Back to GetFilings.com
================================================================================
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, 2003
------------
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 in Rule 12b-2 of the Exchange Act). Yes [ |X| ] No [ ]
Indicate the number of shares outstanding of each of the registrant's classes of
common stock as of the latest practicable date.
As of August 8, 2003, the registrant had 31,525,297 shares of common stock, $.01
par value, outstanding.
================================================================================
ST. MARY LAND & EXPLORATION COMPANY
---------------------------------------
INDEX
-----
Part I. FINANCIAL INFORMATION PAGE
----
Item 1. Financial Statements (Unaudited)
Consolidated Balance
Sheets - June 30, 2003 and
December 31, 2002 ........................................3
Consolidated Statements of
Operations - Three and Six Months Ended
June 30, 2003 and 2002 ...................................4
Consolidated Statements of
Cash Flows - Six Months Ended
June 30, 2003 and 2002 ...................................5
Consolidated Statements of
Stockholders' Equity and
Comprehensive Income - June 30,
2003 and December 31, 2002 ...............................7
Notes to Consolidated Financial
Statements - June 30, 2003 ...............................8
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations ...........................................15
Item 3. Quantitative and Qualitative Disclosures
About Market Risk .......................................29
Item 4. Controls and Procedures .................................30
Part II. OTHER INFORMATION
Item 1. Legal Proceedings .......................................30
Item 4. Submission of Matters to a Vote of Security Holders .....31
Item 6. Exhibits and Reports on Form 8-K ........................31
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 2003 2002
------------ ------------
Current assets:
Cash and cash equivalents $ 10,846 $ 11,154
Short term investments 2,281 1,933
Accounts receivable 57,952 35,399
Prepaid expenses and other 6,684 6,510
Accrued derivative asset 288 -
Refundable income taxes - 1,031
Deferred income taxes 8,204 3,520
------------ ------------
Total current assets 86,255 59,547
------------ ------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 806,587 683,752
Less accumulated depletion, depreciation and amortization (283,828) (263,436)
Unproved oil and gas properties, net of impairment
allowance of $9,838 in 2003 and $8,865 in 2002 65,350 47,984
Other property and equipment, net of accumulated depreciation
of $4,026 in 2003 and $3,586 in 2002 4,263 3,639
------------ ------------
Total property and equipment 592,372 471,939
------------ ------------
------------ ------------
Other noncurrent assets 6,577 5,653
------------ ------------
------------ ------------
Total Assets $ 685,204 $ 537,139
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 63,050 $ 48,790
Accrued hedge liability 21,239 8,707
------------ ------------
Total current liabilities 84,289 57,497
------------ ------------
Noncurrent liabilities:
Long-term credit facility 44,000 14,000
Convertible notes 99,649 99,601
Deferred income taxes 71,538 60,156
Asset retirement obligation liability 24,603 -
Other noncurrent liabilities 12,375 5,727
------------ ------------
Total noncurrent liabilities 252,165 179,484
------------ ------------
Commitments and contingencies
------------ ------------
Minority interest 562 645
------------ ------------
Temporary equity (Note 8):
Common stock subject to put and call options, $0.01 par value
issued and outstanding - 3,380,818 shares in 2003 and -0-
shares in 2002 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 - 29,147,179 shares in 2003 and 28,983,110
shares in 2002; outstanding, net of treasury shares -
28,144,479 shares in 2003 and 27,973,210 shares in 2002 291 290
Additional paid-in capital 143,662 140,688
Treasury stock - at cost: 1,002,700 shares in 2003 and 1,009,900
shares in 2002 (16,057) (16,210)
Retained earnings 238,053 182,512
Accumulated other comprehensive income (loss) (17,761) (7,767)
------------ ------------
Total stockholders' equity 348,188 299,513
------------ ------------
------------ ------------
Total Liabilities, Temporary Equity and Stockholders' Equity $ 685,204 $ 537,139
============ ============
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,
--------------------------- ---------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Operating revenues:
Oil and gas production $ 96,134 $ 46,197 $ 191,822 $ 87,290
Gain on sale of proved properties 86 449 122 413
Marketed gas system revenue 3,333 2,939 7,108 3,444
Other oil and gas revenue 595 397 2,040 747
Derivative gain - 2,327 33 1,975
Other revenues 3,638 46 3,783 907
------------ ------------ ------------ ------------
Total operating revenues 103,786 52,355 204,908 94,776
------------ ------------ ------------ ------------
Operating expenses:
Oil and gas production 23,260 11,531 44,390 25,561
Depletion, depreciation and amortization 21,601 13,279 40,486 26,333
Exploration 6,635 4,297 10,785 11,213
Abandonment and impairment of unproved properties 784 622 1,703 1,319
General and administrative 6,018 3,015 12,164 6,156
Derivative loss 82 - - -
Marketed gas system operating expense 3,098 2,662 6,457 3,086
Minority interest and other 299 243 495 620
------------ ------------ ------------ ------------
Total operating expenses 61,777 35,649 116,480 74,288
------------ ------------ ------------ ------------
Income from operations 42,009 16,706 88,428 20,488
Nonoperating income (expense):
Interest income 344 170 574 280
Interest expense (2,367) (1,018) (4,583) (1,470)
------------ ------------ ------------ ------------
Income before income taxes and cumulative effect of change
in accounting principle 39,986 15,858 84,419 19,298
Income tax expense 15,669 5,269 32,740 6,391
------------ ------------ ------------ ------------
Income before cumulative effect of change in accounting principle 24,317 10,589 51,679 12,907
Cumulative effect of change in accounting principle, net - - 5,435 -
------------ ------------ ------------ ------------
Net income $ 24,317 $ 10,589 $ 57,114 $ 12,907
============ ============ ============ ============
Basic earnings per common share:
Income before cumulative effect of change in accounting principle $ 0.77 $ 0.38 $ 1.67 $ 0.46
Cumulative effect of change in accounting principle - - 0.18 -
------------ ------------ ------------ ------------
Basic net income per common share $ 0.77 $ 0.38 $ 1.85 $ 0.46
============ ============ ============ ============
Diluted earnings per common share:
Income before cumulative effect of change in accounting principle $ 0.71 $ 0.37 $ 1.52 $ 0.46
Cumulative effect of change in accounting principle - - 0.15 -
------------ ------------ ------------ ------------
Diluted net income per common share $ 0.71 $ 0.37 $ 1.67 $ 0.46
============ ============ ============ ============
Basic weighted average common shares outstanding 31,482 27,825 30,921 27,805
============ ============ ============ ============
Diluted weighted average common shares outstanding 35,798 28,428 35,222 28,347
============ ============ ============ ============
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,
---------------------------
Reconciliation of net income to net cash provided 2003 2002
by operating activities: ------------ ------------
Net income $ 57,114 $ 12,907
Adjustments to reconcile net income to net
cash provided by operating activities:
Gain on sale of proved properties (122) (413)
Depletion, depreciation and amortization 40,486 26,333
Exploratory dry hole expense 1,142 6,133
Abandonment and impairment of unproved properties 1,703 1,319
Unrealized derivative gain (33) (1,975)
Deferred income taxes 10,886 4,989
Minority interest and other 879 (548)
Cumulative effect of change in accounting principle, net of tax (5,435) -
------------ ------------
106,620 48,745
Changes in current assets and liabilities:
Accounts receivable (22,553) 12,490
Prepaid expenses and other (174) 8,436
Refundable income taxes 1,031 -
Accounts payable and accrued expenses 5,840 6,399
------------ ------------
Net cash provided by operating activities 90,764 76,070
------------ ------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 2,635 122
Capital expenditures (45,600) (42,577)
Acquisition of oil and gas properties, including $71,594 note
receivable issued to Flying J (77,677) (13,643)
Proceeds from distribution and sale of KMOC stock - 3,114
Deposits to short term investments available-for-sale (1,029) -
Proceeds from short term investments available-for-sale 950 (9,370)
Other 102 (2,122)
------------ ------------
Net cash used in investing activities (120,619) (64,476)
------------ ------------
Cash flows from financing activities:
Proceeds from credit facility 108,811 16,000
Repayment of credit facility (79,820) (80,000)
Proceeds (costs) from issuance of convertible notes (73) 96,754
Proceeds from sale of common stock 2,202 783
Dividends paid (1,573) (1,391)
------------ ------------
Net cash provided by financing activities 29,547 32,146
------------ ------------
Net change in cash and cash equivalents (308) 43,740
Cash and cash equivalents at beginning of period 11,154 4,116
------------ ------------
Cash and cash equivalents at end of period $ 10,846 $ 47,856
============ ============
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,
---------------------------
2003 2002
------------ ------------
In thousands)
Cash paid for interest, including amounts capitalized $ 4,851 $ 478
Cash paid (received) for income taxes 16,275 (8,699)
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 shares of restricted common
stock valued at $71,594,000 to Flying J Oil & Gas Inc. and Big West Oil &
Gas Inc. in exchange for oil and gas properties and related assets and
liabilities. The acquisition was accounted for as a purchase.
