06/04 10Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
------------
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 August 2, 2004, the registrant had 29,662,666 shares of common stock,
$0.01 par value, outstanding.
ST. MARY LAND &EXPLORATION COMPANY
--------------------------------------
INDEX
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Part I. FINANCIAL INFORMATION PAGE
----
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets - June 30, 2004
and December 31, 2003.......................................3
Consolidated Statements of
Operations - Three and Six Months Ended
June 30, 2004 and 2003......................................4
Consolidated Statements of
Cash Flows - Six Months Ended
June 30, 2004 and 2003......................................5
Consolidated Statements of Stockholders' Equity and
Comprehensive Income - June 30, 2004 and
December 31, 2003...........................................7
Notes to Consolidated Financial
Statements - June 30, 2004..................................8
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations..............................................22
Item 3. Quantitative and Qualitative Disclosures
About Market Risk (included within
the content of Item 2).....................................38
Item 4. Controls and Procedures....................................38
Part II. OTHER INFORMATION
Item 1. Legal Proceedings..........................................38
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities......................39
Item 4. Submission of Matters to a Vote of Security Holders........39
Item 6. Exhibits and Reports on Form 8-K...........................40
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
June 30, December 31,
-------------------------------
ASSETS 2004 2003
------------- -------------
Current assets:
Cash and cash equivalents $ 27,581 $ 14,827
Short-term investments 1,447 12,509
Accounts receivable 79,624 65,084
Prepaid expenses and other 4,835 6,020
Deferred income taxes 8,569 8,872
Other 389 611
------------- -------------
Total current assets 122,445 107,923
------------- -------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 932,317 858,246
Less - accumulated depletion, depreciation and amortization (351,356) (312,719)
Wells in progress 31,581 24,691
Unproved oil and gas properties, net of impairment allowance
of $11,210 in 2004 and $10,776 in 2003 38,639 36,793
Other property and equipment, net of accumulated depreciation
of $5,097 in 2004 and $4,656 in 2003 4,795 4,276
------------- -------------
655,976 611,287
------------- -------------
------------- -------------
Other noncurrent assets 5,649 16,644
------------- -------------
------------- -------------
Total Assets $ 784,070 $ 735,854
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 86,507 $ 81,217
Accrued derivative liability 22,359 23,605
------------- -------------
Total current liabilities 108,866 104,822
------------- -------------
Noncurrent liabilities:
Long-term credit facility - 11,000
Convertible notes 99,743 99,696
Asset retirement obligation 26,868 25,485
Net profits interest bonus plan liability 12,648 6,163
Other noncurrent liabilities 5,474 7,088
Deferred income taxes 103,488 90,947
------------- -------------
Total noncurrent liabilities 248,221 240,379
------------- -------------
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: 29,660,768 shares in 2004 and 29,245,123 shares
in 2003; outstanding, net of treasury shares: 28,670,668
shares in 2004 and 28,242,423 shares in 2003 297 292
Additional paid-in capital 144,751 146,362
Treasury stock, at cost: 990,100 shares in 2004 and 1,002,700
shares in 2003 (15,708) (16,057)
Deferred stock-based compensation (6,201) -
Retained earnings 316,793 274,937
Accumulated other comprehensive loss (12,949) (14,881)
------------- -------------
Total stockholders' equity 426,983 390,653
------------- -------------
Total Liabilities and Stockholders' Equity $ 784,070 $ 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 Six Months Ended
June 30, June 30,
--------------------------- ------------------------
2004 2003 2004 2003
------------ ------------ ---------- ----------
Operating revenues:
Oil and gas production $ 95,447 $ 96,134 $188,054 $191,822
Gain on sale of proved properties 1,581 86 1,776 122
Marketed gas revenue 3,724 3,333 7,297 7,108
Other oil and gas revenue 1,395 595 1,462 2,040
Other revenue 376 3,638 496 3,816
------------ ------------ ---------- ----------
Total operating revenues 102,523 103,786 199,085 204,908
------------ ------------ ---------- ----------
Operating expenses:
Oil and gas production 21,573 23,260 45,116 44,390
Depletion, depreciation, amortization
and abandonment liability accretion 20,673 21,601 41,299 40,486
Exploration 6,569 6,276 11,200 10,426
Impairment of proved properties 494 - 494 -
Abandonment and impairment of unproved properties 966 784 1,888 1,703
General and administrative 5,410 5,453 10,987 10,826
Change in net profits interest bonus plan liability 4,325 924 6,485 1,697
Derivative loss 1,721 82 869 -
Marketed gas system operating expense 3,310 3,098 6,721 6,457
Other 897 299 1,562 495
------------ ------------ ---------- ----------
Total operating expenses 65,938 61,777 126,621 116,480
------------ ------------ ---------- ----------
Income from operations 36,585 42,009 72,464 88,428
Nonoperating income(expense):
Interest income 242 344 386 574
Interest expense (1,565) (2,367) (3,053) (4,583)
------------ ------------ ---------- ----------
Income before income taxes and cumulative
effect of change in accounting principle 35,262 39,986 69,797 84,419
Income tax expense (13,426) (15,669) (26,512) (32,740)
------------ ------------ ---------- ----------
Income before cumulative effect of change in accounting principle 21,836 24,317 43,285 51,679
Cumulative effect of change in accounting principle,
net of income tax - - - 5,435
------------ ------------ ---------- ----------
Net Income $ 21,836 $ 24,317 $ 43,285 $ 57,114
============ ============ ========== ==========
Basic weighted average common shares outstanding 28,584 31,482 29,201 30,921
Diluted weighted average common shares outstanding 33,062 35,798 33,646 35,222
Basic earnings per common share:
-------------------------------
Income before cumulative effect of change in accounting principle $ 0.76 $ 0.77 $ 1.48 $ 1.67
Cumulative effect of change in accounting principle - - - 0.18
------------ ------------ ---------- ----------
Basic net income per common share $ 0.76 $ 0.77 $ 1.48 $ 1.85
============ ============ ========== ==========
Diluted earnings per common share:
---------------------------------
Income before cumulative effect of change in accounting principle $ 0.69 $ 0.71 $ 1.34 $ 1.52
Cumulative effect of change in accounting principle - - - 0.15
------------ ------------ ---------- ----------
Diluted net income per common share $ 0.69 $ 0.71 $ 1.34 $ 1.67
============ ============ ========== ==========
Cash dividends declared per common share $ 0.05 $ 0.05 $ 0.05 $ 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 Six Months Ended
June 30,
------------------------------
2004 2003
Reconciliation of net income to net cash provided ------------ ------------
by operating activities:
Net income $ 43,285 $ 57,114
Adjustments to reconcile net income to net
cash provided by operating activities:
Gain on sale of proved properties (1,776) (122)
Depletion, depreciation, amortization
and abandonment liability accretion 41,299 40,486
Exploratory dry hole expense 1,236 1,142
Impairment of proved properties 494 -
Abandonment and impairment of unproved properties 1,888 1,703
Unrealized derivative (gain) loss 869 (33)
Change in net profits interest bonus plan liability 6,485 1,697
Stock-based compensation expense 2,100 -
Deferred income taxes 15,525 10,886
Other (2,588) (818)
Cumulative effect of change in accounting
principle, net of tax - (5,435)
------------ ------------
108,817 106,620
Changes in current assets and liabilities:
Accounts receivable (14,540) (22,553)
Prepaid expenses and other 1,639 857
