statements
of operations. The estimated Net Profits Plan liability is recorded separately
as a noncurrent liability in the accompanying consolidated balance sheets.
The amounts due and payable under the Net Profits Plan as cash
compensation related to the current period operations are recognized as
compensation expense and are included within general and administrative expense
and exploration expense. This treatment provides for a consistent matching of
cash expense with net cash flows from the oil and gas properties in each
respective pool of the Net Profits Plan.
The non-cash portion of Net Profits Plan expense and the corresponding
liability have been reclassified as separate line items in the accompanying
financial statements for all periods presented. As a result, prior period
general and administrative expense, exploration expense and other non-current
liabilities have been reclassified to conform to the current presentation.
The stockholders approved the Restricted Stock Plan in the second
quarter of 2004. The Compensation Committee of the Board of Directors is
-8-
responsible for determining the grant criteria under the Restricted Stock Plan.
The Compensation Committee has approved the issuance of restricted stock units
under the Restricted Stock Plan. Criteria for determining grants under the plan
associated with the current year are established at the beginning of the
performance year. As a result, the Company applies variable plan accounting in
estimating compensation expense during the time from the beginning of the
performance year until a firm measurement date occurs and the grants are issued.
At the restricted stock unit issuance date, the Company is able to measure
compensation expense and applies fixed plan accounting to measure and record the
remaining expense attributable to grants under the plan.
Certain amounts in the 2003 unaudited consolidated financial statements
have been reclassified to correspond to the 2004 presentation. Other than the
Net Profits Plan liability and expense reclassification noted above, the most
significant reclassification is that wells in progress has been classified as a
separate line item in the consolidated balance sheets for all periods presented.
As a result, prior period unproved oil and gas properties, net of impairment
allowance, has been reclassified to conform to the current presentation.
Note 3 - 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 of common
shares outstanding during each period. During the first quarter of 2003, the
Company issued 3,380,818 shares of common stock as part of an acquisition. On
February 9, 2004, the Company repurchased these shares, and the shares were
retired (see Note 11-Repurchase of Common Stock). These shares were considered
outstanding from January 29, 2003 to February 9, 2004 for purposes of
calculating basic and diluted net income per common share and were weighted
accordingly in the calculation of common shares outstanding. The shares were
included in the temporary equity section of the consolidated balance sheet as of
December 31, 2003.
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 other 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 measurement, all unvested shares
attributable to the restricted stock unit grant are included in the diluted
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 794,455 and
673,807 anti-dilutive securities related to stock options for the three-month
and nine-month periods ended September 30, 2003, respectively, and 553,766
anti-dilutive securities related to stock options for the nine-month period
ended September 30, 2004. There were no anti-dilutive securities related to
stock options for the three-month period ended September 30, 2004. 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. A total of
3,846,153 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 nine-month periods ended September 30, 2004 and 2003. The
Convertible Notes were issued in March 2002.
-9-
The following table sets forth the calculation of basic and diluted
earnings per share (in thousands, except per share amounts):
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2004 2003 2004 2003
----------- ------------ ----------- -----------
Income before cumulative effect of change in $ 22,565 $ 13,786 $ 65,850 $ 65,465
accounting principle
Cumulative effect of change in accounting principle,
net of income tax - - - 5,435
----------- ------------ ----------- -----------
Net income $ 22,565 $ 13,786 $ 65,850 $ 70,900
----------- ------------ ----------- -----------
Adjustments to net income for dilution:
Add: Interest expense not incurred if
Convertible Notes converted 1,597 1,597 4,757 4,740
Less: Other adjustments (16) (16) (48) (47)
Less: Income tax effect of dilution items (565) (614) (1,754) (1,821)
----------- ------------ ----------- -----------
Net income adjusted for the effect of dilution $ 23,581 $ 14,753 $ 68,805 $ 73,722
=========== ============ =========== ===========
Basic weighted-average common shares
outstanding in period 28,545 31,529 28,982 31,126
Add: Dilutive effect of stock options 620 453 599 454
Add: Dilutive effect of unvested restricted
stock units 175 - 59 -
Add: Dilutive effect of Convertible Notes using
if-converted method 3,846 3,846 3,846 3,846
----------- ------------ ----------- -----------
Diluted weighted-average common shares
outstanding in period 33,186 35,828 33,486 35,426
=========== ============ =========== ===========
Basic earnings per common share:
Income before cumulative effect of change in
accounting principle $ 0.79 $ 0.44 $ 2.27 $ 2.11
Cumulative effect of change in accounting
principle - - - 0.17
----------- ------------ ----------- -----------
Total $ 0.79 $ 0.44 $ 2.27 $ 2.28
=========== ============ =========== ===========
Diluted earnings per common share:
Income before cumulative effect of change in
accounting principle $ 0.71 $ 0.41 $ 2.05 $ 1.93
Cumulative effect of change in accounting
principle - - - 0.15
----------- ------------ ----------- -----------
Total $ 0.71 $ 0.41 $ 2.05 $ 2.08
=========== ============ =========== ===========
-10-
Note 4 - Compensation Plans
In May 2004 the Restricted Stock Plan was approved by the stockholders,
establishing a long-term incentive program whereby grants of restricted stock or
restricted stock units 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. The total number of shares of the Company's
common stock reserved for issuance under the Restricted Stock Plan is 5,600,000.
This number is reduced to the extent that stock options are granted under the
Company's Option Plans.
St. Mary made grants of 232,861 restricted stock units (RSUs) on June
30, 2004. The total expense associated with these grants was $8.3 million as
measured on June 30, 2004. The total 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% immediately upon issuance
and 25% on each of the first three anniversary dates. The vested shares
underlying the RSU grants will be issued on the third anniversary of the grants,
at which time the shares carry no further restrictions. As of September 30,
2004, there were 170,450 unvested RSUs, which include the total of the 2004
grants less the vested portion of the grants and units forfeited due to employee
terminations prior to vesting. Compensation expense for the nine-month period
ended September 30, 2004 related to the 2004 grants totaled $2.6 million. In
addition, the Company has recorded $389,000 of compensation expense related to
the expected 25% immediate vesting of the estimated 2005 RSU grants.
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 related interpretations. No stock-based employee compensation expense for
stock options is reflected in net income as all options granted under the
Company's plans had an exercise price equal to the market value of the
underlying common stock on the date of grant. The following table illustrates
the effect on net income and earnings per share if the Company had applied the
fair value recognition provisions of Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation," to stock-based
employee compensation through stock options for the periods presented (in
thousands, except per share amounts).
-11-
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Net income -
As reported:
$ 22,565 $ 13,786 $ 65,850 $ 70,900
Add: Stock-based employee compensation expense
included in reported net income, net of
related tax effects 556 - 1,861 -
Less: Stock-based employee compensation
determined under fair value based method for
all expense, net of related income tax effects (1,421) (1,690) (4,471) (4,294)
----------- ----------- ------------ -----------
Pro forma net income $ 21,700 $ 12,096 $ 63,240 $ 66,606
Pro forma basic earnings per share:
Income before cumulative effect of change in
accounting principle $ 0.76 $ 0.38 $ 2.18 $ 1.97
Cumulative effect of change in accounting
principle - - - 0.17
----------- ----------- ------------ -----------
Total $ 0.76 $ 0.38 $ 2.18 $ 2.14
Pro forma diluted earnings per share:
Income before cumulative effect of change in
accounting principle $ 0.68 $ 0.36 $ 1.96 $ 1.81
Cumulative effect of change in accounting
principle - - - 0.15
----------- ------------ ------------ -----------
Total $ 0.68 $ 0.36 $ 1.96 $ 1.96
=========== ============ ============ ===========
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 has been measured at the date of grant using
the Black-Scholes option-pricing model. The fair value of options granted in the
three-month and nine-month periods ended September 30, 2004 and 2003 were
estimated using the following weighted-average assumptions.
-12-
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ----------- ---------- -----------
Risk free interest rate:
Stock options * 3.8% 3.6% 3.3%
Employee stock purchase plan ** ** 3.6% 3.4%
Dividend yield:
Stock options * 0.4% 0.3% 0.4%
Employee stock purchase plan ** ** 0.3% 0.4%
Volatility factor of the expected market
price of the Company's common stock:
Stock options * 49.4% 38.5% 48.7%
Employee stock purchase plan ** ** 22.8% 17.7%
Expected life of the options (in years):
Stock options * 7.7 7.6 6.7
Employee stock purchase plan ** ** 0.5 0.5
- -------------------------------
* No stock options were granted in the third quarter of fiscal year 2004.
** No shares were issued under the Employee Stock Purchase Plan in the third
quarter of fiscal years 2003 and 2004.