In June 2002 the Company issued 800 shares of common stock to a
non-employee director and recorded compensation expense of $14,763.
In April 2002 the Company accepted 9,472,562 shares of common stock in
Constellation Copper Corporation ("Constellation", formerly known as Summo
Minerals Corporation) in lieu of cash payment for the relief of a
$1,400,000 loan and $15,311 in interest due to the Company.
In January 2002 the Company issued 7,200 shares of common stock to its
non-employee directors and recorded compensation expense of $129,683.
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
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock Other Total
------------------ Paid-in Retained -------------------- Comprehensive Stockholders'
Shares Amount Capital Earnings Shares Amount Income (Loss) Equity
---------- ------- ---------- ---------- ---------- --------- ------------- -------------
---------- ------- ---------- ---------- ---------- --------- ------------- -------------
Balances, December 31, 2001 28,779,808 $ 288 $ 137,384 $ 157,739 (1,009,900) $(16,210) $ 6,916 $ 286,117
---------- ------- ---------- ---------- ---------- --------- ------------- -------------
Comprehensive income:
Net Income - - - 27,560 - - - 27,560
Unrealized net loss on marketable
equity securities available
for sale - - - - - - (725) (725)
Change in derivative instrument
fair value - - - - - - (14,644) (14,644)
Reclass to earnings - - - - - - 1,447 1,447
Minimum pension liability adjustment - - - - - - (761) (761)
------------- -------------
Total comprehensive income 12,877
-------------
Cash dividends, $ 0.10 per share - - - (2,787) - - - (2,787)
Issuance for Employee Stock Purchase
Plan 18,217 - 344 - - - - 344
ESPP disqualified distribution - - 21 - - - - 21
Sale of common stock, including income
tax benefit of stock option
exercises 177,085 2 2,743 - - - - 2,745
Accelerated vesing of retiring
director options - - 52 - - - - 52
Directors' stock compensation 8,000 - 144 - - - - 144
---------- ------- ---------- ---------- ---------- --------- ------------- -------------
Balances, December 31, 2002 28,983,110 $ 290 $ 140,688 $ 182,512 (1,009,900) $(16,210) $ (7,767) $ 299,513
---------- ------- ---------- ---------- ---------- --------- ------------- -------------
Comprehensive income:
Net Income - - - 57,114 - - - 57,114
Unrealized net loss on marketable
equity securities available
for sale - - - - - - 303 303
Change in derivative instrument
fair value - - - - - - (25,351) (25,351)
Reclass to earnings - - - - - - 15,054 15,054
-------------
Total comprehensive income 47,120
-------------
Cash dividends, $ 0.05 per share - - - (1,573) - - - (1,573)
Issuance for Employee Stock Purchase
Plan 10,018 - 213 - - - - 213
Sale of common stock, including income
tax benefit of stock option
exercises 154,051 1 2,761 - - - - 2,762
Directors' stock compensation - - - - 7,200 153 - 153
---------- ------- ---------- ---------- ---------- --------- ------------- -------------
Balances, June 30, 2003 29,147,179 $ 291 $ 143,662 $ 238,053 (1,002,700) $(16,057) $ (17,761) $ 348,188
========== ======= ========== ========== ========== ========= ============= =============
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, 2003
Note 1 - Basis of Presentation
The accompanying unaudited condensed consolidated financial statements of
St. Mary Land & Exploration Company and Subsidiaries ("St. Mary" or the
"Company") 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, 2002. In the opinion of management,
all adjustments (consisting of normal recurring accruals) considered necessary
for a fair presentation 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 accounting policies followed by the Company are set forth in Note 1 to
the Company's consolidated financial statements in the Form 10-K for the year
ended December 31, 2002. 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.
Note 2 - Earnings Per Share
Basic net income per common share of stock is calculated by dividing net
income 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 (see Note 8). These shares are considered
outstanding for purposes of calculating basic and diluted net income per common
share and are weighted accordingly in the calculation of common shares
outstanding. Additionally, these shares are included in the temporary equity
section of the accompanying consolidated balance sheets. Following is a
reconciliation of total shares outstanding as of June 30, 2003.
Common shares outstanding in Stockholders' equity 28,144,479
Common shares outstanding in Temporary equity 3,380,818
--------------
Total common shares outstanding 31,525,297
==============
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 subtracting interest expense paid on
the Company's 5.75% Senior Convertible Notes due 2022 (the "Convertible Notes")
from 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 that were issued in 2002 may be
converted, and incremental shares that would be issued under the
reverse-treasury method assumptions if the put option described in Note 8 is
exercised.
The treasury stock method is used to measure the dilutive impact of stock
options. The following table details the weighted-average dilutive and
anti-dilutive securities related to stock options for the periods presented.
-8-
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Dilutive 469,911 439,904 454,483 403,839
Anti-dilutive 615,190 628,416 614,181 684,016
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.
Potentially dilutive shares of 3,846,153 related to the Convertible Notes were
included in the calculation of diluted net income per share for the three and
six months ended June 30, 2003. The Convertible Notes were issued in March 2002.
Shares related to the put option that was granted on January 29, 2003, are
accounted for using the reverse-treasury method. There is no dilutive effect for
the put option in the current quarter or year to date as the average market
value of the Company's stock exceeded the strike price of the put option.
Note 3 - Compensation Plans
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 is
reflected in net income as all options granted under those 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 (in thousands,
except per share amounts).
For the Three Months For the Six Months
Ended June 30, Ended June 30,
--------------------- ---------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Net income
As reported $ 24,317 $ 10,589 $ 57,114 $ 12,907
Pro forma 22,046 8,844 54,543 10,723
Basic earnings per share
As reported $ 0.77 $ 0.38 $ 1.85 $ 0.46
Pro forma 0.70 0.32 1.76 0.39
Diluted earnings per share
As reported $ 0.71 $ 0.37 $ 1.67 $ 0.46
Pro forma 0.64 0.31 1.60 0.38
For purposes of 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. Additional awards in future years are
anticipated.
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair values of options granted in 2003
and 2002 were estimated using the following weighted-average assumptions.
-9-
For the Three Months For the Six Months
Ended June 30, Ended June 30,
--------------------- ---------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Risk free interest rate 3.37% 4.29% 3.05% 4.33%
Dividend yield 0.38% 0.42% 0.39% 0.44%
Volatility factor of the
expected market price of
the Company's common
stock 49.50% 45.35% 48.41% 46.73%
Expected life of the options
(in years) 7.7 6.8 6.3 6.4
Note 4 - Income Taxes
Income tax expense for the three and six months ended June 30, 2003 and
2002 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, Internal Revenue Code
Section 29 credits, valuation allowance adjustments against prior year credits,
and changes in the composition of income tax rates. For the three and six months
ended June 30, 2003, the Company's current portion of income tax expense was
$10,536,000 and $21,854,000, respectively, compared to $197,000 and $1,402,000
for the same respective periods in 2002.
Note 5 - Long-term Debt
In January 2003 the Company entered into a new long-term revolving credit
agreement with a group of banks that replaced the prior credit agreement dated
June 30, 1998. The new credit agreement specifies a maximum loan amount of
$300,000,000 and has a maturity date of January 27, 2006. Borrowings under the
facility are secured by a pledge of collateral against certain oil and gas
properties in favor of the lenders and by common stock of material subsidiaries
of the Company. The borrowing base is currently $275,000,000 and is subject to
periodic re-determination by the lenders based on the value of St. Mary's oil
and gas properties and other assets, as determined by the bank syndicate. We
have elected an aggregate commitment amount of $150,000,000 as of June 30, 2003.
The Company must comply with certain financial and non-financial covenants.
Interest and commitment fees are accrued based on the borrowing base utilization
percentage table below. 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.
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%
At June 30, 2003, the Company's borrowing base utilization percentage as
defined under the credit agreement was 29%. The Company had $44,000,000 in
Eurodollar loans and no ABR loans outstanding under its revolving credit
agreement as of June 30, 2003.
As of June 30, 2003, the Company also had $100,000,000 in outstanding
borrowings under the Convertible Notes due 2022. The Convertible Notes carry a
-10-
contingent interest provision of 0.5% based on the note price in effect over a
period of time. Accordingly, interest was accrued at a rate of 6.25% for the
quarter and six-month periods ended June 30, 2003.
The weighted average interest rates paid for the second quarter of 2003 and
for the six months ended June 30, 2003 were 6.2% and 5.9%, respectively,
including 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.
Note 6 - Derivative Financial Instruments
The Company realized a net loss of $15,069,000 from its derivative
contracts for the six months ended June 30, 2003, and a net gain of $5,460,000
for the six months ended June 30, 2002. Comparative amounts for the three months
ended June 30, 2003 and 2002 were a net loss of $4,522,000 and a net gain of
$1,981,000, respectively.