Accounts payable and accrued expenses 3,903 5,840
------------ ------------
Net cash provided by operating activities 99,819 90,764
------------ ------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 2,205 2,635
Capital expenditures (81,734) (45,600)
Acquisition of oil and gas properties, including related
$71,594 loan to Flying J in 2003 (4,913) (77,677)
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 710 102
------------ ------------
Net cash used in investing activities (62,290) (120,619)
------------ ------------
Cash flows from financing activities:
Proceeds from credit facility 90,497 108,811
Repayment of credit facility (101,500) (79,820)
Costs from issuance of convertible notes - (73)
Proceeds from sale of common stock for exercise
of stock options 7,063 2,202
Repurchase of common stock from Flying J (19,406) -
Dividends paid (1,429) (1,573)
------------ ------------
Net cash provided by (used in) financing activities (24,775) 29,547
------------ ------------
Net change in cash and cash equivalents 12,754 (308)
Cash and cash equivalents at beginning of period 14,827 11,154
------------ ------------
Cash and cash equivalents at end of period $ 27,581 $ 10,846
============ ============
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 Six Months Ended
June 30,
--------------------------------
2004 2003
------------- ------------
(In thousands)
Cash paid for interest, including amounts capitalized $ 4,374 $ 4,851
Cash paid (received) for income taxes $ 8,157 $ (8,699)
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 recorded compensation expense of $2.1 million in the
quarter ended June 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
$64,000 for the first quarter of 2004 and $277,000 in the second quarter
of 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 - - - - - - 43,285 - 43,285
Change in derivative instrument
fair value - - - - - - - (10,306) (10,306)
Reclassification to earnings - - - - - - - 12,238 12,238
-------------
Total comprehensive income 45,217
-------------
Cash dividends, $ 0.05 per share - - - - - - (1,429) - (1,429)
Issuance of 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 408,233 5 9,314 - - - - - 9,319
Deferred compensation related to
restricted stock unit awards - - 8,301 - - (8,301) - - -
Amortization of deffered stock-
based compensation - - - - - 2,100 - - 2,100
Directors' stock compensation - - - 12,600 349 - - - 349
---------- ------ -------- ----------- --------- ------------- -------- ------------- -------------
Balances, June 30, 2004 29,660,768 $ 297 $144,751 (990,100) $(15,708) $ (6,201) $316,793 $ (12,949) $ 426,983
========== ====== ======== =========== ========= ============= ======== ============= =============
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)
--------------------------
June 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 oil and gas reserves. 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 expensed 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 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 with the current presentation.
The Stockholders approved a restricted stock plan in the second quarter
of 2004. The Compensation Committee of the Board of Directors is responsible for
determining the grant criteria under the restricted stock plan. The Compensation
-8-
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, during the time from the beginning of the performance year until
the grants are issued, the Company applies variable plan accounting in
estimating expense until a firm measurement date occurs. 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. Besides 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. Consequently, prior period unproved oil and gas properties, net of
impairment allowance has been reclassified to conform with 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 accompanying consolidated
balance sheets 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 and
other dilutive securities. Adjusted net income is used for the if-converted
method discussed below 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 including the
related income tax effect. 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 treasury stock method is used to measure the dilutive impact of
stock options and unvested restricted stock units. The table below details the
weighted-average dilutive securities related to stock options and unvested
restricted stock units for the periods presented.
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 615,190 and
614,181 anti-dilutive securities related to stock options for the three-month
and six-month periods ended June 30, 2003, respectively, and 0 and 600,053
anti-dilutive securities related to stock options for the three-month and
six-month periods ended June 30, 2004, respectively. There were no anti-dilutive
securities related to restricted stock units for any periods presented.
Shares associated with the conversion feature of the Convertible Notes
are accounted for using the if-converted method. Under the if-converted method,
income used to calculate diluted earnings per share is adjusted for the interest
charges and nondiscretionary adjustments based on income that would have changed
had the Convertible Notes been converted at the beginning of the period.
-9-
Potentially dilutive shares of 3,846,153 related to the Convertible Notes were
included in the calculation of diluted net income per common share for the
three-month and six-month periods ended June 30, 2004 and 2003. The Convertible
Notes were issued in March 2002.
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 Six Months Ended
June 30, June 30,
---------------------------- ---------------------------
2004 2003 2004 2003
------------ ------------ ------------ -----------
Income before cumulative effect of change in
accounting principle $ 21,836 $ 24,317 $ 43,285 $ 51,679
Cumulative effect of change in accounting principle,
net of income tax - - - 5,435
---------- ------------ ------------ -----------
Net income $ 21,836 $ 24,317 $ 43,285 $ 57,114
---------- ------------ ------------ -----------
Adjustments to net income for dilution:
Add: Interest expense not incurred if
Convertible Notes converted 1,580 1,580 3,160 3,142
Less: Other adjustments (16) (16) (32) (31)
Less: Income tax effect of dilution items (596) (601) (1,188) (1195)
---------- ------------ ------------ -----------
Net income adjusted for the effect of dilution 22,804 25,280 45,225 59,030
========== ============ ============ ===========
Basic weighted-average common shares
outstanding in period 28,584 31,482 29,201 30,921
Add: Dilutive effect of stock options 630 470 598 455
Add: Dilutive effect of unvested restricted
stock units 2 - 1 -
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 33,062 35,798 33,646 35,222
========== ============ ============ ===========
Basic earnings per common share:
Income before cumulative effect of change
in accounting principle $ 0.76 $ 0.77 $ 1.48 $ 1.67
Cumulative effect of change in accounting
principle - - - 0.18
---------- ------------ ------------ -----------
Total $ 0.76 $ 0.77 $ 1.48 $ 1.85
========== ============ ============ ===========
Diluted earnings per common share:
Income before cumulative effect of change
in accounting principle $ 0.69 $ 0.71 $ 1.34 $ 1.52
Cumulative effect of change in accounting
principle - - - 0.15
---------- ------------ ------------ -----------
Total $ 0.69 $ 0.71 $ 1.34 $ 1.67
========== ============ ============ ===========
-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 granted 232,861 restricted stock units (RSUs) on June 30,
2004. The total expense associated with this grant was $8.3 million as measured
on June 30, 2004. The grant of RSUs 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 grant, at which time
the shares carry no further restrictions. As a result of the vesting schedule,
$2.1 million was recorded as compensation expense in June 2004. The remaining
$6.2 million was recorded in deferred stock-based compensation as of June 30,
2004.