The Black-Scholes option-pricing model was developed for use in
estimating the fair value of traded options that have no vesting restrictions,
are fully transferable, and are not subject to trading restrictions or blackout
periods. In addition, option valuation models require the input of highly
subjective assumptions, including the expected stock price volatility. Since the
Company's employee 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 existing models do not necessarily provide a reliable single
measure of the fair value of St. Mary's employee stock options.
The Company has not adopted any of the early transition methods
provided for in SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure: an amendment of FASB Statement No. 123."
The FASB has issued a final exposure draft that would further amend SFAS No. 123
and require companies to recognize the fair value of stock options and other
stock-based compensation as expense for reporting periods beginning in July
2005. For awards issued prior to the effective date, the standard will require
companies to utilize prior valuation models of fair value and recognize as
expense the remaining unvested portion of the awards over the remaining vesting
periods.
Note 5 - Income Taxes
Income tax expense for the three-month and nine-month periods ended
September 30, 2004 and 2003 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 the composition of state income rates,
percentage depletion and other permanent differences. The effect of the change
in marginal state tax rates the Company recorded in the third quarter of 2004
was a result of filing 2003 income tax returns, evaluating the impact on future
-13-
temporary difference reversals, the effect of percentage depletion and
evaluating the effect of other permanent items.
For the three-month and nine-month periods ended September 30, 2004,
the Company's income tax expense totaled $12.6 million and $39.1 million,
respectively, compared to $8.8 million and $41.5 million, respectively, for the
three-month and nine-month periods ended September 30, 2003. The Company's
current portion of income tax expense for the three-month and nine-month periods
ended September 30, 2004, was $2.1 million and $15.5 million, respectively,
compared to $4.0 million and $25.9 million, respectively, for the three-month
and nine-month periods ended September 30, 2003. The Company's effective tax
rates for the three-month and nine-month periods ended September 30, 2004, were
35.8% and 37.2%, respectively, compared to 38.8% for both the three-month and
nine-month periods ended September 30, 2003.
In October 2004, the President signed the "American Jobs Creation Act
of 2004". This new law provides for sweeping restructuring of business taxes.
The Company is currently evaluating the impact that this new law will have on
St. Mary.
Note 6 - Long-term Debt
Revolving Credit Facility
The Company has a revolving credit facility with a group of banks. The
credit facility specifies a maximum loan amount of $300.0 million and has a
maturity date of January 27, 2006. Borrowings under the facility are secured by
a pledge of collateral that includes certain oil and gas properties and the
common stock of the material subsidiaries of the Company. The bank group
authorized a borrowing base of $325.0 million in October 2004 under its normal
semi-annual redetermination. The borrowing base redetermination process
considers the value of St. Mary's oil and gas properties, using specified bank
pricing criteria, and other assets as determined by the bank syndicate. Although
the borrowing base exceeds the maximum loan amount, the most that the Company
could borrow under the facility is limited to the maximum loan amount. The
Company elected an aggregate commitment amount of $150.0 million. The Company
must comply with certain financial and non-financial covenants. The Company is
in compliance with all of the covenants. Interest and commitment fees are
accrued based on the borrowing base utilization percentage table below.
Eurodollar 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%
- ------------------------------------------------------------------------------
Eurodollar loans 1.25% 1.50% 1.75% 2.00%
ABR loans 0.00% 0.25% 0.50% 0.75%
Commitment fee rate 0.30% 0.38% 0.38% 0.50%
The Company had no loans outstanding under its revolving credit agreement as of
September 30, 2004.
5.75% Senior Convertible Notes Due 2022
As of September 30, 2004, the Company 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% 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% for the three-month and nine-month periods ended September
30, 2004. Based on the trading price of the Convertible Notes at the most recent
-14-
determination period, the Company will be subject to the contingent interest
payments for the interest period from September 16, 2004 to March 15, 2005.
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. Of this amount, $71,000 was amortized through interest expense
for each of the nine-month periods ended September 30, 2004 and 2003. Interest
expense for each of the three-month periods ended September 30, 2004 and 2003
includes $24,000 of amortization. Derivative gain for the nine months ended
September 30, 2004 contains $57,000 of net gain from mark-to-market adjustments
for this derivative, and derivative gain for the nine months ended September 30,
2003 contains $247,000 of net gain from mark-to-market adjustments. Derivative
gain in the consolidated statements of operations for the three-month periods
ended September 30, 2004 and 2003 includes net gains of $151,000 and $261,000,
respectively, from mark-to-market adjustments for this derivative.
Interest Rate Derivative Contracts
On October 3, 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 receive a fixed interest rate of 5.75% 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 six-month LIBOR rate on
March 15, 2004 and September 15, 2004 was 1.16% and 2.06% respectively. The
Company received proceeds of $484,000 and $311,000 from the semi-annual
settlement of the swaps on March 15, 2004 and September 15, 2004 respectively.
The payment dates of the swaps match exactly with the interest payment dates of
the Convertible Notes. The fair value of the swaps was a liability of $163,000
as of September 30, 2004, and was a liability of $104,000 as of December 31,
2003. The swaps do not qualify for fair value hedge treatment under SFAS No. 133
and related pronouncements. During the nine-month period ended September 30,
2004, the Company received payments of $795,000 under the swap arrangements.
These payments have reduced the Company's interest expense. The Company recorded
a net derivative gain in the consolidated statements of operations of $732,000
for the three-month period ended September 30, 2004 and a net derivative loss of
$58,000 for the nine-month period ended September 30, 2004 from mark-to-market
adjustments for this derivative. The six-month LIBOR rate as of September 30,
2004 was 2.20%.
Weighted-average Interest Rate Paid
The weighted-average interest rates paid for the third quarters of 2004
and 2003 were 7.3% and 7.0%, respectively, including commitment fees paid on the
unused portion of the credit facility aggregate commitment, amortization of
deferred financing costs, and amortization of the contingent interest embedded
derivative associated with the convertible notes. The weighted-average interest
rates paid for the nine-month periods ended September 30, 2004 and 2003 were
7.1% and 6.3%, respectively. The impact of the commitment fees over a lower
average outstanding balance results in a higher weighted-average interest rate
despite lower LIBOR interest rates than in previous periods.
-15-
Note 7 - Oil and Gas Derivative Contracts
The Company recognized a net loss of $33.1 million from its oil and gas
derivative contracts for the nine months ended September 30, 2004, compared to a
net loss of $19.6 million for the same period in 2003. Comparative amounts for
the three-month periods ended September 30, 2004 and 2003 were a net loss of
$13.3 million and $4.5 million, respectively.
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 table below describes the volumes and
average contract prices of hedges currently in place, including contracts
entered into after September 30, 2004. 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 the oil contracts are indexed to
NYMEX.
Swaps Gas (per MMBtu) Oil (per Bbl)
- ----- --------------------------------- ----------------------------------
Weighted-Average Weighted-Average
Contract Contract Price Contract Price
Period Volumes (Regional Index) Volumes (NYMEX)
------------ ----------------- ------------- -----------------
2004
- ----
Quarter Ended:
December 31, 2004 3,087,500 $ 4.63 620,900 $ 28.37
------------ ----------------- ------------- -----------------
2005
- ----
Quarter Ended:
March 31, 2,297,800 7.16 242,452 40.19
June 30, 2,026,600 6.16 184,214 42.56
September 30, 1,605,000 6.24 188,980 41.61
December 31, 1,590,000 6.54 138,770 40.80
------------ ----------------- ------------- -----------------
Total 2005 7,519,400 6.56 754,416 41.24
------------ ----------------- ------------- -----------------
2006
- ----
Quarter Ended:
March 31, 720,000 6.49 103,366 38.93
June 30, 710,000 5.51 99,976 38.15
September 30, 690,000 5.49 100,372 37.47
December 31, 270,000 5.55 77,686 36.42
------------ ----------------- ------------- -----------------
Total 2006 2,390,000 5.80 381,400 37.83
------------ ----------------- ------------- -----------------
2007
- ----
Quarter Ended:
March 31, - - 63,410 35.63
June 30, - - 61,072 35.35
September 30, - - 62,684 35.10
December 31, - - 60,620 34.79
------------ ----------------- ------------- -----------------
Total 2007 - - 247,786 35.22
------------ ----------------- ------------- -----------------
All Contracts 12,996,900 $ 5.96 2,004,502 $ 35.86
============ ================= ============= =================
-16-
Collars Gas (per MMBtu)
- -------
-------------------------------------------
Weighted-AveragWeighted-Average
Contract Floor Ceiling
Period Price Price Volumes Index
------
2004
- ----
Quarter Ended:
December 31, 2004 $ 5.63 $ 6.85 150,000 IF ANR OK
-------------- -------------- ------------- --------------
2005
- ----
Quarter Ended:
March 31, 6.62 8.08 540,000 IF ANR OK
June 30, 5.73 7.20 540,000 IF ANR OK
September 30, 5.75 7.30 415,000 IF ANR OK
December 31, 6.00 7.63 390,000 IF ANR OK
-------------- -------------- ------------- --------------
Total 2005 6.05 7.57 1,885,000 IF ANR OK
-------------- -------------- ------------- --------------
All Contracts $ 6.01 $ 7.51 2,035,000 IF ANR OK
============== ============== ============= ==============
The Company seeks to minimize basis risk and indexes 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 6,009,600
IF Reliant N/S 3,330,000
IF PEPL 2,490,000
IF CIG N System 540,700
IF Henry Hub 506,600
IF HSC 120,000
--------------
Total 12,996,900
==============
Derivative gains and losses are recorded in other revenues in the
consolidated statements of operations. The following table summarizes oil and
gas derivative instrument gain (loss) activity for the periods presented (in
thousands):
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
------------------------------ --------------------------------
2004 2003 2004 2003
------------ -------------- -------------- --------------
Derivative contract settlements included in
oil and gas production revenues $ (13,323) $ (4,517) $ (33,056) $ (19,571)
Ineffective portion of hedges qualifying for
hedge accounting included in other
revenues 33 28 47 75
Non-qualified derivative contracts included
in other revenues 882 297 (1) 283
------------ -------------- -------------- --------------
Total $ (12,408) $ (4,192) $ (33,010) $ (19,213)
============ ============== ============== ==============
On September 30, 2004, St. Mary's remaining cash flow hedge positions
from oil and gas derivatives had an estimated net pre-tax liability of $23.8
-17-
million. The Company anticipates it will reclassify this amount to gains or
losses included in oil and gas production operating revenues as the hedged
production quantities are produced. Based on current prices, the net amount of
existing unrealized after-tax loss as of September 30, 2004, to be reclassified
from accumulated other comprehensive income to oil and gas production operating
revenues in the next twelve months would be $12.6 million, net of deferred
income taxes. The Company anticipates that all original forecasted transactions
will occur by the end of the originally specified time periods.