The Convertible Notes contain a provision for payment of contingent
interest if certain conditions are met. Under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," this provision 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 treated 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, $48,000 and $28,000 was amortized through interest expense for the
six-month periods ended June 30, 2003 and 2002, respectively. Interest expense
for each of the three-month periods ended June 30, 2003 and 2002 includes
$24,000 of amortization. Derivative gain in the consolidated statements of
operations for the six-month periods ended June 30, 2003 and 2002 includes net
losses of $14,000 and $322,000, respectively, from mark-to-market adjustments
for this derivative. Derivative loss for the three months ended June 30, 2003,
contains $141,000 of net loss from mark-to-market adjustments and derivative
gain for the three months ended June 30, 2002 contains $202,000 of net loss.
The Company's previous fixed-rate to floating-rate interest rate swap on
$50,000,000 of the Convertible Notes did not qualify for cash flow or fair value
hedge accounting treatment under SFAS No. 133. This contract was entered into on
March 25, 2002, and was closed out on December 3, 2002. Derivative gain in the
consolidated statement of operations for the period ended June 30, 2002,
includes $2,244,000 of net unrealized mark-to-market gain from the interest rate
swap contract.
The Company has in place derivative contracts for the sale of oil and
natural gas. These contracts include traditional swap and collar arrangements.
The Company attempts to qualify the majority of these instruments as cash flow
hedges for accounting purposes.
-11-
The following table summarizes all derivative instrument activity (in
thousands).
For the Three Months Ended For the Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Gain (Loss) Gain (Loss)
Derivative contract settlements included in
oil and gas production revenues $(4,416) $ (322) $(15,054) $3,513
Ineffective portion of hedges qualifying for
hedge accounting included in derivative loss 60 133 47 54
Non-qualified derivative contracts included
in derivative gain (loss) (142) 2,194 (14) 1,921
Amortization of contingent interest derivative
through interest expense (24) (24) (48) (28)
------------ ------------ ------------ ------------
Total $(4,522) $ 1,981 $(15,069) $5,460
============ ============ ============ ============
On June 30, 2003, St. Mary's cash flow hedges resulted in a net pre-tax
liability of $27,490,000. The Company will reclassify $27,380,000 of this amount
to gains or losses included in oil and gas production operating revenues as the
hedged production quantity is produced. The remaining amount relates to an
undesignated collar that will be marked to market through the statement of
operations until it expires on December 31, 2003. Based on current prices the
net amount of existing unrealized after-tax loss as of June 30, 2003, to be
reclassified from accumulated other comprehensive income to oil and gas
production operating revenues in the next twelve months would be $16,587,000,
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 7 - 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 fair value of an asset retirement obligation with a corresponding increase
to the carrying value of the related long-lived asset is recorded at the time a
well is completed or acquired. The Company depletes the amount added to proved
oil & 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, external estimates as to the cost to abandon
the wells in the future and federal and state regulatory requirements. The
-12-
liability is discounted using a credit-adjusted risk-free rate of approximately
7.25%. Revisions to the liability could occur due to changes in estimated
abandonment costs or well economic lives, or if federal or state regulators
enact new requirements regarding the abandonment of wells.
Upon adoption of SFAS No. 143, the Company recorded a discounted liability
of $21,403,000, reversed the existing offshore abandonment liability of
$9,144,000, increased property and equipment by $12,827,000, decreased
accumulated DD&A by $8,280,000 and recognized a one-time cumulative effect
gain of $5,435,000 (net of deferred tax benefit of $3,414,000). The Company
depletes the amount added to property costs and recognizes accretion expense in
connection with the discounted liability over the remaining economic lives of
the respective oil and gas properties.
As of June 30, 2003, the Company's capitalized proved oil and gas
properties included $42,991,000 of estimated salvage value, which is excluded
from the Company's DD&A calculation.
A reconciliation of the Company's liability for the three and six months
ended June 30, 2003, is as follows (in thousands).
Three Months Ended Six Months Ended
June 30, 2003 June 30, 2003
------------------ ------------------
Beginning Asset Retirement Obligation $ 23,734 $ -
Liability from SFAS 143 adoption - 21,403
Liabilities incurred 956 2,892
Liabilities settled (530) (530)
Accretion expense 443 838
------------------ ------------------
Ending Asset Retirement Obligation $ 24,603 $ 24,603
================== ==================
The following tables illustrate the effect on the asset retirement
obligation liability, net income and earnings per share if the Company had
adopted the provisions of SFAS No. 143 on January 1, 2002. The pro forma amounts
of the liability are measured using current information, assumptions and
interest rates as of January 1, 2003 (in thousands, except per share amounts).
January 1, 2002 December 31, 2002
-------------------- -------------------
Asset retirement
obligation liability $20,358 $21,829
Three Months Ended Six Months Ended
June 30, 2002 June 30, 2002
-------------------- -------------------
Net Income
As reported $10,589 $12,907
Pro forma $10,359 $12,436
Basic EPS
As reported $ 0.38 $ 0.46
Pro forma $ 0.37 $ 0.45
Diluted EPS
As reported $ 0.37 $ 0.46
Pro forma $ 0.36 $ 0.45
-13-
Note 8 - Flying J Acquisition
On January 29, 2003, the Company acquired oil and gas properties from
Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. (collectively,
"Flying J"). St. Mary issued 3,380,818 shares of its restricted common stock
valued at $71,594,000 for proved reserves and unproved acreage, $445,000 of
other assets, a $1,936,000 asset retirement liability, a $2,012,000 hedge
liability, and $3,861,000 in cash received for net purchase price adjustments.
In addition, St. Mary made a non-recourse loan to Flying J and Big West of
$71,594,000 at LIBOR plus 2% for up to a 39-month period that is secured by a
pledge of the shares of St. Mary common stock issued to Flying J. During the
39-month loan period Flying J and Big West can elect to put their shares of St.
Mary stock to the Company for $71,594,000 plus accrued interest on the loan for
the first thirty months, and St. Mary can elect to call the shares for an amount
of $97,447,000, with the proceeds applied to the repayment of the loan and
accrued interest. The acquisition was accounted for using the purchase method of
accounting. Operating results from the acquired properties have been included in
the statements of operations only from the date of closing.
The common stock that was issued in this transaction has been recorded as
temporary equity because the Company can be required to repurchase these shares.
The shares of common stock are considered outstanding for basic and diluted
earnings per share calculations. These shares could potentially become part of
permanent stockholders' equity in the future. The loan arising from this
transaction is considered a contra-temporary equity item on the consolidated
balance sheets, as opposed to an asset, since the loan is secured by the common
stock issued as part of this transaction. Since the loan is considered to be
contra-equity and because there are uncertainties related to how the loan will
be repaid, no interest revenue will be recorded in connection with the loan
until the Company receives such interest. At June 30, 2003, the cumulative
amount of interest receivable but not recorded as income was $1,029,000.
Note 9 - Recently Issued Accounting Standards
In May 2003 the Financial Accounting Standards Board ("FASB") issued SFAS
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity." This Statement establishes standards for how an
issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity and requires that such financial
instruments be classified as a liability (or as an asset in certain
circumstances). SFAS No. 150 is effective for all freestanding instruments
entered into or modified after May 31, 2003. Otherwise, it became effective for
the Company as of July 1, 2003. St. Mary currently has no financial instruments
that fall within the scope of SFAS No. 150. As a result, the adoption of this
Statement is not expected to have an impact on the Company's financial position
or results of operations.
In April 2003 the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement amends and
clarifies technical aspects of financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This Statement is effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003.
The FASB and representatives of the accounting staff of the Securities and
Exchange Commission are currently engaged in discussions regarding the
application of certain provisions of SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the
extractive industries, including oil and gas companies. The FASB and the SEC
staff are considering whether the provisions of SFAS No. 141 and SFAS No.142
require registrants to classify costs associated with mineral rights, including
both proved and unproved lease acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs, and
provide specific footnote disclosures. Historically, the Company has included
oil and gas lease acquisition costs as a component of oil and gas properties. In
-14-
the event the FASB and SEC staff determine that costs associated with mineral
rights are required to be classified as intangible assets, a substantial portion
of the Company's oil and gas property acquisition costs would be separately
classified on its balance sheets as intangible assets. However, the Company's
results of operations would not be affected since such intangible assets would
continue to be depleted and assessed for impairment in accordance with existing
successful efforts accounting rules and impairment standards. Further, the
Company does not believe the classification of oil and gas lease acquisition
costs as intangible assets would have any impact on the Company's compliance
with covenants under its debt agreements.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
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 in the circumstances. Such statements are subject to a number of
assumptions, risks and uncertainties, including such factors as the volatility
and level of oil and natural gas prices, unexpected drilling conditions and
results, production rates and reserve replacement, reserve estimates, drilling
and operating service availability and risks, uncertainties in cash flow, the
financial strength of hedge contract counterparties, the availability of
attractive exploration, development and property acquisition opportunities,
financing requirements, expected acquisition benefits, competition, litigation,
environmental matters, the potential impact of government regulations, and other
matters discussed under the "Risk Factors" section of our 2002 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.