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 Six Months Ended
June 30, June 30,
---------------------------- --------------------------
2004 2003 2004 2003
----------- ---------- ------------ ----------
Net income -
------------
As reported: $ 21,836 $ 24,317 $ 43,285 $ 57,114
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects 1,302 - 1,302 -
Less: Stock-based employee compensation
determined under fair value based
method for all expense, net of related
income tax effects (2,163) (2,271) (3,046) (2,571)
----------- ---------- ------------ ----------
Pro forma net income $ 20,975 $ 22,046 $ 41,541 $ 54,543
=========== ========== ============ ==========
Basic earnings per share -
--------------------------
As reported:
Income before cumulative effect of
change in accounting principle $ 0.76 $ 0.77 $ 1.48 $ 1.67
Cumulative effect of change in
accounting principle - - - 0.18
----------- ---------- ------------ ----------
Total $ 0.76 $ 0.77 $ 1.48 $ 1.85
=========== ========== ============ ==========
Pro forma:
Income before cumulative effect of
change in accounting principle $ 0.73 $ 0.70 $ 1.42 $ 1.58
Cumulative effect of change in
accounting principle - - - 0.18
----------- ---------- ------------ ----------
Total $ 0.73 $ 0.70 $ 1.42 $ 1.76
=========== ========== ============ ==========
Diluted earnings per share -
----------------------------
As reported:
Income before cumulative effect of
change in accounting principle $ 0.69 $ 0.71 $ 1.34 $ 1.52
Cumulative effect of change in
accounting principle - - - 0.15
----------- ---------- ------------ ----------
Total $ 0.69 $ 0.71 $ 1.34 $ 1.67
=========== ========== ============ ==========
Pro forma:
Income before cumulative effect of
change in accounting principle $ 0.66 $ 0.64 $ 1.28 $ 1.45
Cumulative effect of change in
accounting principle - - - 0.15
----------- ---------- ------------ ----------
Total $ 0.66 $ 0.64 $ 1.28 $ 1.60
=========== ========== ============ ==========
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.
-12-
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair value of options granted in the
three-month and six-month periods ended June 30, 2004 and 2003 were estimated
using the following weighted-average assumptions.
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------ ---------------------
2004 2003 2004 2003
-------- --------- -------- --------
Risk free interest rate:
Stock options * 3.4% 3.6% 3.1%
Employee stock purchase plan 3.6% 3.4% 3.6% 3.4%
Dividend yield:
Stock options * 0.4% 0.3% 0.4%
Employee stock purchase plan 0.3% 0.4% 0.3% 0.4%
Volatility factor of the expected market
price of the Company's common stock:
Stock options * 49.5% 38.5% 48.4%
Employee stock purchase plan 16.1% 12.5% 16.1% 12.5%
Expected life of the options (in years):
Stock options * 7.7 7.6 6.3
Employee stock purchase plan 0.5 0.5 0.5 0.5
-------------------------------
* No stock options were granted in the second quarter of fiscal year 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 require companies to
recognize the fair value of stock options and other stock-based compensation as
expense for reporting periods beginning in 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 six-month periods ended June
30, 2004 and 2003 differ from the amounts that would be provided by applying the
statutory U.S. Federal income tax rate to income before income taxes primarily
due to the effect of state income taxes, percentage depletion, changes in the
composition of income tax rates and other permanent differences. For the
three-month and six-month periods ended June 30, 2004, the Company's current
portion of income tax expense was $7.5 million and $13.4 million, respectively,
-13-
compared to $10.5 million and $21.9 million, respectively, for the three-month
and six-month periods ended June 30, 2003.
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 for the full $300.0 million in April 2004 under its
normal semi-annual redetermination. The borrowing base redetermination process
considers the value of St. Mary's oil and gas properties and other assets, as
determined by the bank syndicate. The Company elected an aggregate commitment
amount of $150.0 million. The Company must comply with certain financial and
non-financial covenants. The Company is currently 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
June 30, 2004.
5.75% Senior Convertible Notes Due 2022
As of June 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 six-month periods ended June 30,
2004. Based on the trading price of the Convertible Notes over the determination
periods, the Company was subject to the contingent interest payments for the
interest period from September 16, 2003 to March 15, 2004, and will be subject
to the contingent interest payments for the interest period from March 16, 2004
to September 15, 2004.
Under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," 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, $47,000 was amortized through interest expense
for each of the six-month periods ended June 30, 2004 and 2003. Interest expense
for each of the three-month periods ended June 30, 2004 and 2003 includes
$24,000 of amortization. Derivative loss for the six months ended June 30, 2004
contains $93,500 of net loss from mark-to-market adjustments for this
derivative, and derivative gain for the six months ended June 30, 2003 contains
$13,700 of net loss from mark-to-market adjustments. Derivative loss in the
-14-
consolidated statements of operations for the three-month periods ended June 30,
2004 and 2003 includes net losses of $97,400 and $141,000, 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 was 1.16%, and the Company received proceeds of $484,000 from the
semi-annual settlement of the swaps on that date. 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 $894,000 as of June 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. The Company
recorded a net derivative loss in the consolidated statements of operations of
$1.6 million for the three-month period ended June 30, 2004 and a net derivative
loss of $790,000 for the six-month period ended June 30, 2004 from
mark-to-market adjustments for this derivative.
Weighted-average Interest Rate Paid
The weighted-average interest rates paid for the second quarters of
2004 and 2003 were 7.2% and 6.2%, 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. The weighted-average interest rates paid for the six-month
periods ended June 30, 2004 and 2003 were 6.9% 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 quarters.
Note 7 - Oil and Gas Derivative Contracts
The Company recognized a net loss of $19.7 million from its oil and gas
derivative contracts for the six months ended June 30, 2004, compared to a net
loss of $15.1 million for the same period in 2003. Comparative amounts for the
three-month periods ended June 30, 2004 and 2003 were a net loss of $11.1
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 June 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.
-15-
Swaps
-----
Gas (per MMBtu) Oil (per Bbl)
-------------------------------------- ---------------------------------------
Weighted-Average Weighted-Average
Contract Contract Price Contract Price
Month Volumes (Regional Index) Volumes (NYMEX)
------------- --------------------- --------------- --------------------
July 944,700 $ 4.18 172,500 $ 24.65
August 962,000 4.23 172,900 24.81
September 956,600 4.24 178,300 25.38
October 954,100 4.24 176,700 25.38
November 863,800 4.35 174,200 25.39
December 859,600 4.36 172,100 25.40
------------- --------------------- --------------- --------------------
Total 2004 5,540,800 4.26 1,046,700 25.17
------------- --------------------- --------------- --------------------
2005
January 242,600 5.69 36,000 31.70
February 242,600 5.69 36,000 31.70
March 242,600 5.69 14,900 35.25
April 242,600 5.69 9,000 39.22
May 179,000 5.76 9,000 39.22
June 25,000 6.12 9,000 39.22
July 25,000 6.12 9,000 39.22
August - - 7,000 39.49
------------- --------------------- --------------- --------------------
Total 2005 1,199,400 5.72 129,900 34.61
------------- --------------------- --------------- --------------------
All Contracts 6,740,200 $ 4.52 1,176,600 $ 26.21
============= ===================== =============== ====================
Collars
-------
Gas (per MMBtu)
---------------------------------------------------
Floor Ceiling
Duration Price Price Volumes Index
-------- ----- ----- ------- -----
July 2004 - June 2005 $ 5.75 $ 6.89 25,000 per month IF ANR OK
August 2004 - July 2005 $ 5.50 $ 6.81 25,000 per month 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 3,841,200
IF CIG N System 1,261,100
IF Henry Hub 1,037,900
IF Reliant N/S 360,000
IF HSC 240,000
--------------
Total 6,740,200
==============
For contracts in place on June 30, 2004, a hypothetical change of 10
percent in future gas strip prices representing a $0.59 increase per MMBtu
applied to a notional amount of 6.7 million MMBtu covered by natural gas swaps
and 600,000 MMbtu covered by natural gas collars would cause a change in hedge
gain or loss included in gas revenue of $3.2 million in 2004 and $713,000 in
2005. A hypothetical change of 10 percent in the future NYMEX strip oil prices
representing a $3.67 increase per Bbl applied to a notional amount of 1.1 MMBbl
covered by crude oil swaps would cause a change in hedge gain or loss included
in oil revenue of $3.7 million in 2004 and $214,000 in 2005.