Note 8 - 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 requires 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", No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits", and
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
defined-benefit pension plan covering substantially all employees who meet age
and service requirements (the "Qualified Pension Plan"). The Company also has a
supplemental non-contributory pension plan covering certain management employees
(the "Nonqualified Pension Plan").
Components of Net Periodic Benefit Cost
The following table presents the components of the net periodic cost
for both the Qualified Pension Plan and the Nonqualified Pension Plan (in
thousands):
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
--------------------------------- ---------------------------------
2004 2003 2004 2003
--------------- -------------- --------------- --------------
Components of net periodic benefit cost:
Service cost $ 285 $ 241 $ 854 $ 722
Interest cost 122 107 367 321
Expected return on plan assets (74) (43) (221) (129)
Amortization of prior service cost (4) (6) (12) (19)
Amortization of net actuarial loss 55 82 163 247
--------------- -------------- --------------- --------------
Net periodic benefit cost $ 384 $ 381 $ 1,151 $ 1,142
=============== ============== =============== ==============
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% 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 $987,000 to the pension plans during the second
quarter of 2004. No further contributions are planned for the remainder of 2004.
-18-
Note 9 - Asset Retirement Obligations
Effective January 1, 2003, the Company adopted the provisions of SFAS
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
applies to legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or the normal
operation of a long-lived asset. SFAS No. 143 requires the Company to recognize
an estimated liability for costs associated with the abandonment of its oil and
gas properties.
As of January 1, 2003, the Company recognized the future cost to
abandon oil and gas properties over the estimated economic life of the oil and
gas properties in accordance with the provisions of SFAS No. 143. A liability
for the estimated fair value of an asset retirement obligation and a
corresponding increase to the carrying value of the related long-lived asset are
recorded at the time a well is completed or acquired. The 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 life of
the respective oil and gas properties. Prior to the adoption of SFAS No. 143 the
Company had recognized an abandonment liability for its offshore wells. These
offshore liabilities were reversed upon adoption of SFAS No. 143, and the
methodology described above was used to determine the liability associated with
abandoning all wells, including those offshore.
The estimated 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. 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.
Upon adoption of SFAS No. 143 on January 1, 2003, the Company recorded
a discounted liability of $21.4 million, reversed the existing offshore
abandonment liability of $9.1 million, increased property and equipment by $12.8
million, decreased accumulated Depreciation, Depletion and Amortization
("DD&A") by $8.3 million and recognized a one-time cumulative effect gain of
$5.4 million (net of deferred tax benefit of $3.4 million). The Company depletes
the amount added to 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.
As of September 30, 2004, the Company has excluded $45.5 million of
estimated salvage value from its DD&A calculation.
A reconciliation of the Company's liability for the three-month and
nine-month periods ended September 30, 2004, is as follows (in thousands):
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
---------------------------------- ---------------------------------
2004 2003 2004 2003
--------------- --------------- --------------- ---------------
Beginning asset retirement obligation $ 26,868 $ 24,603 $ 25,485 $ -
Liability from SFAS No. 143 adoption - - - 21,403
Liabilities incurred 612 522 1,280 3,415
Liabilities settled (137) (925) (364) (1,456)
Accretion expense 492 435 1,434 1,273
--------------- --------------- --------------- ---------------
Ending asset retirement obligation $ 27,835 $ 24,635 $ 27,835 $ 24,635
=============== =============== =============== ===============
-19-
Note 10 - Net Profits Interest Bonus 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% of all costs and expenses associated with that pool.
Thereafter, 10% of future cash flows generated by the pool are allocated among
the participants and distributed at least annually. The percentage of cash flows
from the pool to be allocated among the participants increases to 20% after the
Company has recovered 200% of the total costs and expenses for the pool,
including payments made under the Net Profits Plan at the 10% level.
The Company records the estimated 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
liability attributable to the Net Profits Plan. The amounts recorded as
compensation expense from the Net Profits Plan in the periods presented below
relate to those payments attributable to the respective periods' actual realized
results from oil and gas sales (in thousands):
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
----------------------------------- ----------------------------------
2004 2003 2004 2003
--------------- ---------------- ---------------- --------------
Beginning liability for Net Profits Plan $ 12,648 $ 2,544 $ 6,163 $ 846
Increase in liability 9,669 2,811 19,610 9,403
Reduction in liability for cash payments
made or accrued and recognized as
compensation expense under the Net
Profits Plan (2,142) (2,102) (5,598) (6,996)
--------------- ---------------- ---------------- --------------
Ending liability for Net Profits Plan $ 20,175 $ 3,253 $ 20,175 $ 3,253
=============== ================ ================ ==============
-20-
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 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 the adjustment of the liability is associated with the future net
cash flows from oil and gas properties in the respective pools rather than
current period 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 (in thousands):
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------------------- ----------------------------------
2004 2003 2004 2003
----------------- ----------------- --------------- ---------------
General and Administrative Expense $ 4,565 $ 732 $ 8,193 $ 2,070
Exploration Expense 2,962 (23) 5,819 336
----------------- ----------------- --------------- ---------------
Total $ 7,527 $ 709 $ 14,012 $ 2,406
================= ================= =============== ===============
Note 11 - Repurchase of Common Stock
Repurchase of Common Stock from Flying J
On February 9, 2004, the Company repurchased 3,380,818 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 the Company's acquisition of 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 balance and borrowings under its bank
credit facility.
-21-
The following table shows the unaudited pro forma effects on the
summarized consolidated balance sheet if the transactions had occurred on
December 31, 2003. The table assumes that the Company would have borrowed the
necessary cash payment from its existing credit facility (in thousands):
Unaudited
pro forma
December 31, Pro forma December 31,
2003 adjustments 2003
---------------------------------------------------------
Summarized Balance Sheet:
Current assets $ 107,923 $ 107,923
Property and equipment, net 611,287 611,287
Other noncurrent assets 16,644 16,644
------------------ -----------------
Total Assets $ 735,854 $ 735,854
================== =================
Current liabilities $ 104,822 $ 104,822
Debt, including senior debt 110,696 $ 19,406 130,102
Other noncurrent liabilities,
including minority interest 129,683 129,683
------------------ -----------------
Total Liabilities 345,201 364,607
Restricted common stock held by Flying J 71,594 $ (71,594) -
Note receivable from Flying J (71,594) $ 71,594 -
------------------ -----------------
Total Temporary Equity - -
------------------ -----------------
Total Equity 390,653 $ (19,406) 371,247
------------------ -----------------
Total Liabilities and Stockholders' Equity $ 735,854 $ 735,854
================== =================
Selected Share Information:
Total common shares outstanding, net of
treasury shares, including restricted shares 31,623 (3,381) 28,242
================== =================
Stock Repurchase Program
In August 1998, the Company's Board of Directors approved a stock
repurchase program whereby 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 the Company's
existing bank credit facility agreement and compliance with securities laws. The
stock repurchase program may be suspended or discontinued at any time. In August
2004 the Company's Board of Directors approved an increase in the number of
shares that may be repurchased under the program to 3,000,000 as of the
effective date of the resolution. During the third quarter of 2004 the Company
repurchased a total of 489,300 shares of its common stock under the program at a
weighted average price of $33.39 per share. As of September 30, 2004, the
Company has Board authorization to repurchase the remaining 2,510,700 shares. On
September 30, 2004, the Company retired from treasury the 489,300 recently
repurchased shares together with 740,100 shares repurchased in prior years. The
retirement resulted in a reduction of 1,229,400 shares issued, $26.7 million in
treasury stock, $12,000 in common stock, and $26.7 million in additional paid-in
capital.