-15-
Financial Results
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
(In thousands, except per share data)
Oil and gas production revenues $ 96,134 $ 46,197 $191,822 $ 87,290
Net income $ 24,317 $ 10,589 $ 57,114 $ 12,907
Per share - basic $ 0.77 $ 0.38 $ 1.85 $ 0.46
Per share - diluted $ 0.71 $ 0.37 $ 1.67 $ 0.46
Net Income
We generated net income of $24.3 million or $0.71 per diluted share for the
second quarter of 2003 compared with net income of $10.6 million or $0.37 per
diluted share for the same quarter of 2002. Comparing the six-months ended June
30, 2003 to June 30, 2002, net income and diluted earnings per share were $57.1
million and $1.67 per share versus $12.9 million and $0.46 per share,
respectively. Included in net income for the six-months ended June 30, 2003, is
$5.4 million, or $0.15 per diluted share, associated with the cumulative effect
of a change in accounting principle required upon the adoption of Statement of
Financial Accounting Standards No. 143 "Accounting for Asset Retirement
Obligations." The increase in net income over the comparative periods is a
result of increased oil and gas prices and higher production volumes associated
with successful drilling results, the acquisition of the Burlington properties
acquired in December 2002 and the Flying J properties acquired in January 2003.
-16-
Results of Operations
The following table sets forth selected operating data for the periods
indicated.
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
(In thousands, except volume and per volume data)
Oil and gas production revenues:
Gas production $ 65,650 $ 29,113 $ 131,581 $ 53,734
Oil production 30,484 17,084 60,241 33,556
------------ ------------ ------------ ------------
Total $ 96,134 $ 46,197 $ 191,822 $ 87,290
============ ============ ============ ============
Net production:
Gas (MMcf) 13,614 9,618 25,318 19,173
Oil (MBbls) 1,164 673 2,205 1,378
MMCFE 20,595 13,655 38,546 27,440
Net daily production:
Gas (MMcf) 149.6 105.7 139.9 105.9
Oil (MBbls) 12.8 7.4 12.2 7.6
MMCFE 226.3 150.1 213.0 151.6
Average realized sales price (1):
Gas (per Mcf) $ 4.82 $ 3.03 $ 5.20 $ 2.80
Oil (per Bbl) $ 26.20 $ 25.39 $ 27.32 $ 24.35
Oil and gas production costs:
Lease operating expense $ 15,149 $ 8,177 $ 29,020 $ 18,626
Transportation costs 1,941 761 3,331 1,577
Production taxes 6,170 2,593 12,039 5,358
------------ ------------ ------------ ------------
Total $ 23,260 $ 11,531 $ 44,390 $ 25,561
============ ============ ============ ============
Additional per MCFE data:
Sales price $ 4.67 $ 3.38 $ 4.98 $ 3.18
Lease operating expense 0.74 0.60 0.75 0.68
Transportation costs 0.09 0.06 0.09 0.06
Production taxes 0.30 0.18 0.31 0.19
------------ ------------ ------------ ------------
Operating margin $ 3.54 $ 2.54 $ 3.83 $ 2.25
============ ============ ============ ============
Depletion, depreciation and amortization $ 1.05 $ 0.97 $ 1.05 $ 0.96
General and administrative $ 0.29 $ 0.22 $ 0.32 $ 0.22
-----------------------
(1)Includes the effects of St. Mary's hedging activities.
-17-
Three-Month Comparison
Oil and Gas Production Revenues. Our quarterly oil and gas production
revenues increased $49.9 million, or 108% to $96.1 million for the three months
ended June 30, 2003. The following table presents components of the increase in
total production revenues between 2003 and 2002.
Production Price Price
% Change $ Change % Change
-------------------------------------------------
o Natural Gas 42% $1.80/Mcf 59%
o Oil 73% $0.81/Bbl 3%
Following is our product mix.
Percentage of Revenue Percentage of Production
--------------------- ------------------------
Three Months Ended June 30 2003 2002 2003 2002
-----------------------------------------------------------------------------
o Natural Gas 68% 63% 66% 70%
o Oil 32% 37% 34% 30%
Average net daily production was 226.3 MMCFE for 2003 compared with 150.1
MMCFE in 2002, an increase of 51%. Included in our 2003 production volumes are
10.5 MMcf per day and 4.8 MBbls per day from the Burlington and Flying J
acquisitions. Wells completed in 2002 and 2003 and properties acquired in the
last two quarters of 2002 and during 2003 have added revenue of $34.2 million
and average net daily production of 79.9 MMCFE in 2003 over the comparable 2002
period.
Projections of pricing for oil and natural gas for the remainder of the
year lead us to believe that our average realized price for each product will be
higher in 2003 than for comparable periods of 2002. However, since the end of
June 2003, the forward prices have decreased relative to the prices in effect
for most of the second quarter of 2003. The prices we receive reflect the impact
of market forces, which are influenced by many factors including: political
events, economic growth, supply, fuel demand, electricity demand, weather,
Organization of Petroleum Exporting Countries policies and others.
Information regarding the current effects of oil and gas hedging activity
is included in the table below, which reflects increased hedging of oil
production as a result of our Burlington and Flying J acquisitions.
Three Months Ended June 30 2003 2002
--------------------------------------------------------------------------
o Percentage of oil production hedged 57% 39%
o Oil volumes hedged (MBbls) 661 260
o Increase (decrease) in oil revenue ($1.3 million) $1.2 million
o Average realized oil price per Bbl
without hedging $27.30 $23.64
o Percentage of gas production hedged 39% 44%
o Natural gas MMBtu hedged 5.9 million 4.6 million
o Decrease in gas revenue ($2.9 million) ($1.5 million)
o Average realized gas price per Mcf
without hedging $5.03 $3.18
Marketed Gas Revenue and Gas System Operating Expense. As a result of our
acquisition of gas gathering system lines in Coal County, Oklahoma, in February
2002 we began taking title to and marketing natural gas for third parties. For
the three months ended June 30, 2003, we received $3.3 million from the sale of
this natural gas compared to $2.9 million for the same period in 2002. Operating
costs associated with these revenues totaled $3.1 million for the three months
ended June 30, 2003 compared to $2.7 million for the same period in 2002. The
higher natural gas prices in 2003 are the primary reason the revenues and costs
-18-
are higher in 2003. Due to fluctuations in natural gas prices, cost inflation
and the variability of production from oil and gas wells, we may not always have
a positive gross margin from gas marketing.
Oil and Gas Production Expenses. Oil and gas production costs consist of
lease operating expense, production taxes and transportation expenses. Total
production costs increased $11.7 million or 102% to $23.3 million for the three
months ended June 30, 2003, from $11.5 million in the same period of 2002. Our
acquisition of properties from Burlington and Flying J added $6.5 million of
production costs, and wells completed in later 2002 and in 2003 added $2.1
million of production costs in 2003 that were not reflected in 2002.
Additionally, we experienced a general increase in production taxes on higher
revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.29 to $1.13 for
the second quarter of 2003 compared with $0.84 for the second quarter of 2002.
This increase is comprised of the following:
o A $0.12 increase in production taxes due to higher per MCFE prices.
o A $0.03 increase in transportation costs.
o A $0.07 increase in LOE that reflects our additions of higher cost oil
production properties in the Williston Basin through our acquisitions from
Burlington and Flying J.
o A $0.07 increase in LOE due to a one-time Authorization for Expenditure
adjustment to decrease workover expenses at the Judge Digby field that
occurred in the second quarter of 2002.
We continue to believe that our workover activity in the Williston Basin
will increase over the remainder of the summer. Since production increases
resulting from workover activity are not likely to appear in the period those
costs are incurred, we believe that our LOE per MCFE will increase during the
remainder of 2003. These increases could be offset in part by decreases in
production taxes due to possible decreases in oil and gas prices.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion and amortization expense ("DD&A") increased $8.3 million or 63% to
$21.6 million for the three months ended June 30, 2003, from $13.3 million in
the same period of 2002. DD&A per MCFE increased by 8% to $1.05 for the
second quarter of 2003 compared with $0.97 in 2002. The increase in expense is a
result of both higher production volumes in 2003 and the higher per unit rate
which reflects acquisitions and drilling results in 2002 and 2003.