-16-
The following table summarizes all derivative instrument gain (loss)
activity for the periods presented (in thousands):
For the Three Months Ended For the Six Months Ended
June 30, June 30,
--------------------------------- -------------------------------
2004 2003 2004 2003
--------------- -------------- -------------- --------------
Derivative contract settlements included in oil
and gas production revenues $ (11,134) $ (4,416) $ (19,733) $ (15,054)
Ineffective portion of hedges qualifying for
hedge accounting included in derivative
loss (1) 60 14 47
Non-qualified derivative contracts included in
derivative gain (loss) (1,720) (142) (883) (14)
Amortization of contingent interest derivative
through interest expense (23) (24) (47) (48)
--------------- -------------- -------------- --------------
Total $ (12,878) $ (4,522) $ (20,649) $ (15,069)
=============== ============== ============== ==============
On June 30, 2004, St. Mary's remaining cash flow hedge positions from
oil and gas derivatives had an estimated net pre-tax liability of $21.6 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 June 30, 2004, to be reclassified from
accumulated other comprehensive income to oil and gas production operating
revenues in the next twelve months would be $11.8 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").
-17-
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 Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2004 2003 2004 2003
--------------- -------------- --------------- --------------
Components of net periodic benefit cost:
Service cost $ 285 $ 241 $ 569 $ 481
Interest cost 122 107 245 214
Expected return on plan assets (74) (43) (148) (86)
Amortization of prior service cost (4) (6) (8) (13)
Amortization of net actuarial loss 55 82 109 165
--------------- -------------- --------------- --------------
Net periodic benefit cost $ 384 $ 381 $ 767 $ 761
=============== ============== =============== ==============
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.
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.
-18-
Upon adoption of SFAS No. 143, 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 June 30, 2004, the Company has excluded $41.9 million of
estimated salvage value from its DD&A calculation.
A reconciliation of the Company's liability for the three-month and
six-month periods ended June 30, 2004, is as follows (in thousands):
For the Three Months Ended For the Six Months Ended
June 30, June 30,
---------------------------------- ---------------------------------
2004 2003 2004 2003
--------------- --------------- --------------- ---------------
Beginning asset retirement obligation $ 26,036 $ 23,734 $ 25,485 $ -
Liability from SFAS No. 143 adoption - - - 21,403
Liabilities incurred 505 956 668 2,892
Liabilities settled (150) (530) (227) (530)
Accretion expense 477 443 942 838
--------------- --------------- --------------- ---------------
Ending asset retirement obligation $ 26,868 $ 24,603 $ 26,868 $ 24,603
=============== =============== =============== ===============
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 is 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 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 June 30, For the Six Months Ended June 30,
-------------------------------------------- -----------------------------------------
2004 2003 2004 2003
-------------------- ------------------- ------------------- ------------------
Compensation Expense $ 1,460 $ 2,610 $ 3,456 $ 4,894
-19-
The Company records the estimated liability for the Net Profits Plan
based on the discounted value of future payments associated with each individual
pool. The following table presents the changes in the estimated liability
attributable to the Net Profits Plan (in thousands):
Balance as of December 31, 2003 $ 6,163
Increase in liability 9,941
Reduction in liability for cash payments
made under the Net Profits Plan (3,456)
--------------------
Balance as of June 30, 2004 $ 12,648
====================
The Company records changes in the present value of estimated future
payments under the Net Profits Plan as a separate item in the consolidated
statements of operations. The change in the estimated 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. 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 June 30, For the Six Months Ended June 30,
-------------------------------------- ----------------------------------
2004 2003 2004 2003
----------------- ----------------- --------------- ---------------
General and Administrative Expense $ 2,725 $ 565 $ 3,629 $ 1,338
Exploration Expense 1,600 359 2,856 359
----------------- ----------------- --------------- ---------------
Total $ 4,325 $ 924 $ 6,485 $ 1,697
================= ================= =============== ===============
Note 11 - Repurchase of Common Stock
On February 9, 2004, the Company repurchased 3,380,818 restricted
shares of its common stock from Flying J Oil & Gas and Big West Oil &
Gas, Inc. (collectively "Flying J") for a total of $91.0 million. St. Mary
originally issued these shares to Flying J on January 29, 2003, in connection
with St. Mary's acquisition of 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.
-20-
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
================== =================
-21-
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 robust oil and gas prices through the
first six months of 2004.
Second Quarter 2004 Highlights
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 and from continuing strong demand for
natural gas in domestic markets. Oil prices continued to be very strong,
reflecting a weaker US dollar, strong worldwide demand, Middle East instability,
uncertainty associated with Russian oil exports, uncertainties resulting from
doubts about OPEC announcements regarding their ability to increase production
and crude oil refining constraints in the United States. NYMEX prices for the
second quarter of 2004 averaged $5.97 per MMBtu and $38.43 per barrel, an
increase of 5 percent for gas and 9 percent for oil compared to the first
quarter of 2004 and an increase of 32 percent for gas and 9 percent for oil
compared to the second quarter of 2003.
Net income for the quarter ended June 30, 2004, was $21.8 million or
$0.69 per diluted share compared to the 2003 results of $24.3 million or $0.71
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. Production decreased 12 percent to 18.0 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 13 percent to $5.29
per MCFE. Unit costs increased for the period as operating expense increased
$0.07 to $1.20 per MCFE due to general upward cost pressure and due to increased
workover expense, and DD&A (including impairments) increased $0.10 to $1.15
per MCFE as a result of overall higher finding costs.
In the second quarter of 2004 the State of Oklahoma announced, one
quarter earlier than in the prior year, that its severance tax incentive credit
would be available for production from July 1, 2003 to June 30, 2004. We
estimate and accrue a net reduction of severance tax expense in Oklahoma when
the state announces that all of the criteria for the incentive have been met and
that they will accept refund claims. We accrued a $3.1 million benefit for this
item in June 2004.
-22-
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 recorded $2.1 million of
compensation expense in June 2004. The remaining expense of $6.2 million was
recorded in deferred stock-based compensation as of June 30, 2004 and will be
recognized over the remaining vesting periods.
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. This reclassification will have the effect of
reducing previously reported general and administrative expense and exploration
expense to include only those amounts that relate to oil and gas production
realized in the current period. The analyses throughout this report reflect
this change for all periods presented. For the quarter ended June 30, 2004 the
expense related to the change in the estimated liability for the net profits
interest bonus plan increased to $4.3 million from $924,000 for the comparable
quarter of 2003.