Note 12 - Subsequent Events
Subsequent to September 30, 2004, the Company signed agreements to
acquire, for cash, a total of approximately $97.5 million of oil and gas
properties in three separate transactions. Payment for the properties will be
made from cash on hand and funds available under St. Mary's existing credit
facility. It is expected that $60.4 million of the acquisitions will close in
the fourth quarter of 2004 and that the remaining $37.1 million will close in
-22-
early January 2005. Closing of these acquisitions is subject to the completion
of customary due diligence. Two of the acquisitions will be corporate
acquisitions that will require the Company to record a deferred income tax
liability that reflects a carry over tax basis which is lower than the recorded
cost for financial reporting purposes.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 the sale of produced natural gas at the wellhead and
the sale of produced crude oil. Our oil and gas reserves and operations are
concentrated in the Anadarko, Arkoma, Permian and various Rocky Mountain basins
and in the onshore Gulf Coast and offshore Gulf of Mexico area. We maintain a
balanced portfolio of proved reserves, development drilling opportunities and
non-conventional gas prospects.
This report contains forward-looking statements. You should review our
cautionary note about forward-looking statements at the end of this section.
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. We continued to benefit from record-high oil and gas prices
through the first nine months of 2004.
Third Quarter 2004 Highlights
We announced two events subsequent to the end of the quarter. In
October we executed three separate agreements to acquire a total of $97.5
million of oil and gas properties. Please see our outlook for the remainder of
2004 below. In its November 1, 2004 issue Forbes magazine has listed us as the
number 9 company on its 2004 list of 200 Best Small Companies. Forbes has
indicated that to qualify for this list, candidate companies must indicate a
consistent pattern of positive growth based on various growth and earnings
criteria of Forbes over a five-year period and for the last 12 months evaluated.
Those criteria are closely aligned to our long-standing objective of growing
shareholder value over a long period of time.
Gas prices have remained at historic high levels due to supply and
transportation constraints resulting from the continuing maturity of
gas-producing basins in North America, from lost production associated with
Hurricane Ivan, and from continuing strong demand for natural gas in domestic
markets. Oil prices have reached all-time highs on the spot markets reflecting
worldwide concerns about producer ability to ensure sufficient supply to meet
increasing demand. OPEC announcements regarding increasing production have not
reduced the impact of a weaker US dollar nor quelled fears caused by
weather-related destruction of facilities, Middle East and North African
political instability, uncertainty associated with Russian oil exports, the oil
rig workers' strike in Norway and crude oil refining constraints in the United
States. NYMEX prices for the third quarter of 2004 averaged $5.84 per MMBtu and
$43.88 per barrel, an increase of 14 percent for gas and 45 percent for oil
compared to the third quarter of 2003.
-23-
Net income for the quarter ended September 30, 2004, was $22.6 million
or $0.71 per diluted share compared to the 2003 results of $13.8 million or
$0.41 per diluted share. Per share results reflect a decline in basic weighted
average shares outstanding resulting from the repurchase of 3.4 million shares
from Flying J in early February 2004 and the repurchase under our stock
repurchase program of a total of 489,300 shares in the third quarter of 2004.
Offsetting these decreases was the exercise of approximately 529,000 shares of
employee stock options in the nine months ended September 30, 2004. Production
decreased one percent to 19.0 BCFE on a comparative three-month basis due to
natural declines in existing production that have not been completely offset by
new production. Compared to the same period a year earlier, our average realized
price increased 21 percent to $5.43 per MCFE. Unit costs increased between
comparative periods as operating expense increased $0.02 to $1.27 per MCFE due
to increased production taxes caused by higher revenues. We experienced a per
MCFE general decrease in both recurring LOE and workover expense between the
quarters. We expect year-to-date comparisons for lease operating expense to be
similar to the nine months ended comparisons. DD&A (including impairments)
increased $0.05 to $1.13 per MCFE as a result of overall higher finding costs.
We re-initiated our stock repurchase program in August 2004. Since that
time we have repurchased a total of 489,300 shares of our common stock at an
average cost of $33.39 per share. These repurchases were funded from available
cash. As of October 29, 2004, we have 2,510,700 shares remaining that may be
repurchased under the program.
First Nine Months 2004 Highlights
NYMEX prices for the first nine months of 2004 averaged $5.83 per MMBtu
and $39.11 per barrel, an increase of two percent for gas and 26 percent for oil
compared to the same period in 2003. As of September 30, 2004, the NYMEX strip
for the remainder of the year was $50.66 per barrel for oil and $6.63 per MMBtu
for gas. The NYMEX strip for 2005 was $45.24 per barrel for oil and $6.89 per
MMBtu for gas.
Net income for the nine months ended September 30, 2004, was $65.9
million or $2.05 per diluted share compared to the 2003 results of $65.5 million
or $1.93 per diluted share before the cumulative effect of change in accounting
principle of an additional $5.4 million or $0.15 per diluted share of income.
Production decreased 4 percent to 55.5 BCFE on a comparative nine-month basis
due to the natural decline in existing production and delays in bringing new
wells on-line. Compared to the same period a year earlier, our average realized
price increased nine percent to $5.25 per MCFE. Lease operating expense unit
costs (including taxes) increased $0.08 to $1.26 per MCFE primarily due to
increased production taxes due to higher sales prices and additions of higher
cost properties in our Rocky Mountain region. General and administrative expense
increased $0.03 to $0.30 per MCFE due to a 5% increase in actual general and
administrative cost coupled with the 4% decrease in production volumes. DD&A
unit costs (including impairments) increased $0.07 to $1.13 per MCFE as a result
of higher per unit cost additions.
Except for our Gulf Coast region, we are seeing a general industry
trend of drilling rig shortages in our core areas. These shortages and the
increase in steel costs have created an environment of steadily increasing costs
for exploration and development drilling. We now anticipate that the cost to
drill and complete a well will be approximately 20 percent higher than we
budgeted at the beginning of the year in these areas. The cost increases have
been included in our capital expenditures budget. In our Gulf Coast region
drilling rigs are still available and we are not experiencing cost increases.
We determined that the expense adjustment related to the estimated
future net profits interest bonus plan liability should be presented separately
from general and administrative and exploration expense because this liability
is calculated based on the estimated net cash flows not yet realized from the
future production of oil and gas and as such are not current expenses like
general and administrative or exploration expense. This reclassification has the
effect of reducing previously reported general and administrative expense and
-24-
exploration expense to include only those amounts that relate to realized
periodic oil and gas production. The analyses throughout this report reflect
this change for all periods presented. For the quarter ended September 30, 2004,
the expense related to the change in the estimated liability for this plan
increased to $7.5 million from $709,000 for the comparable quarter of 2003. The
expense for the nine months ended September 30, 2004, increased to $14.0 million
compared to $2.4 million in 2003. These increases are due to the performance of
individual pools, the effect of a higher price environment, and the application
of lower discount rates.
Net cash provided by operating activities was $157.1 million, up 4
percent from the $150.9 million provided in 2003. This positive cash flow trend
is expected to continue as prices remain relatively higher and we continue to
control our operating costs.
In May 2004 our stockholders approved the restricted stock plan, and we
issued 232,861 restricted stock units on June 30, 2004. These grants vest 25%
immediately and 25% on each of the first three anniversary dates. The shares of
our common stock underlying the restricted stock units will be issued, and all
restrictions will lapse on June 30, 2007. We have recorded $3.0 million of
compensation expense through September 2004. The remaining expense of $5.3
million is recorded in deferred stock-based compensation and will be recognized
over the remaining vesting periods.
On February 9, 2004, we repurchased 3,380,818 shares of our common
stock from Flying J for a total of $91.0 million. We originally issued these
shares to Flying J on January 29, 2003, in connection with our acquisition of
oil and gas properties. We also loaned Flying J $71.6 million in connection with
the property acquisition. Flying J used the proceeds from the share repurchase
to repay the outstanding loan balance. Accrued interest, which we had not been
recording due to the non-recourse nature of the note, was forgiven as part of
the transaction. The net $19.4 million difference was funded from our available
cash and from borrowings under our bank credit facility. The amount funded from
borrowings under our bank credit facility was repaid during the second quarter.