Exploration. Exploration expense increased $2.3 million or 54% to $6.6
million for the three months ended June 30, 2003, compared with $4.3 million in
2002. In 2003 we have had a lesser ownership interest in lower cost exploratory
dry holes than in 2002, offsetting in part increased exploration overhead due to
increases in our geologic and exploration staff as a result of the acreage we
have acquired in the Williston, Green River and Powder River basins. Components
of total exploration expense are as follows (in thousands).
Three Months Ended
June 30,
---------------------------
2003 2002
------------ ------------
o Geological and geophysical expenses $ 2,301 $ 495
o Exploratory dry holes 681 1,955
o Overhead and other expenses 3,653 1,847
------------ ------------
$ 6,635 $ 4,297
============ ============
-19-
General and Administrative. General and administrative expenses increased
$3.0 million or 100% to $6.0 million for the three months ended June 30, 2003,
compared with $3.0 million in 2002. The increase in cost on a per MCFE basis is
primarily due to our compensation expense.
Our employee count increased by 19% from June 30, 2002 to June 30, 2003.
This change has resulted in a general increase in G&A of $1.4 million
between the quarters ending on those dates. That increase plus a $3.8 million
increase in compensation expense associated with our incentive compensation
plans, a $245,000 increase in charitable contributions expense and a $117,000
increase in insurance and corporate governance costs were partially offset by a
$2.7 million increase in COPAS overhead reimbursement from operations and
G&A we allocated to exploration expense. COPAS overhead reimbursement from
operations has increased as a result of an increase in the number of properties
we operate in our Rockies region due to our Burlington and Flying J
acquisitions. The increase in compensation expense associated with our incentive
compensation plans reflects both the benefit we have received from the current
price environment for past employee performance and the performance of our
employees during the current year. As we continue our expected growth in size
and number of personnel and if oil and gas prices perform as expected, we
anticipate that G&A will continue to increase in total. However, we expect
G&A to remain relatively flat on a per MCFE basis.
Interest Expense. Interest expense increased by $1.3 million to $2.4
million for the quarter ended June 30, 2003 compared to $1.0 million for the
quarter ended June 30, 2002. This difference reflects the benefit of an interest
rate swap on our 5.75% convertible notes that reduced interest expense by
$383,000 in 2002, the 0.5% contingent interest provision on our convertible
notes which applied in 2003 but not in 2002 and increased borrowings under our
credit facility. We anticipate that quarterly interest expense in 2003 will
continue to be higher than in 2002 due to the termination in December 2002 of
the interest rate swap.
Income Taxes. Income tax expense totaled $15.7 million for the three months
ended June 30, 2003, and $5.3 million in 2002, resulting in effective tax rates
of 39.2% and 33.2%, respectively. The effective rate change from 2002 reflects
an increase in our highest marginal federal tax rate, the expiration of the
Section 29 tax credit, adjustments to valuation allowances to reflect the
likelihood that prior Alternative Minimum Tax credits created by Section 29
credits will not be used, changes in the composition of the highest marginal
state tax rates as a result of our recent acquisitions and the 2002 adjustment
to valuation allowances against state income taxes from net operating loss
carryovers.
Six-Month Comparison
Oil and Gas Production Revenues. We experienced an increase in oil and gas
production revenues of $104.5 million, or 120% to $191.8 million for the six
months ended June 30, 2003, compared with $87.3 million for the same period in
2002. The following table presents the components of increases or (decreases)
between 2003 and 2002.
Production Price Price
% Change $ Change % Change
-------------------------------------------------
o Natural Gas 32% $2.39/Mcf 85%
o Oil 60% $2.97/Bbl 12%
Following is our product mix.
Percentage of Revenue Percentage of Production
--------------------- ------------------------
Six Months Ended June 30 2003 2002 2003 2002
-----------------------------------------------------------------------------
o Natural Gas 69% 62% 66% 70%
o Oil 31% 38% 34% 30%
Average net daily production increased 40% to 213.0 MMCFE for the first six
months of 2003 compared with 151.6 MMCFE in 2002. Included in our 2003
production volumes are 9.7 MMcf per day and 4.2 Mbbls per day from the
-20-
Burlington and Flying J acquisitions. Wells completed in 2002 and 2003 and
properties acquired in the last two quarters of 2002 and during 2003 have added
revenue of $70.5 million and average net daily production of 72.8 MMCFE in the
first six months of 2003 over the comparable 2002 period.
Information regarding the current effects of oil and gas hedging activity
is included in the table below, which reflects increased hedging of oil
production as a result of our Burlington and Flying J acquisitions.
Six Months Ended June 30 2003 2002
--------------------------------------------------------------------------
o Percentage of oil production hedged 57% 39%
o Oil volumes hedged (MBbls) 1,262 542
o Increase (decrease) in oil revenue ($5.2 million) $2.6 million
o Average realized oil price per Bbl
without hedging $29.69 $22.46
o Percentage of gas production hedged 35% 43%
o Natural gas MMBtu hedged 9.7 million 9.0 million
o Decrease in gas revenue ($9.8 million) $904,000
o Average realized gas price per Mcf
without hedging $5.03 $3.18
Marketed Gas System Revenue and Gas System Operating Expense. For the six
months ended June 30, 2003, we received $7.1 million from the sale of this
natural gas compared to $3.4 million in the same period of 2002. Operating costs
associated with these revenues totaled $6.5 million for the period ended June
30, 2003, compared to $3.1 million for the same period in 2002. Our gas
marketing activities for third parties began in February 2002. The increase in
2003 as compared to 2002 is a result of a full six months of activity and
relatively higher gas prices.
Oil and Gas Production Expenses. Total production costs increased $18.8
million to $44.4 million for the six months ended June 30, 2003, from $25.6
million in 2002. Our acquisition of properties from Burlington and Flying J
added $11.4 million of production costs, and wells completed in 2002 and 2003
added $3.6 million of production costs in 2003 that were not reflected in 2002.
Additionally, we experienced a general increase in production taxes on higher
revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.22 to $1.15 for
the six months ended June 30, 2003 compared with $0.93 for 2002. This increase
is comprised of the following:
o A $0.12 increase in production taxes due to higher per MCFE prices.
o A $0.03 increase in transportation costs.
o A $0.07 increase in LOE that reflects our additions of higher cost oil
properties in the Williston Basin through our acquisitions from Burlington
and Flying J.
Depreciation, Depletion, Amortization and Impairment. DD&A increased
$14.2 million or 54% to $40.5 million for the six months ended June 30, 2003,
from $26.3 million in 2002. DD&A per MCFE increased by 9% to $1.05 for the
six months ended June 30, 2003 compared with $0.96 in 2002. The increase in
expense is a result of both higher production volumes in 2003 and the higher per
unit rate which reflects acquisitions and drilling results in 2002 and 2003.
Exploration. Exploration expense decreased $428,000 or 4% to $10.8 million
for the six months ended June 30, 2003, compared with $11.2 million in 2002. In
2003 we have had a lesser ownership interest in lower-cost exploratory dry holes
than in 2002, offsetting in part increased exploration overhead due to increases
in our geologic and exploration staff as a result of the acreage we have
-21-
acquired in the Williston, Green River and Powder River basins. Components of
total exploration expense are as follows (in millions).
Six Months Ended
June 30,
---------------------------
2003 2002
------------ ------------
o Geological and geophysical expenses $ 3.7 $ 1.3
o Exploratory dry holes 1.2 6.1
o Overhead and other expenses 5.9 3.8
------------ ------------
$ 10.8 $ 11.2
============ ============
General and Administrative. General and administrative expenses increased
$6.0 million or 98% to $12.2 million for the six months ended June 30, 2003,
compared with $6.2 million in 2002. The increase in cost on a per MCFE basis is
primarily due to an increase in our compensation expense.
The increase in our employee count has resulted in a general increase in
G&A of $2.7 million between six-month periods ending on June 30, 2003 and
June 30, 2002. That increase plus a $5.9 million increase in expense associated
with our incentive compensation plans, a $664,000 increase in accrued charitable
contributions expense and a $396,000 increase in insurance and corporate
governance costs were partially offset by a $3.9 million increase in COPAS
overhead reimbursement from operations and G&A we allocated to exploration
expense. COPAS overhead reimbursement from operations has increased due to an
increase in the number of properties we operate in our Rockies region as a
result of our Burlington and Flying J acquisitions. The increase in expense
associated with our incentive compensation plans reflects both the benefit we
have received from the current price environment for past employee performance
and the performance of our employees during the current year.
Interest Expense. Interest expense increased by $3.1 million to $4.6
million for the six months ended June 30, 2003 compared to $1.5 million for the
period ended June 30, 2002. The increase reflects a full six months of accrued
interest in 2003 on our 5.75% convertible notes that were issued in March 2002,
the benefit of an interest rate swap on those notes that reduced interest
expense by $446,000 in 2002, the 0.5% contingent interest provision on the notes
which applied in 2003 but not in 2002, and increased borrowings under our credit
facility. We anticipate that interest expense in 2003 will be higher than the
2002 amount due to the termination of the interest rate swap in December 2002
and since we have increased borrowings under our credit facility in 2003.