First Six Months 2004 Highlights
NYMEX prices for the first six months of 2004 averaged $5.83 per MMBtu
and $36.79 per barrel, a decrease of 4 percent for gas and an increase of 17
percent for oil compared to the same period in 2003. As of June 30, 2004, the
NYMEX strip for the remainder of the year was $37.13 per barrel for oil and
$6.33 per MMBtu for gas.
Net income for the six months ended June 30, 2004, was $43.3 million or
$1.34 per diluted share compared to the 2003 results of $51.7 million or $1.52
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 5 percent to 36.5 BCFE on a comparative six-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
4 percent to $5.15 per MCFE. Lease operating expense unit costs (including
taxes) increased $0.09 to $1.24 per MCFE primarily due to additions of higher
cost properties in our Rocky Mountain region. DD&A unit costs (including
impairments) increased $0.08 to $1.13 per MCFE as a result of higher per unit
cost additions. General and administrative expense increased $0.02 to $0.30 per
MCFE due to a 1 percent increase in actual general and administrative cost
coupled with the 5 percent decrease in production volumes. The expense related
to our net profits interest bonus plan liability increased to $6.5 million for
the six months ended June 30, 2004 period compared to $1.7 million in 2003 due
to the performance of individual pools and the effect of a higher price
environment.
Net cash provided by operating activities was $99.8 million, up 10
percent from the $90.8 million provided in 2003. This positive cash flow trend
is expected to continue as prices remain relatively higher and our operating
costs remain under control.
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.
-23-
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 increased to $305 million. Of this
amount, $205 million is allocated to exploration and development
drilling with the remainder for acquisitions. A table of budgeted
amounts by core area is detailed under the caption Capital
Expenditure Budget. Through June we have closed $4.9 million of
acquisitions. Although we continue to aggressively evaluate
acquisition packages, the probability of closing on a significant
acquisition in the second half of 2004 becomes less likely as we
get further into the year.
o We expect to see the decline in our production levels begin to
reverse in the second half of the year. A portion of the
comparative decline between periods has resulted from slower
replacement of production at NE Mayfield and reflects the flush
production from this area we reported in the second quarter of
2003. We attribute our estimate of future production to an
increase in expected completion activity in the second half of
2004.
o Our Hanging Woman Basin coalbed methane project is on schedule. We
plan to complete 108 wells in Wyoming in 2004. Two drilling rigs
are operating in the project and 14 wells have been drilled as of
July 1, 2004. 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.
o We continue to evaluate 3-D seismic data that covers our entire
24,914 fee acreage position in St. Mary Parish, Louisiana. In
conjunction with the 3-D seismic shoot, we optioned 14,969 acres
for lease to third parties, primarily in the middle portion of our
property where little exploration has historically taken place. An
option to lease approximately 2,800 acres was exercised during the
second quarter.
-24-
A Quarter and Six-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 Six Months Ended
June 30, $ of June 30, % of
----------------------- Change -------------------------- Change
2004 2003 Between 2004 2003 Between
Periods Periods
---------- --------- ----------- -----------
Net Production Volumes
----------------------
Natural Gas (Mcf) 11,070 13,614 22,683 25,318
Oil (Bbl) 1,161 1,164 2,302 2,205
MCFE 18,038 20,595 (12)% 36,494 38,546 (5)%
Average Daily Production
------------------------
Natural Gas (Mcf per day) 122 150 125 140
Oil (Bbls per day) 13 13 13 12
MCFE per day (6:1) 198 226 (12)% 201 213 (6)%
Oil & Gas Production Revenues
---------------------------------
Gas Production $ 59,701 $ 65,650 $ 120,141 $ 131,581
Oil Production 35,746 30,484 67,913 60,241
---------- --------- ----------- -----------
Total $ 95,447 $ 96,134 (1)% $ 188,054 $ 191,822 (2)%
========== ========= =========== ===========
Oil & Gas Production Costs
------------------------------
Lease Operating Expenses $ 15,452 $ 15,149 $ 30,629 $ 29,020
Transportation Costs 1,629 1,941 3,366 3,331
Production Taxes 4,492 6,170 11,121 12,039
---------- --------- ----------- -----------
Total $ 21,573 $ 23,260 (7)% $ 45,116 $ 44,390 2%
========== ========= =========== ===========
Average Realized Sales Price, net of hedging
--------------------------------------------
Natural Gas (Per Mcf) $ 5.39 $ 4.82 12% $ 5.30 $ 5.20 2%
Oil (Per Bbl) $ 30.78 $ 26.20 17% $ 29.50 $ 27.32 8%
Per MCFE Data:
--------------
Net Realized Price $ 5.29 $ 4.67 13% $ 5.15 $ 4.98 4%
Lease Operating Expense (0.86) (0.74) 16% (0.84) (0.75) 12%
Transportation Costs (0.09) (0.09) -0-% (0.09) (0.09) -0-%
Production Taxes (0.25) (0.30) (17)% (0.31) (0.31) -0-%
General and Administrative (0.30) (0.26) 15% (0.30) (0.28) 7%
---------- --------- ----------- -----------
Operating Profit $ 3.79 $ 3.28 16% $ 3.61 $ 3.55 2%
========== ========= =========== ===========
Depletion, Depreciation and Amortization $ 1.15 $ 1.05 10% $ 1.13 $ 1.05 8%
Financial Information (In Thousands, Except Per Share Amounts):
-------------------------------------------------------------- % of
Change
Between
June 30, 2004 December 31, 2003 Periods
------------- ----------------- -------
Working Capital $ 13,579 $ 3,101 338%
Long-Term Debt $ 99,743 $ 110,696 (10)%
Stockholders' Equity $ 426,983 $ 390,653 9%
-25-
Three Months Ended Six Months Ended
June 30, $ of June 30, % of
----------------------- Change -------------------------- Change
2004 2003 Between 2004 2003 Between
Periods Periods
---------- --------- ----------- -----------
Basic Net Income Per Common Share $ 0.76 $ 0.77 (1)% $ 1.48 $ 1.85 (20)%
Diluted Net Income Per Common Share $ 0.69 $ 0.71 (3)% $ 1.34 $ 1.67 (20)%
Basic Weighted-Average Shares Outstanding 28,584 31,482 (9)% 29,201 30,921 (6)%
Diluted Weighted-Average Shares Outstanding 33,062 35,798 (8)% 33,646 35,222 (4)%
Net Cash Provided By Operating Activities $ 99,819 $ 90,764 10%
Net Cash Used In Investing Activities $ (62,290) $ (120,619) (48)%
Net Cash Provided By (Used In) Financing
Activities $ (24,775) $ 29,547 (184)%
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 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
expenses will remain fairly constant with respect to recurring costs and will
decrease slightly for planned workover activity. 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 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 decrease relative to the first six 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, sales of non-strategic properties and access to the
capital markets.
Our Current Credit Facility.