Including shares purchased under our share repurchase program, net expenditures
for repurchased shares of common stock through September 30, 2004, are $35.7
million.
Outlook for the Remainder of 2004
Over the remainder of 2004, we will continue to execute our business
plan, which includes:
o Capital expenditures budget revised to a total of $292 million. Of this
amount, $225 million is allocated to exploration and development
drilling with the remainder allocated to acquisitions. The revised
exploration and development drilling portion includes adjustments for
both general cost increases we are experiencing and our participation
in the drilling of additional wells. A table of budgeted amounts by
core area is detailed under the caption Capital Expenditure Budget.
Through September 2004 we have closed $6.6 million of acquisitions. We
announced in October that we have executed separate agreements to
acquire, in three separate transactions, a total of $97.5 million of
oil and gas properties for cash. We are scheduled to close two of the
transactions in the fourth quarter totaling $60.4 million. The
remaining $37.1 million acquisition is scheduled to close on
January 5, 2005. Closing of these acquisitions is subject to the
completion of customary due diligence. We anticipate funding these
acquisitions with cash on hand and funds available under our existing
credit facility.
o We expect the third quarter production increase to continue into the
fourth quarter. We attribute our estimate of future production to
improved drilling results from expected completion activity for the
rest of 2004 supplemented slightly by our recently announced
acquisitions.
-25-
o Our Hanging Woman Basin coalbed methane project is slightly behind our
original schedule. We previously planned to complete 108 wells in
Wyoming in 2004. However, permitting on Federal land has been slower
than expected. We anticipate that these permits will be issued in the
spring of 2005. We anticipate that 27 Federal well permits will be
approved in November bringing the total number of completed wells to 69
at year-end, 37 of which have been drilled as of October 20, 2004. Of
the originally scheduled 108 wells, 19 wells have been combined with
deeper zones using multi-seam completions to provide operational
enhancements. The high-pressure pipeline to connect these wells to the
main trunk line is currently under construction and is on schedule to
be completed by December 1, 2004. Although we may have some moderate
production in December 2004, we expect more meaningful volumes of
natural gas to begin producing in 2005.
-26-
A Quarter and Nine-Month Overview of Selected Reserve, Production and Financial
Information, Including Trends:
Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
- --------------------------------------------------------------------------
Three Months Ended % of Nine Months Ended % of
September 30, Change September 30, Change
------------------------ Between ---------------------------- Between
2004 2003 Periods 2004 2003 Periods
----------- --------- ------- ------------ ------------ -------
Net Production Volumes
- ----------------------
Natural Gas (Mcf) 11,531 12,378 34,214 37,696
Oil (Bbl) 1,245 1,147 3,547 3,352
MCFE 19,000 19,262 (1)% 55,494 57,808 (4)%
Average Daily Production
- ------------------------
Natural Gas (Mcf per day) 125 135 125 138
Oil (Bbls per day) 14 13 13 12
MCFE per day (6:1) 207 209 (1)% 203 212 (4)%
Oil & Gas Production Revenues
- ---------------------------------
Gas Production $ 61,031 $ 56,134 $ 181,172 $ 187,715
Oil Production 42,160 30,280 110,073 90,521
----------- --------- ------------ ------------
Total $ 103,191 $ 86,414 19% $ 291,245 $ 278,236 5%
=========== ========= ============ ============
Oil & Gas Production Costs
- ------------------------------
Lease Operating Expenses $ 14,663 $ 16,282 $ 45,291 $ 45,302
Transportation Costs 2,022 1,751 5,388 5,082
Production Taxes 7,478 5,881 18,600 17,920
----------- --------- ------------ ------------
Total $ 24,163 $ 23,914 1% $ 69,279 $ 68,304 1%
=========== ========= ============ ============
Average Realized Price, net of hedging
- --------------------------------------
Natural Gas (Per Mcf) $ 5.29 $ 4.53 17% $ 5.30 $ 4.98 6%
Oil (Per Bbl) $ 33.87 $ 26.39 28% $ 31.04 $ 27.01 15%
Per MCFE Data:
- --------------
Average Realized Price, net of hedging $ 5.43 $ 4.49 21% $ 5.25 $ 4.81 9%
Lease Operating Expense (0.77) (0.85) (9)% (0.82) (0.78) 5%
Transportation Costs (0.11) (0.09) 22% (0.10) (0.09) 11%
Production Taxes (0.39) (0.31) 26% (0.34) (0.31) 10%
General and Administrative (0.29) (0.25) 16% (0. 30) (0.27) 11%
----------- --------- ------------ ------------
Operating Profit $ 3.87 $ 2.99 30% $ 3.69 $ 3.36 10%
=========== ========= ============ ============
Depletion, Depreciation and Amortization $ 1.13 $ 1.08 5% $ 1.13 $ 1.06 7%
Financial Information (In Thousands, Except Per Share Amounts):
% of
Change
Between
September 30, 2004 December 31, 2003 Periods
--------------------- ------------------- -------
Working Capital $ 2,362 $ 3,101 (8)%
Long-Term Debt $ 99,767 $ 110,696 (10)%
Stockholders' Equity $ 434,321 $ 390,653 11%
-27-
For the Three Months % of For the Nine Months % of
Ended September 30, Change Ended September 30, Change
------------------------- Between ---------------------------- Between
2004 2003 Periods 2004 2003 Periods
----------- ---------- ------- ------------ ------------ -------
Basic Net Income Per Common Share $ 0.79 $ 0.44 80% $ 2.27 $ 2.28 -%
Diluted Net Income Per Common Share $ 0.71 $ 0.41 78% $ 2.05 $ 2.08 -%
Basic Weighted-Average Shares Outstanding 28,545 31,529 (9)% 28,982 31,126 (7)%
Diluted Weighted-Average Shares Outstanding 33,186 35,828 (7)% 33,486 35,426 (5)%
Net Cash Provided By Operating Activities $ 157,132 $ 150,914 4%
Net Cash Used In Investing Activities $ (109,053) $ (153,648) (29)%
Net Cash Used In Financing Activities $ (38,218) $ (1,306) (2,826)%
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.
For the remainder of this year we expect oil and gas production costs
will increase compared to prior year amounts. Production taxes will be higher as
a percentage of revenue in the remainder of 2004 as a result of the increase in
pricing we are experiencing and the timing of the Oklahoma incentive tax credit
we recorded in the fourth quarter of 2003. Depreciation, depletion and
amortization will likely increase due to the higher costs associated with
finding and acquiring crude oil and natural gas. We expect general and
administrative expense per MCFE for all of 2004 will also remain fairly
consistent relative to the first nine months of 2004.
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 continue to 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, debt financing and access to the capital markets.
Our Current Credit Facility.
The calculated borrowing base for our credit facility was increased to
$325.0 million in October 2004 following a normal semi-annual borrowing base
review. This determination was based on our June 2004 internal estimate of oil
and gas reserves using bank specified pricing. We have elected a commitment
amount of $150.0 million under this facility, which results in lower commitment
fees payable to the bank syndicate. We believe this commitment level is adequate
for our near-term liquidity requirements. We must comply with certain financial
and non-financial covenants, and we are in compliance with all of these
covenants. Interest and commitment fees are accrued based on the borrowing base
utilization percentage. LIBOR-based borrowings accrue interest at LIBOR plus the
applicable margin from the utilization table, and Alternate Base Rate borrowings
accrue interest at prime plus the applicable margin from the utilization table
located in Note 6 of Part I, Item 1 of this report. Commitment fees are accrued
-28-
on the unused portion of the aggregate commitment amount and are included in
interest expense in the consolidated statements of operations. We did not have
an outstanding balance on September 30, 2004. Please see Note 6 in Part I, Item
1 of this report.
We decreased our net borrowings by $11.0 million in the first nine
months of 2004 through cash flow from operations. Our weighted-average interest
rate paid in 2004 has been 7.1 percent and includes commitment fees paid on the
unused portion of the credit facility borrowing base, amortization of deferred
financing costs, and amortization of the contingent interest embedded derivative
associated with the convertible notes.
Interest Rate 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. On October 3, 2003, we executed interest rate swaps on a total
notional amount of $50.0 million of the convertible notes. The sensitivity
analysis discussed below presents the hypothetical change in fair value of those
financial instruments we held at September 30, 2004, that are sensitive to
changes in interest rates. 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. Giving consideration to the interest
rate swaps, we had floating-rate debt of $50.0 million and had $50.0 million of
fixed-rate debt at September 30, 2004. 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 $125,000 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.