Income Taxes. Income tax expense totaled $32.7 million for the six months
ended June 30, 2003, and $6.4 million in 2002, resulting in effective tax rates
of 38.8% and 33.1%, respectively. The effective rate change from 2002 reflects
an increase in our highest marginal federal tax rate, the expiration of the
Section 29 tax credit, adjustments to valuation allowances to reflect the
likelihood that prior Alternative Minimum Tax credits created by Section 29
credits will not be used, changes in the composition of the highest marginal
state tax rates as a result of our recent acquisitions and the 2002 adjustment
to valuation allowances against state income taxes from net operating loss
carryovers.
The current portion of the income tax expense in 2003 is $21.9 million
compared to $1.5 million in 2002. These amounts are 66% and 23% of the total tax
for the respective periods. The difference results from increased taxable income
caused by significantly higher oil and gas prices and production, a reduction in
the percentage of deductible intangible drilling costs relative to total income
and interest income recognized for tax purposes from our Flying J transaction.
Cumulative Effect of Change in Accounting Principle, net. On January 1,
2003, we adopted SFAS No. 143. The impact of adoption resulted in income to us
of $8.8 million offset by the deferred income tax effect of $3.4 million. See
-22-
Note 7 of the Notes to Consolidated Financial Statements under Part I, Item 1 of
this report.
Liquidity and Capital Resources
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. All of these sources can be impacted by significant
fluctuations in oil and gas prices and the availability of financing to oil and
gas producers in the market. An unexpected decrease in oil and gas prices would
reduce expected cash flow from operating activities, might reduce the borrowing
base on our credit facility, could reduce the value of our non-strategic
properties and historically has limited our industry's access to the capital
markets.
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. Exploration and development programs are generally
financed from internally generated cash flow, debt financing and cash and cash
equivalents on hand. Cash uses for the acquisition of oil and gas properties and
the payment of stockholder dividends are discretionary and can be reduced or
eliminated in the event of an unexpected decrease in oil and gas prices. At any
given point in time we may be obligated to pay for commitments to explore for or
develop oil and gas properties or incur trade payables. However, future
obligations can be reduced or eliminated when necessary. We are currently only
required to make interest payments on our debt obligations, although we have
voluntarily been reducing our outstanding borrowings under our revolving credit
facility. As of the date of filing this report, the outstanding balance of the
revolving credit facility was $24 million, representing a $20.0 million
reduction from the $44.0 million outstanding balance at June 30, 2003. An
unexpected increase in oil and gas prices would provide increased flexibility to
modify our uses of cash flow.
We continually review our capital expenditure budget to reflect changes in
current and projected cash flow, drilling and acquisition opportunities, debt
requirements and other factors.
Cash Flow. Net cash provided by operating activities increased $14.7
million or 19% to $90.8 million for the six months ended June 30, 2003 compared
with $76.1 million in 2002. Our $34.2 million increase in net income between the
two periods combined with a $13.5 million increase in the effect of non-cash
items were offset by a $43.0 million change in current assets and liabilities
relating to increased accounts receivables offset by decreased prepaid expenses,
and collections of refundable income taxes. We anticipate increased cash flow
from operations in 2003 as a result of higher oil and gas prices in 2003 and
increased production attributable to our property acquisitions and drilling
activities in late 2002 and early 2003.
Net cash used in investing activities increased $56.1 million or 87% to
$120.6 million for the six months ended June 30, 2003, compared with net cash
used of $64.5 million in 2002. This increase results from additional capital
expenditures and acquisition costs. Total capital expenditures, including
acquisitions of oil and gas properties, in the first six months of 2003
increased $67.1 million or 119% to $123.3 million compared with $56.2 million in
the first six months of 2002. This increase reflects the utilization of $71.6
million in short term investments, cash equivalents and increased borrowings
under our credit facility to provide a loan to Flying J as part of our
acquisition of properties from Flying J in January 2003. This loan is secured by
our common stock issued in the transaction.
Net cash provided by financing activities decreased $2.6 million to $29.5
million for the six months ended June 30, 2003, compared with $32.1 million in
2002. This decrease reflects the 2002 issuance of our 5.75% convertible notes
and the use of proceeds to pay down our credit facility, partially offset by
additional borrowing on our credit facility to fund our 2003 acquisitions.
-23-
St. Mary had $10.8 million in cash and cash equivalents and had working
capital of $2.0 million as of June 30, 2003, compared with $11.2 million in cash
and cash equivalents and working capital of $2.1 million at December 31, 2002.
Senior Convertible Notes. In March 2002 we issued in a private placement a
total of $100.0 million of 5.75% senior convertible notes due 2022 with a 0.5
percent contingent interest provision. Interest payments are due on March 15 and
September 15 of every year. We received net proceeds of $96.8 million after
deducting the initial purchasers' discount and estimated offering expenses
payable by us. The notes are general unsecured obligations and rank on a parity
in right of payment with all our existing and future senior indebtedness and
other general unsecured obligations, and are senior in right of payment with all
our future subordinated indebtedness. The notes are convertible into our common
stock at a conversion price of $26.00 per share, subject to adjustment. We can
redeem the notes with cash in whole or in part at a repurchase price of 100% of
the principal amount plus accrued and unpaid interest including contingent
interest beginning on March 20, 2007. The note holders have the option of
requiring us to repurchase the notes for cash at 100% of the principal amount
plus accrued and unpaid interest including contingent interest upon (1) a change
in control of St. Mary or (2) on March 20, 2007, March 15, 2012 and March 15,
2017. If the note holders request repurchase on March 20, 2007, we may pay the
repurchase price with cash, shares of our common stock valued at a discount to
the market price at the time of repurchase or any combination of cash and our
discounted common stock. We are not restricted from paying dividends, incurring
debt, or issuing or repurchasing our securities under the indenture for the
notes. There are no financial covenants in the indenture. We used a portion of
the net proceeds from the notes to repay our credit facility balance and used
the remaining net proceeds to fund a portion of our 2002 capital expenditures.
On March 25, 2002, we entered into a five-year fixed-rate to floating-rate
interest rate swap on $50.0 million of the notes. The floating rate was
determined as LIBOR plus 0.36%. We elected to terminate this swap on December 3,
2002, and received proceeds of $4.0 million.
Credit Facility. On January 29, 2003, we entered into a new $300.0 million
credit facility with Wachovia Bank as Administrative Agent and eight other
participating banks. This new credit facility replaced our previous $200.0
million credit facility and has a maturity date of January 27, 2006. The
calculated borrowing base is currently $275.0 million. We have elected a
commitment amount of $150.0 million under this facility. We believe this
commitment level is adequate for our current liquidity needs and results in
lower commitment fees payable to the bank syndicate. We are required to comply
with certain financial and non-financial covenants, and we are currently in
compliance with all covenants under the credit facility. 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.
Borrowing base
utilization percentage <50% =>50%<75% =>75%<90% >90%
---------------------------------------------------------------------------
Eurodollar Loans 1.250% 1.500% 1.750% 2.000%
ABR Loans 0.000% 0.250% 0.500% 0.750%
Commitment Fee Rate 0.300% 0.375% 0.375% 0.500%
Our loan balance of $44.0 million is comprised of LIBOR based traunches at
June 30, 2003. Our weighted average interest rates paid for the second quarter
of 2003 and for the six months ended June 30, 2003 were 6.2% and 5.9%,
respectively, including 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.
-24-
Schedule of Contractual Obligations. The following table summarizes our
future estimated principal payments for the periods specified (in millions).
Long-Term Operating Total Cash
Contractual Obligations Debt Leases Obligation
---------------------------- ------------ ------------ ------------
Less than 1 year $ - $ 1.9 $ 1.9
1-3 years 44.0 2.9 46.9
4-5 years - 2.2 2.2
After 5 years 100.0 3.2 103.2
------------ ------------ ------------ $ $
Total $ 144.0 $ 10.2 $ 154.2
============ ============ ============
In the period from 1-3 years, we have one lease of office space for our
regional offices that will expire. A third lease for office space 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 5.75%
convertible notes will not exercise the conversion or redemption features until
final maturity.
Common Stock. In 1998 St. Mary's Board of Directors authorized a stock
repurchase program whereby we may purchase from time-to-time, in open market
transactions or negotiated sales, up to two million of our common shares.
Through June 30, 2003, we have repurchased a cumulative total of 1,009,900
shares of St. Mary's common stock under the program. We anticipate that
additional purchases of shares may occur as market conditions warrant. Any
future purchases will be funded with internal cash flow and borrowings under our
credit facility.