The calculated borrowing base for our credit facility was increased to
$300.0 million in April 2004 following a normal semi-annual borrowing base
review. 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 currently 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
-26-
the utilization table, and Alternate Base Rate borrowings accrue interest at
prime plus the applicable margin from the utilization table located in Note 5 of
Part IV, Item 15 of our December 31, 2003 report. 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. We did not have
an outstanding balance on June 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 six
months of 2004 through cash flow from operations. Our weighted-average interest
rate paid in 2004 has been 6.9 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, which we expect will
continue to result in lower interest expense through September of 2004 compared
to last year unless interest rates rise significantly. The sensitivity analysis
discussed below presents the hypothetical change in fair value of those
financial instruments we held at June 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 June 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 $252,000 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 six-months of 2004 we spent $86.6 million on
capital development and a net $19.4 million to acquire shares of our common
stock from Flying J using cash flows from operations and debt financing. We
decreased outstanding borrowings on our credit facility by $11.0 million, and we
made $9.9 million in net cash payments for income taxes.
-27-
The following table presents amounts and percentage changes between the
six-month periods ended June 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 $ 9,055 10%
Net cash used in investing activities $ 58,329 (48)%
Net cash provided by (used in) financing activities $ (54,322) (184)%
Analysis of cash flow changes between the six months ended June 30, 2004 and
June 30, 2003.
Operating Activities. Sources of cash flow from oil and gas sales
remained flat between periods as production decreases were offset by price
increases. Cash expenditures for operating expenses also remained flat between
periods. Of the difference in the table, $6.9 million relates to changes in
current assets and liabilities. Accounts receivable balances increased at a
lesser rate for the six months ended June 30, 2004 than for the same period in
2003 and resulted in a positive $8.0 million impact on cash flow from
operations. Accounts payable, accrued expenses and prepaid expenses also
increased at a lesser rate between the two periods resulting in a $1.1 million
negative impact to cash flows from operating activities and resulted in $1.1
million of offset to the positive increase.
Investing Activities. The decrease in net cash used results 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 $25.2 million increase
in drilling expenditures in 2004 over 2003. Total 2004 capital expenditures,
including acquisitions of oil and gas properties, decreased $36.6 million or 30
percent to $86.6 million compared to $123.3 million in 2003. An additional $22.9
million of the decrease relates to expiration of the restriction period for
funds held for tax-deferred exchange of oil and gas properties and receipts from
short-term investments.
Financing Activities. The $54.3 million change from cash provided by
financing activities to cash used in financing activities reflects the net $19.4
million we paid to repurchase our shares from Flying J on February 9, 2004 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 $4.9 million more of proceeds from stock option exercises as compared
to 2003.
St. Mary had $27.6 million in cash and cash equivalents and had working
capital of $13.6 million as of June 30, 2004, compared to $14.8 million in cash
and cash equivalents and working capital of $3.1 million as of December 31,
2003.
-28-
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 $205 million for exploration and development expenditures
in 2004. The $100 million we have allocated for acquisitions of producing
properties is dependent on our ability to complete a significant acquisition in
the second half of 2004. 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 $ 87.6 91
o Rocky Mountain region 51.7 77
o ArkLaTex region 23.5 37
o Gulf Coast region 18.4 12
o Coal Bed Methane 14.3 108
o Permian Basin region 10.0 27
--------
$ 205.5
========
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.
Six Months Ended June 30,
--------------------------------------------
2004 2003
------------------- ---------------------
(In thousands)
Development costs $ 67,850 $ 42,164
Exploration costs 15,186 19,176
Acquisitions:
Proved 4,925 77,676
Unproved 4,890 4,096
------------------- ---------------------
Total including asset retirement obligation $ 92,851 $ 143,112
=================== =====================
We are proceeding with the development of coalbed methane reserves in
our Hanging Woman Basin project. We have 154,000 net lease acres in the basin
and are concentrating our initial development on 79,000 net acres located in
Wyoming. Our current development plan for this project considers only the
Wyoming acreage. 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 in 2004 to fund our capital expenditures budget. 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.
-29-
Financing Alternatives
In 2004 we are seeing 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 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.
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
economics of our acquisition. We are hedging a small percentage of our
forecasted production on a discretionary basis.
The table below describes the volumes and average contract prices of
hedges we currently have in place, including hedges entered into after June 30,
2004. The majority of our oil and gas derivatives are swap agreements. Oil and
gas derivatives tend to make our earnings less sensitive to movements in
commodity price and were factored in the analysis of sensitivity below.
-30-
Swaps
-----
Gas (per MMBtu) Oil (per Bbl)
-------------------------------------- -----------------------------------
Weighted-Average Weighted-Average
Contract Contract Price Contract Price
Month Volumes (Regional Index) Volumes (NYMEX)
------------- ----------------------- -------------- -------------------
July 944,700 $ 4.18 172,500 $ 24.65
August 962,000 4.23 172,900 24.81
September 956,600 4.24 178,300 25.38
October 954,100 4.24 176,700 25.38
November 863,800 4.35 174,200 25.39
December 859,600 4.36 172,100 25.40
------------- ----------------------- -------------- -------------------
Total 2004 5,540,800 4.26 1,046,700 25.17
------------- ----------------------- -------------- -------------------
2005
January 242,600 5.69 36,000 31.70
February 242,600 5.69 36,000 31.70
March 242,600 5.69 14,900 35.25
April 242,600 5.69 9,000 39.22
May 179,000 5.76 9,000 39.22
June 25,000 6.12 9,000 39.22
July 25,000 6.12 9,000 39.22
August - - 7,000 39.49
------------- ----------------------- -------------- -------------------
Total 2005 1,199,400 5.72 129,900 34.61
------------- ----------------------- -------------- -------------------
All Contracts 6,740,200 $ 4.52 1,176,600 $ 26.21
============= ======================= ============== ===================
Collars
-------
Gas (per MMBtu)
--------------------------------------------------
Floor Ceiling
Duration Price Price Volumes Index
-------- ----- ----- ------- -----
July 2004 - June 2005 $ 5.75 $ 6.89 25,000 per month IF ANR OK
August 2004 - July 2005 $ 5.50 $ 6.81 25,000 per month IF ANR OK
We anticipate that all hedge transactions will occur as expected.
We seek to minimize basis risk and index our oil hedges to NYMEX prices
and our gas hedges to various regional index prices associated with pipelines in
proximity to our areas of gas production. The natural gas volumes associated
with specific Inside FERC regional indexes are as follows:
Regional Index MMBtu
-------------- -----
IF ANR OK 3,841,200
IF CIG N System 1,261,100
IF Henry Hub 1,037,900
IF Reliant N/S 360,000
IF HSC 240,000
--------------
Total 6,740,200
==============
For contracts in place on June 30, 2004, a hypothetical change of 10
percent in future gas strip prices representing a $0.59 increase per MMBtu
applied to a notional amount of 6.7 million MMBtu covered by natural gas swaps
and 600,000 MMbtu covered by natural gas collars would cause a change in hedge
gain or loss included in gas revenue of $3.2 million in 2004 and $713,000 in
2005. A hypothetical change of 10 percent in the future NYMEX strip oil prices
representing a $3.67 increase per Bbl applied to a notional amount of 1.1 MMBbl
-31-
covered by crude oil swaps would cause a change in hedge gain or loss included
in oil revenue of $3.7 million in 2004 and $214,000 in 2005.