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 and
stockholder dividends. In the first nine months of 2004 we spent $133.9 million
on capital development and a net $35.7 million to acquire shares of our common
stock using cash flows from operations and debt financing. We decreased
outstanding borrowings on our credit facility by $11.0 million, and we made net
cash payments of $14.8 million for income taxes and $1.4 million for dividends.
The following table presents amounts and percentage changes between the
nine-month periods ended September 30, 2004 and 2003 for our operating,
investing and financing activities. 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.
Amount of Change Percent Change
2004/2003 Between Periods
----------------------- ------------------------ ----------------------- ------------------------
Net cash provided by operating activities $ 6,218 4%
Net cash used in investing activities $ 44,595 (29)%
Net cash used in financing activities $ (36,912) (2,826)%
-29-
Analysis of cash flow changes between the nine months ended September 30, 2004
and 2003.
Operating Activities. Sources of cash flow from oil and gas sales
increased by $10.0 million from the period ended September 30, 2003 to the
period ended September 30, 2004. This was a result of price increases that
offset a net production decrease between the comparative periods. Cash
expenditures for operating expenses, exploration expenses and general and
administrative expenses decreased by $6.3 million between the two periods and
were partially offset by a $3.8 million dollar decrease in cash received from
other revenue items. Prepaid expenses and other also increased for the 2004
period, but decreased during the respective period of 2003 resulting in a $6.2
million negative impact to cash flows from operating activities and resulted in
that amount of offset to the positive increases.
Investing Activities. The decrease in net cash used resulted from lower
acquisition activity in 2004, noting that the Flying J acquisition occurred in
the first quarter of 2003. This decrease is offset by the $46.1 million increase
in drilling expenditures in 2004 over 2003. Total 2004 capital expenditures,
including acquisitions of oil and gas properties, decreased $22.5 million or 14
percent to $133.9 million compared to $156.5 million in 2003. An additional
$21.5 million of the decrease relates to expiration of the restriction period
for funds held for tax-deferred exchange of oil and gas properties and net
receipts from short-term investments.
Financing Activities. The $36.9 million increase in cash used in
financing activities reflects the net $19.4 million we paid to repurchase our
shares from Flying J on February 9, 2004, $16.3 million paid to repurchase
shares under our share repurchase plan, and payments against our credit
facility. In 2003 we borrowed to fund our acquisition of properties from Flying
J. In 2004 we have paid $11.0 million and reduced our credit facility
outstanding balance to zero. In 2004 we also received $7.6 million more of
proceeds from stock option exercises as compared to 2003.
St. Mary had $24.7 million in cash and cash equivalents and had working
capital of $2.4 million as of September 30, 2004, compared to $14.8 million in
cash and cash equivalents and working capital of $3.1 million as of December 31,
2003.
Capital Expenditure Budget
Expenditures for exploration and development of oil and gas properties
and acquisitions are the primary use of our capital resources. We now anticipate
spending approximately $225 million for exploration and development expenditures
in 2004. In October 2004 we executed separate agreements to acquire a total of
approximately $97.5 million of oil and gas properties for cash. Of this amount,
$60.4 million is expected to close in the fourth quarter of 2004 and $37.1
million is expected to close in January 2005. 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.
In millions Gross well count
----------- ----------------
o Mid-Continent region $ 96.0 129
o Rocky Mountain region 59.7 92
o ArkLaTex region 27.2 56
o Gulf Coast region 25.8 12
o Coal Bed Methane 11.8 95
o Permian Basin region 4.9 19
--------
$ 225.4
========
-30-
We regularly review our capital expenditure budget to reflect changes
in current and projected cash flow, acquisition opportunities, debt requirements
and other factors. The above allocations are subject to change based on various
factors and results.
The following table sets forth certain information regarding the costs
incurred by us in our oil and gas activities during the periods indicated.
Nine Months Ended September 30,
------------------------------------------------------
2004 2003
------------------------- -------------------------
(In thousands)
Development costs $ 118,508 $ 78,155
Exploration costs 29,037 26,416
Acquisitions:
Proved 8,026 75,844
Unproved 6,951 5,476
------------------------- -------------------------
Total including asset retirement obligation $ 162,522 $ 185,891
========================= =========================
We are proceeding with the development of coalbed methane reserves in
our Hanging Woman Basin project. We have 155,000 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 47,000 net acres in Montana relating to this project. See Legal
Proceedings under Part II, Item 1 of this report.
We believe that internally generated cash flow and our credit facility
will be utilized to fund our capital expenditures budget in 2004 and for
identified acquisitions expected to close in 2004 and 2005. 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 are considering. Also, the impact of oil and gas
prices on investment opportunities, the availability of capital and borrowing
capability, and the success of our development and exploratory activity could
lead to funding requirements for further development.
Financing Alternatives
We continue to see that the debt and equity financing capital markets
remain very attractive to energy companies who 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 current cash balance and debt availability are significant, we are not
currently considering accessing the capital markets in 2004. However, 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
as well as expanding our borrowing availability under traditional secured bank
financing.
Sensitivity Analysis
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, 2003.
-31-
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 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 are also hedging a small percentage of
our forecasted production on a discretionary basis.
Note 7 of the Notes to Consolidated Financial Statements (Unaudited)
contained in 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
October 29, 2004, and Note 7 is incorporated herein by reference. We anticipate
that all hedge transactions will occur as expected.
For contracts in place on September 30, 2004, a hypothetical change of
10 percent in future gas strip prices representing a $0.65 increase per MMBtu
applied to a notional amount of 3.9 million MMBtu covered by natural gas swaps
and 955,000 MMBtu covered by natural gas collars would cause a change in hedge
gain or loss included in gas revenue of $1.7 million in 2004 and $849,000 in
2005. A hypothetical change of 10 percent in the future NYMEX strip oil prices
representing a $4.43 increase per Bbl applied to a notional amount of 1.6 MMBbl
covered by crude oil swaps would cause a change in hedge gain or loss included
in oil revenue of $2.9 million in 2004, $2.3 million in 2005, $1.1 million in
2006, and $923,000 in 2007. Oil and gas derivatives tend to make our earnings
less sensitive to movements in commodity price and were factored into this
analysis of sensitivity.
Summary of Interest Rate Hedges in Place
We entered into fixed-to-floating interest rate swaps on $50.0 million
of convertible notes on October 3, 2003. We attempt to maintain a balanced
allocation between fixed and floating rate debt. As our usage of the credit
facility at that time was nearing zero, we elected to exchange fixed rate
payments for floating rate payments on a portion of the interest on our
convertible notes. This hedge does not qualify for fair value hedge treatment
under Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities." Excluding accrued payments due
to us at September 30, 2004, the interest rate swaps had a fair value liability
of $163,000. Derivative loss in the consolidated statements of operations for
the nine months ended September 30, 2004, includes $58,000 of loss related to
the fair value liability increase. We anticipate that interest expense in the
fourth quarter of 2004 will increase relative to the first three quarters as we
access our credit facility to close acquisitions.
-32-
Schedule of Contractual Obligations
The following table summarizes our future estimated debt payments and
minimum lease payments for the periods specified (in millions):
Less than More than 5
Contractual Obligations 1 year 1-3 years 3-5 years years Total
- -------------------------------------- ---------- ----------- ----------- ------------ ----------
Long-Term Debt Principal and Interest $ 6.3 $ 109.4 $ - $ - $ 115.7
Operating Leases 2.8 3.0 2.2 3.0 11.0
Other Long-Term Liabilities - 2.7 0.2 0.6 3.5
---------- ----------- ----------- ------------ ----------
Total $ 9.1 $ 115.1 $ 2.4 $ 3.6 $ 130.2
========== =========== =========== ============ ==========
This table excludes the unfunded portion of our estimated pension
liability of $2.4 million as we cannot determine with accuracy the timing of
future payments. The table also excludes estimated payments associated with our
net profits interest bonus plan. Although we record a liability for the
estimated future payments, we are not able to precisely predict the timing of
these amounts. We have excluded asset retirement obligations for the same
reason. Pension liabilities and asset retirement obligations are discussed in
Note 8 and Note 9, respectively, of Part IV, Item 15 of our Annual Report on
Form 10-K for the year ended December 31, 2003, and also in Part I, Item 1 of
this Quarterly Report on Form 10-Q.
Three leases for office space will expire in year 3, and a fourth
office space lease will expire in year 4. 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 $100.0 million. However, our common shares outstanding would
increase by 3,846,150 shares.
Our projected requirements for cash to pay interest and dividends for
the remainder of 2004 are $112,000 and $1.4 million, respectively. We anticipate
making cash payments for income taxes, dependent on net income and capital
spending.
Off-Balance Sheet Arrangements
Aside from operating leases we do not have any off-balance sheet
financing nor do we have any unconsolidated subsidiaries.
Critical Accounting Policies and Estimates
We refer you to the corresponding section of our Annual Report on Form
10-K for the year ended December 31, 2003.