On January 29, 2003, we issued a total of 3,380,818 restricted shares of
our common stock valued at $71.6 million to Flying J Oil & Gas Inc. and Big
West Oil & Gas Inc. (collectively Flying J) for the acquisition of oil and
gas properties, and we made a non-recourse loan to Flying J in the amount of
$71.6 million at LIBOR plus 2% for up to a 39-month period. The loan is secured
by a pledge of the 3,380,818 shares and during the 39-month loan period Flying J
can elect to sell these shares to St. Mary for $71.6 million plus accrued
interest on the loan for up to the first 30 months, and we can elect to
repurchase the shares for $97.4 million with the proceeds applied to repayment
of the loan. The shares are subject to contractual restrictions on transfer for
a period of two years. Flying J cannot increase their ownership percentage in
St. Mary for a period of 30 months. For accounting purposes the stock and the
loan are reflected in the temporary equity section of our consolidated balance
sheets. Because the loan is reflected in temporary equity we will not record
interest income from the loan until such time as Flying J and Big West make
actual payment of the interest to us. At June 30, 2003, the cumulative amount of
interest receivable but not recorded as income by us was $1.0 million.
Capital and Exploration Expenditures Incurred. Expenditures for exploration
and development of oil and gas properties and acquisitions are the primary use
of our capital resources. The following table sets forth certain information
regarding the costs incurred by us in our oil and gas activities during the
periods indicated. These expenditures include the value of the stock issued in
the Flying J transaction.
-25-
Six Months Ended June 30,
--------------------------
2003 2002
------------ ------------
(In thousands)
Development $ 42,164 $ 30,444
Exploration 19,176 9,034
Acquisitions:
Proved 77,676 7,040
Unproved 4,096 8,597
------------ ------------
Total $ 143,112 $ 55,115
============ ============
We continuously evaluate opportunities in the marketplace for oil and gas
properties and, accordingly, may be a buyer or a seller of properties at various
times. We will continue to emphasize acquisitions in our core areas utilizing
St. Mary's technical expertise, financial flexibility and structuring
experience. In addition, we are also actively seeking larger acquisitions of
assets or companies that would afford opportunities to expand our existing core
areas, to acquire additional geoscientists or to gain a significant acreage and
production foothold in a new basin.
St. Mary's total costs incurred in the first six months of 2003 increased
$88.0 million or 160% compared to the first six months of 2002. We spent $65.4
million in the first six months of 2003 for unproved property acquisitions and
domestic exploration and development compared to $48.1 million for the
comparable period in 2002.
We continue to evaluate the results of our two coalbed methane pilot
programs located in the Hanging Woman Basin. On April 30, 2003, the Bureau of
Land Management issued its record of decision approving the two environmental
impact statements that considered coalbed methane development in northeast
Wyoming and southeast Montana, and the BLM is now issuing drilling permits on
federal acreage in Wyoming. We hope the two environmental impact statements will
also open the door for new coalbed methane development on federal acreage in
this area of Montana. Immediately after the decision was issued several
environmental groups filed multiple challenges. These challenges and a
previously reported environmental public interest group lawsuit by the Northern
Plains Resource Council, Inc. affect 89,700 gross acres related to this project.
Capital Expenditure Budget. We anticipate spending approximately $233
million for capital and exploration expenditures in 2003 with $90 million
allocated for acquisitions, which includes the $71.6 million acquisition of
properties from Flying J in January 2003. Budgeted ongoing exploration and
development expenditures in 2003 for each of our core areas is as follows (in
millions).
o Mid-Continent region $ 51
o Williston Basin 35
o ArkLaTex region 21
o Gulf Coast and Gulf of Mexico region 15
o Permian Basin 12
o Other 9
--------
Total $ 143
========
-26-
We believe the amount not funded from our internally generated cash flow in
2003 can be funded from our existing cash and our credit facility. 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 and our ability to assimilate these acquisitions. 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. If
additional development or attractive acquisition opportunities arise, we may
consider other forms of financing, including the public offering or private
placement of equity or debt securities.
Derivatives. We seek to protect our rate of return on acquisitions of
producing properties by hedging cash flow when the economic criteria from our
evaluation and pricing model indicate it would be appropriate. Management's
strategy is generally to hedge cash flows from acquisitions for up to 24 months
in order to meet minimum rate-of-return criteria. Management reviews these
hedging parameters on a quarterly basis. We may periodically hedge additional
production when we view the price environment to be favorable for hedging. We
generally limit our aggregate hedge position to no more than 50% of total
production but will hedge larger percentages of total production in certain
circumstances. We seek to minimize basis risk and index the majority of oil
hedges to NYMEX prices and the majority of gas hedges to various regional index
prices associated with pipelines in proximity to our areas of gas production.
Our policy requires that we diversify our hedge positions with various
counterparties and requires that such counterparties have clear indications of
financial strength. Including hedges entered into since June 30, 2003 we have
the following swaps and collars in place:
Swaps
----- Average Quantity Average Fixed
Product Volumes/month Type Contract Price Duration
-----------------------------------------------------------------------------------------
Natural Gas 1,845,000 MMBtu $4.49 07/03 - 12/03
Natural Gas 869,000 MMBtu $4.08 01/04 - 12/04
Oil 202,000 Bbls $25.57 07/03 - 12/03
Oil 144,500 Bbls $23.71 01/04 - 12/04
Collars
------- Average Floor Ceiling
Product Volumes/month Price Price Duration
-----------------------------------------------------------------------------------------
Natural Gas 152,000 MMbtu $2.50 $5.96 07/03 - 12/03
Other Derivatives. Our 5.75% convertible notes contain a provision for
payment of contingent interest if certain conditions are met. Under SFAS No. 133
this provision 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 separated and accounted for as a derivative instrument. The
value of the derivative at issuance in March 2002 was $474,000. This amount was
recorded as a decrease to the 5.75% convertible notes payable in the
consolidated balance sheets. Of this amount, $47,000 has been amortized through
interest expense in 2003. Derivative loss in the consolidated statements of
operations includes $14,000 of net loss from mark-to-market adjustments for this
derivative at June 30, 2003, compared to a net loss of $245,000 included in
derivative loss at June 30, 2002.
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, 2002.
-27-
Accounting Matters
New Accounting Standards
In May 2003 the Financial Accounting Standards Board issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This Statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity and requires that such financial instruments be
classifies as a liability (or as an asset in certain circumstances). SFAS No.
150 is effective for all freestanding instruments entered into or modified after
May 31, 2003. Otherwise, it became effective for us as of July 1, 2003. We
currently have no financial instruments that fall within the scope of SFAS No.
150. As a result, the adoption of this Statement is not expected to have an
impact on our financial position or results of operations.
In April 2003 the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement amends and
clarifies technical aspects of financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This Statement is effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. In addition, except in certain
limited circumstances, all provisions of this Statement should be applied
prospectively.
Effective January 1, 2003, we adopted the provisions of SFAS No. 143,
"Accounting for Asset Retirement Obligations." Upon adoption of SFAS No. 143, we
recorded a discounted liability of $21.4 million, reversed the existing offshore
abandonment liability of $9.1 million, increased net property and equipment by
$21.1 million and recognized a one-time cumulative effect gain of $5.4 million
(net of deferred tax benefit of $3.4 million). We will deplete the amount added
to property and equipment and recognize accretion expense in connection with the
discounted liability over the remaining economic lives of the respective oil and
gas properties. Prior to the adoption of SFAS No. 143, we assumed that salvage
value approximated abandonment costs and therefore salvage value was not
reflected in the DD&A calculation. As a result of adopting SFAS No. 143 and
the discounting of the asset retirement obligation, the salvage value must now
be reflected in the DD&A rate. Accordingly, $13.7 million was reversed from
accumulated DD&A and is included as a part of the increase in net property
and equipment in the cumulative effect adjustment. This adjustment to
accumulated DD&A relates to prior depletion of salvage value that would have
been excluded from the DD&A calculation if the abandonment liability had
been separately recognized. As of June 30, 2003, our capitalized proved oil and
gas properties included $43.0 million of estimated salvage value, which is not
included in our DD&A calculation.
The FASB and representatives of the accounting staff of the Securities and
Exchange Commission are currently engaged in discussions regarding the
application of certain provisions of SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the
extractive industries, including oil and gas companies. The FASB and the SEC
staff are considering whether the provisions of SFAS No. 141 and SFAS No.142
require registrants to classify costs associated with mineral rights, including
both proved and unproved lease acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs, and
provide specific footnote disclosures. Historically, we have included oil and
gas lease acquisition costs as a component of oil and gas properties. In the
event the FASB and SEC staff determine that costs associated with mineral rights
are required to be classified as intangible assets, a substantial portion of our
oil and gas property acquisition costs would be separately classified on our
balance sheets as intangible assets. However, our results of operations would
not be affected since such intangible assets would continue to be depleted and
assessed for impairment in accordance with existing successful efforts
accounting rules and impairment standards. Further, we do not believe the
-28-
classification of oil and gas lease acquisition costs as intangible assets would
have any impact on our compliance with covenants under its debt agreements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We hold derivative contracts and financial instruments that have cash flow
and net income exposure to changes in commodity prices or interest rates.