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 June 30, 2004, the interest rate swaps had a fair value liability of
$894,000. Derivative loss in the consolidated statements of operations at June
30, 2004, includes $1.6 million of loss related to the fair value liability
increase. Unless we access our credit facility to make an acquisition or
interest rates increase dramatically, interest expense through September 2004
should decrease compared to last year due to these fixed-to-floating interest
rate swaps.
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 1 More than 5
Contractual Obligations year 1-3 years 3-5 years years Total
---------------------------------------------- ----------- ----------- ----------- ------------ ---------
Long-Term Debt Principal and Interest $ 6.0 $ 112.5 $ - $ - $ 118.5
Operating Leases 2.4 3.3 1.9 2.7 10.3
Other Long-Term Liabilities - 1.7 0.2 0.3 2.2
----------- ----------- ----------- ------------ ---------
Total $ 8.4 $ 117.5 $ 2.1 $ 3.0 $ 131.0
=========== =========== =========== ============ =========
This table excludes the unfunded portion of our estimated pension
liability of $2.1 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 Form 10-K for the
year ended December 31, 2003, and also in Part I Item 1 of this report.
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 $3.1 million and $1.5 million, respectively. We will
also make 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.
-32-
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.
Additional Comparative Data in Tabular Form:
Change Between the Change Between the
Three Months Ended Six Months Ended
Oil and Gas Production Revenues June 30, 2004 and 2003 June 30, 2004 and 2003
------------------------------- ------------------------- --------------------------
Decrease in oil and gas production revenues
(in thousands) $ (687) $ (3,768)
Components of Revenue Increases (Decreases):
Natural Gas
-----------
Realized price change per Mcf $ 0.57 $ 0.10
Realized price percentage change 12% 2%
Production change (MMcf) (2,544) (2,635)
Production percentage change (19)% (10)%
Oil
---
Realized price change per Bbl $ 4.58 $ 2.18
Realized price percentage change 17% 8%
Production change (MBbl) (2) 97
Production percentage change -0-% 4%
Our product mix as a percentage of total oil and gas revenue and production:
Three Months Ended June 30, Six Months Ended June 30,
------------------------------------ -------------------------------------
Revenue 2004 2003 2004 2003
------- ----------------- --------------- ----------------- ----------------
Natural Gas 63% 68% 64% 69%
Oil 37% 32% 36% 31%
Production
----------
Natural Gas 61% 66% 62% 66%
Oil 39% 34% 38% 34%
Information regarding the effects of oil and gas hedging activity:
Three Months Ended June 30, Six Months Ended June 30,
------------------------------------ -----------------------------------
Natural Gas Hedging 2004 2003 2004 2003
------------------- ---------------- ---------------- ----------------- --------------
Percentage of gas production hedged 20% 39% 26% 35%
Natural gas MMBtu hedged 2.5 million 5.9 million 6.5 million 9.7 million
Decrease in gas revenue ($4.0 million) ($2.9 million) ($7.1 million) ($9.8 million)
Average realized gas price per Mcf
before hedging $ 5.75 $ 5.03 $ 5.61 $ 5.59
Average realized gas price per Mcf
after hedging 5.39 4.82 5.30 5.20
Oil Hedging
-----------
Percentage of oil production hedged 45% 57% 43% 57%
Oil volumes hedged (MBbl) 519 661 982 1,262
Decrease in oil revenue ($1.7 million) ($1.3 million) ($7.2 million) ($5.2 million)
Average realized oil price per Bbl
before hedging $ 32.26 $ 27.30 $ 32.62 $ 29.69
Average realized oil price per Bbl
after hedging 30.78 26.20 29.50 27.32
-33-
Information regarding the components of exploration expense:
Three Months Ended June 30, Six Months Ended June 30,
-------------------------------- -------------------------------
Summary of Exploration Expense (In millions) 2004 2003 2004 2003
-------------------------------------------- -------------- -------------- ------------- --------------
Geological and geophysical expenses $ 1.4 $ 2.3 $ 2.2 $ 3.7
Exploratory dry holes 1.1 0.7 1.2 1.1
Overhead and other expenses 4.1 3.3 7.8 5.6
-------------- -------------- ------------- --------------
$ 6.6 $ 6.3 $ 11.2 $ 10.4
============== ============== ============= ==============
Comparison of Financial Results and Trends between the Quarters ended June 30, 2004 and 2003
Oil and gas production revenues. Average net daily production decreased
12 percent to 198.2 MMCFE for the quarter ended June 30, 2004 compared with
226.3 MMCFE for the quarter ended June 30, 2003. Wells completed in 2003 and
2004 combined with wells from acquisitions in 2003 and 2004 have added revenue
of $21.3 million and average net daily production of 30.2 MMCFE in 2004 compared
to 2003. These increases are offset by natural declines in production from older
properties and 5.7 MMCFE per day of 2003 production from properties that were
sold in 2003.
Gain on sale of proved properties. In the second quarter of 2004 we
finalized sales of properties sold in 2003 and recognized $1.6 million
additional gain.
Other oil and gas revenue. Other oil and gas revenue increased $800,000
to $1.4 million for the quarter ended June 30, 2004, compared with $595,000 for
the comparative quarter ended June 30, 2003. In 2004 we received $900,000 for
the use of our fee property.
Other revenue. The second quarter of 2003 included $3.6 million from
proceeds of a litigation settlement.
Oil and gas production expenses. Total production costs decreased $1.7
million, or 7 percent, to $21.6 million for the second quarter of 2004, from
$23.3 million in the comparable period of 2003. Wells completed in 2003 and 2004
combined with wells from acquisitions in 2003 and 2004 added $868,000 of
incremental production costs in 2004 that were not reflected in 2003. This
moderate increase in production costs relative to added revenue reflects the
benefit of the second quarter 2004 accrual of severance tax incentive credits
for wells completed in 2003 and 2004. Production costs from properties sold in
2003 totaled $897,000 in 2003 that were not reflected in 2004. We experienced an
increase in production taxes consistent with an increase in revenue from crude
oil, but those amounts were more than offset by the June 2004 accrual of $3.1
million in state severance tax incentive credits.
Total oil and gas production costs per MCFE increased $0.07 to $1.20
for 2004, compared with $1.13 for 2003. This increase is comprised of the
following:
o A $0.08 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;
o A $0.01 decrease reflecting general decreases in LOE per MCFE
in our other core areas;
o A $0.09 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;
o A $0.04 overall increase in LOE relating to workover charges;
and
o Offset by a $0.16 decrease in our Mid-Continent region
production taxes caused by the severance tax incentive credit
accrual.
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
-34-
the plan. The increase in the estimated liability resulted in expense of $4.3
million for the three months ended June 30, 2004 compared to $924,000 for the
same three months of 2003.
General and administrative. General and administrative expenses
decreased slightly to $5.4 million for the quarter ended June 30, 2004, compared
with $5.5 million for the respective 2003 timeframe. The increase in expense on
a per MCFE basis reflects lower volumes in 2004.