-33-
Additional Comparative Data in Tabular Form:
Change Between the Change Between the
Three Months Ended Nine Months Ended
September 30, 2004 September 30, 2004
Oil and Gas Production Revenues and 2003 and 2003
- ------------------------------- ----------------------- --------------------------
Increase in oil and gas production revenues (in thousands) $ 16,777 $ 13,009
Components of Revenue Increases (Decreases):
Natural Gas
Realized price change per Mcf $ 0.76 $ 0.32
Realized price change percentage 17% 6%
Production change (MMcf) (847) (3,482)
Production change percentage (7)% (9)%
Oil
Realized price change per Bbl $ 7.48 $ 4.03
Realized price change percentage 28% 15%
Production change (MBbl) 98 195
Production change percentage 9% 6%
Our product mix as a percentage of total oil and gas revenue and production:
Three Months Ended September 30, Nine Months Ended September 30,
------------------------------------- -------------------------------------
Revenue 2004 2003 2004 2003
- ------- ----------------- ---------------- ----------------- ----------------
Natural Gas 59% 65% 62% 67%
Oil 41% 35% 38% 33%
Production
Natural Gas 61% 64% 62% 65%
Oil 39% 36% 38% 35%
Information regarding the effects of oil and gas hedging activity:
Three Months Ended September 30, Nine Months Ended September 30,
---------------------------------------- -------------------------------------
Natural Gas Hedging 2004 2003 2004 2003
- ------------------- ------------------ ------------------ ------------------ ---------------
Percentage of gas production hedged 24% 44% 25% 38%
Natural gas MMBtu hedged 3.0 million 6.0 million 9.6 million 15.7 million
Decrease in gas revenue ($3.4 million) ($1.9 million) ($10.5 million) ($11.8 million)
Average realized gas price per Mcf
before hedging $ 5.59 $ 4.69 $ 5.61 $ 5.29
Average realized gas price per Mcf
after hedging $ 5.29 $ 4.53 $ 5.30 $ 4.98
Oil Hedging
- -----------
Percentage of oil production hedged 43% 55% 43% 57%
Oil volumes hedged (MBbl) 530 636 1,512 1,898
Decrease in oil revenue ($9.9 million) ($2.6 million) ($22.5 million) ($7.8 million)
Average realized oil price per Bbl
before hedging $ 41.84 $ 28.66 $ 37.40 $ 29.33
Average realized oil price per Bbl
after hedging $ 33.87 $ 26.39 $ 31.04 $ 27.01
-34-
Information regarding the components of exploration expense:
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------- -------------------------------
Summary of Exploration Expense (in millions) 2004 2003 2004 2003
- -------------------------------------------- -------------- -------------- ------------- --------------
Geological and geophysical expenses $ 3.2 $ 0.7 $ 5.3 $ 4.4
Exploratory dry holes 1.3 6.4 2.5 7.5
Overhead and other expenses 4.4 2.8 12.3 8.4
-------------- -------------- ------------- --------------
$ 8.9 $ 9.9 $ 20.1 $ 20.3
============== ============== ============= ==============
Comparison of Financial Results and Trends between the Quarters ended
September 30, 2004 and 2003
Oil and gas production revenues. Average net daily production decreased
one percent to 206.5 MMCFE for the quarter ended September 30, 2004 compared
with 209.4 MMCFE for the quarter ended September 30, 2003. Wells completed in
2003 and 2004 combined with wells from acquisitions in 2003 and 2004 have added
revenue of $21.2 million and average net daily production of 27.1 MMCFE in 2004
compared to 2003. These increases are offset by natural declines in production
from older properties and 3.8 MMCFE per day of 2003 production from properties
that were sold in 2003.
Oil and gas production expenses. Total production costs were relatively
flat between the quarters. Wells completed in 2003 and 2004 combined with wells
from acquisitions in 2003 and 2004 added $1.8 million of incremental production
costs in 2004 that were not reflected in 2003. Production costs from properties
sold in 2003 totaled $995,000 in 2003 that were not reflected in 2004. We
experienced an increase in production taxes consistent with an increase in
revenue from crude oil.
Total oil and gas production costs per MCFE increased $0.02 to $1.27
for 2004, compared with $1.25 for 2003. This increase is comprised of the
following:
o A $0.07 increase in production taxes due to higher revenue
from crude oil in our Rocky Mountain region;
o A $0.02 increase in production taxes due to higher revenue
from natural gas prices;
o A $0.01 increase in transportation costs;
o A $0.05 decrease reflecting general decreases in LOE per MCFE
primarily related to our Rocky Mountain and Permian regions;
and
o A $0.03 overall decrease in LOE relating to workover charges.
Change in net profits interest bonus plan liability. This expense is
the change in the net present value of estimated future incentive compensation
payments to be made to plan participants under the computational provisions of
the plan. The increase in the estimated liability resulted in expense of $7.5
million for the three months ended September 30, 2004 compared to $709,000 for
the same three months of 2003. The increase is a result of higher production
prices and lower discount rates used in the calculation.
General and administrative. General and administrative expenses
increased 14% or $669,000 to $5.5 million for the quarter ended September 30,
2004 compared to $4.8 million for the quarter ended September 30, 2003. The
increase in expense on a per MCFE basis of $0.04 reflects a 14% increase in cost
and reflects lower volumes in 2004.
The increase in our employee count from June of 2003 to September of
2004 has resulted in an increase in general and administrative expense of
$798,000 between the third quarter of 2004 and the third quarter of 2003. That
increase, plus a $342,000 increase in fees that are directly related to
Sarbanes-Oxley compliance, other increases in professional fees of $267,000 and
a $709,000 increase in expense associated with our incentive compensation plans
were offset by a $1.6 million increase in the amount of general and
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administrative expense we allocated to exploration expense. The increase in
expense associated with our incentive compensation plans results from $865,000
of expense we recorded for restricted stock units offset by a $196,000 decrease
in accruals under our cash bonus plans.
Interest expense. Interest expense decreased by $362,000 to $1.5
million for 2004 compared to $1.8 million for 2003. The decrease reflects the
benefit of the interest rate swaps that we entered into on October 3, 2003, and
decreased average borrowings under our credit facility in 2004 relative to the
prior year.
Income taxes. Income tax expense totaled $12.6 million for the third
quarter of 2004 and $8.8 million for the third quarter of 2003, resulting in
effective tax rates of 35.8 % and 38.8%, respectively. The effective rate change
from 2003 reflects percentage depletion and other permanent differences as well
as changes in the composition of the highest marginal state tax rates as a
result of acquisition and drilling activity. The cumulative effect of the change
in marginal state tax rates that we recorded in the third quarter of 2004 was a
result of filing our 2003 income tax returns and evaluating the impact on future
temporary difference reversals. Changes in the effect of percentage depletion
and other permanent items also impact the two periods differently, although on a
much smaller scale.
On October 22, 2004, the President signed the "American Jobs Creation
Act of 2004". This new law provides for sweeping restructuring of business
taxes. We are currently evaluating the impact that this new law will have on St.
Mary.
Comparison of Financial Results and Trends between the nine months ended
September 30, 2004 and 2003
Oil and gas production revenues. Average net daily production decreased
four percent to 202.5 MMCFE for the nine months ended September 30, 2004
compared with 211.8 MMCFE for the nine months ended September 30, 2003. Wells
completed in 2003 and 2004 combined with wells from acquisitions in 2003 and
2004 have added revenue of $65.6 million and average net daily production of
35.7 MMCFE in 2004 compared to 2003. These increases are offset by natural
declines in production from older properties and 4.1 MMCFE per day of 2003
production from properties that were sold in 2003.
Gain on sale of proved properties. In 2004 we finalized sales of
properties sold in 2003 and recognized $1.6 million additional gain.
Other revenue. The nine months ended September 30, 2003 included $3.6
million from proceeds of a litigation settlement.
Oil and gas production expenses. Total production costs remained flat
between the respective periods. Wells completed in 2003 and 2004 combined with
wells from acquisitions in 2003 added $6.7 million of incremental production
costs in 2004 that were not reflected in 2003. Production costs from properties
sold in 2003 totaled $2.6 million in 2003 that were not reflected in 2004.
Additionally, we experienced an increase in production taxes consistent with an
increase in revenue from crude oil, but those amounts were offset by a June 2004
accrual of $3.1 million in state severance tax incentive credits.
Total oil and gas production costs per MCFE increased $0.08 to $1.26
for 2004, compared with $1.18 for 2003. This increase is comprised of the
following:
o A $0.06 increase in production taxes due to higher revenue
from crude oil in our Rocky Mountain region;
o A $0.03 increase in production taxes due to higher revenue
from natural gas prices;
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o A $0.01 increase in transportation costs;
o A $0.04 increase in LOE that reflects our additions of higher
cost oil properties in our Rocky Mountain region through our
acquisitions from Burlington and Flying J; and
o A $0.06 decrease in our Mid-Continent region production taxes
resulting from the severance tax incentive credit accrual.