The increase in our employee count from March of 2003 to June of 2004
has resulted in a small increase in general and administrative expense of
$451,000 between the second quarter of 2004 and the second quarter of 2003. That
increase plus a $728,000 increase in fees directly related to Sarbanes-Oxley
compliance were offset by a $952,000 increase in the amount of general and
administrative expense we allocated to exploration expense and a $741,000
decrease in expense associated with our incentive compensation plans. The
decrease in expense associated with our incentive compensation plans results
from a $1.1 million decrease in payments under our net profits interest bonus
plan and a $1.7 million decrease in accruals under our cash bonus plans that
reflects the production decline in 2004. The impact of these two items is
reduced by the $2.1 million of expense we recorded from the restricted stock
unit issuance that occurred on June 30, 2004.
Interest expense. Interest expense decreased by $802,000 to $1.6
million for 2004 compared to $2.4 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 $13.4 million for the second
quarter of 2004 and $15.7 million for the second quarter of 2003, resulting in
effective tax rates of 38.1 % and 39.2%, 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.
Comparison of Financial Results and Trends between the Six Months ended June 30,
2004 and 2003
Oil and gas production revenues. Average net daily production decreased
6 percent to 200.6 MMCFE for the six months ended June 30, 2004 compared with
213.0 MMCFE for the six months ended June 30, 2003. Wells completed in 2003 and
2004 combined with wells from acquisitions in 2003 and 2004 have added revenue
of $44.4 million and average net daily production of 40.1 MMCFE in 2004 compared
to 2003. These increases are offset by natural declines in production from older
properties and 4.4 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 six months ended June 30, 2003 included $3.6 million
from proceeds of a litigation settlement.
Oil and gas production expenses. Total production costs increased
slightly to $45.1 million for the first six months of 2004 from $44.4 million in
the comparable period of 2003. Wells completed in 2003 and 2004 combined with
wells from acquisitions in 2003 added $4.9 million of incremental production
costs in 2004 that were not reflected in 2003. Production costs from properties
sold in 2003 totaled $1.3 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 more than offset by
the June 2004 accrual of $3.1 million in state severance tax incentive credits.
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Total oil and gas production costs per MCFE increased $0.09 to $1.24
for 2004, compared with $1.15 for 2003. This increase is comprised of the
following:
o A $0.05 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 decrease reflecting general decreases in LOE per MCFE
in our other core areas;
o A $0.09 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;
o A $0.02 overall increase in LOE relating to workover charges;
and
o Offset by an $0.08 decrease in our Mid-Continent region
production taxes caused by the severance tax incentive credit
accrual.
Change in net profits interest bonus plan liability. This expense
increased $4.8 million to $6.5 million for the six months ended June 30, 2004
compared to $1.7 million for the same six 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 and costs.
General and administrative. General and administrative expenses
increased slightly to $11.0 million for the six months ended June 30, 2004,
compared with $10.8 million for the respective 2003 timeframe. The increase in
cost on a per MCFE basis reflects the 6 percent difference between a 1 percent
increase in general and administrative expense and a 5 percent decrease in
production between the respective periods.
The increase in employee count has resulted in an increase in general
and administrative expense of $2.6 million between the first six months of 2004
and the first six months of 2003. We also experienced a $756,000 increase in
fees directly related to Sarbanes-Oxley compliance. Those increases were offset
by a $959,000 decrease in expense associated with our incentive compensation
plans and a $2.4 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 $1.6 million
decrease in accruals under our cash bonus plan that reflects the production
decline in 2004. The impact of these two items is reduced by the $2.1 million of
expense we recorded from 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 $1.5 million to $3.1
million for 2004 compared to $4.6 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 $26.5 million for the first
six months of 2004 and $32.7 million for the first six months of 2003, resulting
in effective tax rates of 38.0 % and 38.8%, respectively. The effective rate
change from 2003 reflects changes in the composition of the highest marginal
state tax rates as a result of acquisition and drilling activity, percentage
depletion and other permanent differences.
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The current portion of the income tax expense in 2004 is $13.4 million
compared to $21.9 million in 2003. These amounts are 51 percent and 66 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. Therefore, we 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.
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 report 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,
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 has appealed this decision and the Ninth Circuit Court of Appeals has
granted expedited status to this appeal. Briefing in this case is now complete.
We have no current indications as to when the Ninth Circuit Court of Appeals
will render a decision. Notwithstanding our success in the lower 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 leases in Montana become unavailable, we are proceeding with this
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project on non-federal leases in Wyoming, and we anticipate acquiring additional
non-federal leases in Montana and Wyoming.
ITEM 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
(c) In May 2004, St. Mary issued a total of 8,400 restricted shares of
common stock valued at $235,000 from treasury to non-employee directors
pursuant to the Company's non-employee director stock compensation
plan. These shares were not registered under the Securities Act of 1933
in reliance on Rule 506 of Regulation D promulgated under the
Securities Act since the directors are accredited investors and
certificates representing the shares bear a legend restricting the
transfer of those shares.
(e) During the quarter ended June 30, 2004, the Company did not repurchase
any shares of its common stock, which is the sole class of equity
securities registered by the Company pursuant to Section 12 of the
Exchange Act.
ITEM 4. Submission of Matters to a Vote of Security Holders
At the Company's annual stockholders' meeting on May 26, 2004, the
stockholders elected management's current slate of directors. The directors
elected and the vote tabulation for each director are as follows:
Director For Withheld
-------- --- ---------
Barbara M. Baumann 25,469,260 375,625
Larry W. Bickle 25,430,704 414,181
Ronald D. Boone 25,537,923 306,962
Thomas E. Congdon 25,553,593 291,292
William J. Gardiner 25,446,871 398,014
Mark A. Hellerstein 25,553,223 291,662
John M. Seidl 25,429,704 415,181
William D. Sullivan 25,594,327 250,558
Also at the Company's annual stockholders' meeting on May 26, 2004, the
stockholders approved the Company's restricted stock plan to provide for the
grant of restricted stock and restricted stock unit awards to employees,
consultants and directors of the Company. The tabulation of votes for that
proposal is as follows:
For 19,323,384
Against 1,294,690
Abstain 903,503
Not voted 4,323,308
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ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
The following exhibits are furnished as part of this report:
Exhibit Description
10.1 St. Mary Land & Exploration Company Restricted Stock Plan
as adopted on April 18, 2004 (filed as Exhibit 99.1 to the
registrant's Post-Effective Amendment No. 1 to Form S-8
(Registration Nos. 333-30055, 333-35352, 333-88780 and
333-106438) filed on June 30, 2004 and incorporated herein by
reference)
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.
(b) Reports on Form 8-K
St. Mary Land & Exploration Company filed the following current
reports on Form 8-K during the quarter ended June 30, 2004:
On April 22, 2004, we filed a current report on Form 8-K reporting under Item 9
that we had issued a press release announcing a regular semi-annual $0.05 per
share cash dividend.
On April 30, 2004, we filed a current report on Form 8-K reporting under Item 12
that we had issued a press release announcing our first quarter 2004 financial
results.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
August 4, 2004 By: /s/ MARK A. HELLERSTEIN
------------------------------------------
Mark A. Hellerstein
President and Chief Executive Officer
August 4, 2004 By: /s/ DAVID W. HONEYFIELD
------------------------------------------
David W. Honeyfield
Vice President - Finance, Secretary
and Treasurer
August 4, 2004 By: /s/ GARRY A. WILKENING
------------------------------------------
Garry A. Wilkening
Vice President - Administration and
Controller