Change in net profits interest bonus plan liability. This expense
increased $11.6 million to $14.0 million for the nine months ended September 30,
2004 compared to $2.4 million for the same nine months of 2003. The amount
recorded is reflective of sustained oil and gas price increases that are
currently increasing the amounts we expect to pay out under the net profits
interest bonus plan. Adjustments to the liability are subject to estimation and
may change dramatically from quarter to quarter based on assumptions used for
reserve quantities, commodity pricing, discount rates and costs.
General and administrative. General and administrative expenses
increased five percent or $830,000 to $16.5 million for the nine months ended
September 30, 2004, compared with $15.6 million for the respective 2003
timeframe. The increase in cost on a per MCFE basis of $0.03 reflects the effect
of the five percent increase in general and administrative expense and a four
percent decrease in production between the respective periods.
The increase in employee count has resulted in an increase in general
and administrative expense of $3.4 million between the first nine months of 2004
and the first nine months of 2003. We also experienced an $858,000 increase in
fees that are directly related to Sarbanes-Oxley compliance and $680,000 of
increases in other professional fees. Those increases were offset by a $250,000
decrease in expense associated with our incentive compensation plans and a $4.0
million increase in the amount of general and administrative expense we
allocated to exploration expense. The decrease in expense associated with our
incentive compensation plans results from a $1.4 million decrease in cash
payments under our net profits interest bonus plan and a $1.8 million decrease
in accruals under our cash bonus plan that reflects the production decline we
have experienced in 2004. The impact of these two items is reduced by the $3.0
million of expense we recorded related to our June 30, 2004 restricted stock
unit issuance. The increase in general and administrative expense allocated to
exploration expense reflects our increase in skilled technical staff from early
2003 to date. The technical staff was increased in order to integrate our
acquisitions from 2002 and 2003 and to implement an increased drilling budget in
2004. The budget increase results from new projects identified from these
acquisitions as well as other new drilling projects and discoveries during that
timeframe.
Interest expense. Interest expense decreased by $1.9 million to $4.5
million for 2004 compared to $6.4 million for 2003. The decrease reflects the
benefit of the interest rate swap that we entered into on October 3, 2003 and
decreased average borrowings under our credit facility in 2004 relative to the
prior year.
Income taxes. Income tax expense totaled $39.1 million for the first
nine months of 2004 and $41.5 million for the first nine months of 2003,
resulting in effective tax rates of 37.2 % and 38.8%, respectively. The
effective rate change from 2003 reflects percentage depletion and other
permanent differences as well as changes in the composition of the highest
marginal state tax rates as a result of acquisition and drilling activity.
The current portion of the income tax expense in 2004 is $15.5 million
compared to $25.9 million in 2003. These amounts are 40 percent and 62 percent
of the total tax for the respective periods. We increased our 2004 budget for
drilling expenditures over 2003 amounts, and revenues are projected for only a
slight increase in 2004 over 2003. 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 lower in 2004 than it was in 2003.
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Accounting Matters
We recognized a $5.4 million gain net of income tax in 2003 from the
adoption of SFAS No. 143 effective January 1, 2003.
We refer you to Note 9 of Part I, Item 1 of this Quarterly Report on
Form 10-Q for additional information.
Cautionary Note 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
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:
o the amount and nature of future capital, development and
exploration expenditures,
o the drilling of wells,
o reserve estimates and the estimates of both future net
revenues and the present value of future net revenues that are
included in their calculation,
o future oil and gas production estimates,
o repayment of debt,
o business strategies,
o expansion and growth of operations,
o recent legal developments, and
o 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, the risks of various exploration strategies, 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 economically attractive exploration, development and property acquisition
opportunities, financing requirements, expected acquisition benefits, the
pending nature of certain reported acquisition transactions in this report and
the ability to complete the transactions, competition, litigation, environmental
matters, the potential impact of government regulations, and other matters
discussed in the "Risk Factors" section of our 2003 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 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 Vice President - Finance, 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
Vice President - Finance, 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 Vice President - Finance 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.
As previously reported, Nance Petroleum Corporation, a wholly owned
subsidiary, is named along with several other leaseholders and interested
parties as an additional co-defendant in a lawsuit that was originally filed in
the U.S. District Court for the District of Montana on June 12, 2001. The
plaintiff, the Northern Plains Resource Council, Inc., an environmental public
interest group, sued the U.S. Bureau of Land Management, the U.S. Secretary of
the Interior, the Montana BLM State Director and Fidelity Exploration &
Production Company. The lawsuit seeks the cancellation of all federal leases
related to coalbed methane development in Montana issued by the BLM since
January 1, 1997. This cancellation is sought primarily on the grounds of an
alleged failure of the BLM to comply with federal environmental laws. NPRC
alleges that the environmental impacts of coalbed methane development were not
properly analyzed before the challenged leases were issued. The Montana portion
of our Hanging Woman Basin coalbed methane project contains approximately 74,000
total net acres. The lawsuit potentially affects approximately 47,000 net acres
that are subject to federal leases. Based on information presently available, we
believe that the BLM complied with the applicable environmental laws, and the
District Court agreed by granting the defendants' motion for summary judgment in
December 2003. The court held that the issuance process regarding the federal
leases in question complied with the applicable environmental laws. The
plaintiff appealed this decision, and the Ninth Circuit Court of Appeals
affirmed the decision of the trial court on August 26, 2004. Plaintiff has filed
a petition for rehearing that is now pending before the Ninth Circuit. The Court
has not ruled on whether it will grant this petition. Notwithstanding our
success in the lower court and the appellate court, there is no assurance as to
the ultimate outcome of the lawsuit, and therefore, there is no assurance that
it will not adversely affect our coalbed methane project. Even if the federal
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leases in Montana become unavailable, we are proceeding with this project on
non-federal leases in Wyoming, and we anticipate acquiring additional
non-federal leases in Montana and Wyoming.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(e) The following table provides information about purchases by the Company
during the quarter ended September 30, 2004, 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
---------- ----------------- ------------------- --------------------- --------------------
(a) (b) (c) (d)
Total Number of Maximum Number of
Shares Purchased as Shares that May Yet
Total Number of Part of Publicly Be Purchased Under
Shares Purchased Average Price Paid Announced Program (1) the Program (1)
Period per Share
---------- ----------------- ------------------- --------------------- --------------------
07/01/04 - - 0 - $ - 0 - - 0 - 990,100
07/31/04
---------- ----------------- ------------------- --------------------- --------------------
08/01/04 - 413,000 $ 33.24 413,000 2,587,000
08/31/04
---------- ----------------- ------------------- --------------------- --------------------
09/01/04 - 76,300 $ 34.21 76,300 2,510,700
09/30/04
---------- ----------------- ------------------- --------------------- --------------------
Total: 489,300 $ 33.39 489,300 2,510,700
---------- ----------------- ------------------- --------------------- --------------------
(1) 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 3,000,000 as of the
effective date of the resolution. St. Mary had not made any repurchases
under the program since 2001. 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 $0.20 per share.
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ITEM 5. OTHER INFORMATION
On August 3, 2004, the Audit Committee of the Board of
Directors of St. Mary approved in advance certain non-audit services to
be performed by Deloitte & Touche LLP, St. Mary's independent
auditor. These non-audit services are to perform corporate income tax
compliance services.
ITEM 6. Exhibits
The following exhibits are furnished as part of this report:
Exhibit Description
------- -----------
10.1* Second Amendment to Credit Agreement dated September 20, 2004
among St. Mary Land & Exploration Company, Wachovia Bank,
National Association as Issuing Bank and Administrative
Agent, and the Lenders party thereto
10.2* Third Amendment to Credit Agreement dated October 20, 2004
among St. Mary Land & Exploration Company, Wachovia Bank,
National Association as Issuing Bank and Administrative
Agent, and the Lenders party thereto
10.3* Form of Restricted Stock Unit Award Memorandum under the St.
Mary Land & Exploration Company Restricted Stock Plan
31.1* Certification of Chief Executive Officer pursuant to Section
302 of the Sarbanes - Oxley Act of 2002
31.2* Certification of Vice President - Finance 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 thereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
November 4, 2004 By: /s/ MARK A. HELLERSTEIN
------------------------------------------
Mark A. Hellerstein
President and Chief Executive Officer
November 4, 2004 By: /s/ DAVID W. HONEYFIELD
------------------------------------------
David W. Honeyfield
Vice President - Finance, Secretary
and Treasurer
November 4, 2004 By: /s/ GARRY A. WILKENING
------------------------------------------
Garry A. Wilkening
Vice President - Administration and
Controller