Financial and commodity-based derivative contracts are used to limit the risks
inherent in some crude oil and natural gas price changes that have an effect on
us.
Our board of directors has adopted a policy regarding the use of derivative
instruments. This policy requires every derivative used by St. Mary to relate to
underlying offsetting positions, anticipated transactions or firm commitments.
It prohibits the use of speculative, highly complex or leveraged derivatives.
Under the policy, the Chief Executive Officer and Vice President - Finance must
review and approve all risk management programs that use derivatives. The board
of directors periodically reviews these programs.
Commodity Price Risk. We use various hedging arrangements to manage our
exposure to price risk from natural gas and crude oil production. These hedging
arrangements have the effect of locking in for specified periods, at
predetermined prices or ranges of prices, the prices we will receive for the
volumes to which the hedge relates. Consequently, while these hedging
arrangements are structured to reduce our exposure to decreases in prices
associated with the hedged commodity, they also limit the benefit we might
otherwise receive from any price increases associated with the hedged commodity.
The derivative gain or loss effectively offsets the loss or gain on the
underlying commodity exposures that have been hedged. The fair value of the
swaps are estimated based on quoted market prices of comparable contracts and
approximate the net gains or losses that would have been realized if the
contracts had been closed out at quarter-end. The fair value of the futures are
based on quoted market prices obtained from the New York Mercantile Exchange and
have been adjusted for our hedging of the basis differential accorded to the
pipelines relative to our areas at production.
A hypothetical $0.10 per MMBtu change in our quarter-end market prices for
natural gas swaps and futures contracts on a notional amount of 22.4 million
MMBtu would cause a potential $1.8 million change in net income before income
taxes over the remaining life of the contracts in place on June 30, 2003 and a
potential $875,000 change for the last six months of 2003. A hypothetical $1.00
per Bbl change in our quarter-end market prices for crude oil swaps and future
contracts on a notional amount of 2.9 million Bbls would cause a potential $2.7
million change in net income before income taxes over the remaining life of the
contracts in place on June 30, 2003 and a potential $1.2 million change for the
last six months of 2003. These hypothetical changes were discounted to present
value using a 7.5% discount rate since the latest expected maturity date of
certain swaps and futures contracts is greater than one year from the reporting
date.
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. A sensitivity analysis presents the
hypothetical change in fair value of those financial instruments held by St.
Mary at June 30, 2003, which 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 for floating rate debt,
interest rate changes generally do not affect the fair market value but do
impact future results of operations and cash flows, assuming other factors are
held constant. The carrying amount of our floating rate debt approximates its
fair value. At June 30, 2003, we had floating rate debt of $44.0 million and
$100.0 million of fixed rate debt. Assuming constant debt levels, the impact on
results of operations and cash flows for the remainder of the year resulting
from a one-percentage-point change in interest rates would be approximately
$220,000 before taxes.
-29-
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
-----------------
The previously reported legal proceeding involving Nance Petroleum
Corporation and the Northern Plains Resource Council, Inc. in the U.S. District
Court for the District of Montana had no significant developments during the
quarterly period ended June 30, 2003. For a description of this proceeding,
please see the "Legal Proceedings" section of St. Mary's Annual Report on Form
10-K for the year ended December 31, 2002.
On August 4, 2003, the Company received a copy of an Administrative Order
(the "Order") by the U.S. Environmental Protection Agency (Docket No.
CWA-06-2003-1995) related to certain oil and gas properties in the Gulf of
Mexico that are or were owned, operated or leased by St. Mary Energy Company.
Interests in these properties were acquired by the Company through its
acquisition of St. Mary Energy Company, formerly named King Ranch Energy, Inc.,
on December 17, 1999. The Order alleges violations of the Clean Water Act
through certain violations of EPA reporting rules with respect to such
properties under applicable EPA permits during reporting monitoring periods from
July 1, 1998 to December 31, 1999. Based on a preliminary internal review to
date, the Company believes that any reporting discrepancies were inadvertent and
did not involve any improper discharge of pollutants into the environment, and
the Company plans to fully cooperate with the EPA to appropriately correct and
remedy any reporting discrepancies. Due to the preliminary nature of this
matter, the Company cannot predict whether any monetary or other penalties will
be imposed. However, the Company does not currently expect that such penalties,
if any, would have a material effect on the Company's financial condition,
results of operations or cash flows.
-30-
ITEM 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
At the Company's annual stockholders' meeting on May 21, 2003, the
stockholders approved 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 28,792,078 171,902
Larry W. Bickle 28,772,485 191,495
Ronald D. Boone 28,772,485 191,495
Thomas E. Congdon 28,772,485 191,495
William J. Gardiner 28,772,397 191,583
Mark A. Hellerstein 28,772,485 191,495
Arend J. Sandbulte 28,435,397 528,583
John M. Seidl 28,435,397 528,583
Also at the Company's annual stockholders' meeting on May 21, 2003, the
stockholders approved an amendment to the Company's stock option plans to
increase the total number of shares issuable under those plans by 1,300,000
shares to a total of 5,600,000. The tabulation of votes for that proposal is as
follows:
For 16,898,695
Against 11,374,779
Abstain 690,506
Also at the Company's annual stockholders' meeting on May 21, 2003, the
stockholders approved a non-employee director stock compensation plan for the
issuance of up to a total of 30,000 shares of St. Mary common stock to
non-employee directors as part of their annual or other compensation over an
anticipated period of up to five years. The tabulation of votes for that
proposal is as follows:
For 25,297,824
Against 2,874,837
Abstain 791,319
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 Non-Employee
Director Stock Compensation Plan as adopted on
March 27, 2003
10.2 St. Mary Land & Exploration Company Stock Option
Plan, As Amended on March 25, 1999, January 27,
2000, March 29, 2001, March 27, 2003 and May 22,
2003 (filed as Exhibit 99.1 to registrant's
-31-
Exhibit Description
------- -----------
Registration Statement on Form S-8 (Registration
No. 333-106438) and incorporated herein by
reference)
10.3 St. Mary Land & Exploration Company Incentive
Stock Option Plan, As Amended on March 25, 1999,
January 27, 2000, March 29, 2001, March 27, 2003
and May 22, 2003 (filed as Exhibit 99.2 to
registrant's Registration Statement on Form S-8
(Registration No. 333-106438) and incorporated
herein by reference)
10.4* Guaranty Agreement by St. Mary Energy Company in
favor of Wachovia Bank, National Association, as
Administrative Agent, dated January 27, 2003
10.5* Guaranty Agreement by St. Mary Operating Company in
favor of Wachovia Bank, National Association, as
Administrative Agent, dated January 27, 2003
10.6* Guaranty Agreement by Nance Petroleum Corporation in
favor of Wachovia Bank, National Association, as
Administrative Agent, dated January 27, 2003
10.7* Guaranty Agreement by NPC Inc. in favor of Wachovia
Bank, National Association, as Administrative Agent,
dated January 27, 2003
10.8* Pledge and Security Agreement between St. Mary Land
& Exploration Company and Wachovia Bank, National
Association, as Administrative Agent, dated
January 27, 2003
10.9* Pledge and Security Agreement between Nance Petroleum
Corporation and Wachovia Bank, National Association,
as Administrative Agent, dated January 27, 2003
10.10* First Supplement and Amendment to Deed of Trust,
Mortgage, Line of Credit Mortgage, Assignment,
Security Agreement, Fixture Filing and Financing
Statement for the benefit of Wachovia Bank,
National Association, as Administrative Agent,
dated effective as of January 27, 2003
10.11* Deed of Trust - St. Mary Land & Exploration to
Wachovia Bank, National Association, as
Administrative Agent, dated effective as of
January 27, 2003
10.12* Deed of Trust (CO, NV, SD) to Wachovia Bank, National
Association, as Administrative Agent, dated effective
as of April 2003
10.13* Deed of Trust (LA, MT, ND, NM, OK, TX, UT, WY) to
Wachovia Bank, National Association, as
Administrative Agent, dated effective as of
April 2003
10.14* First Supplement and Amendment to Deed of Trust,
Mortgage, Line of Credit Mortgage, Assignment,
Security Agreement, Fixture Filing and Financing
Statement for the benefit of Wachovia Bank,
National Association, as Administrative Agent,
dated effective as of April 2003
10.15* Second Supplement and Amendment to Deed of Trust,
Mortgage, Line of Credit Mortgage, Assignment,
Security Agreement, Fixture Filing and Financing
Statement for the benefit of Wachovia Bank, National
Association, as Administrative Agent, dated effective
as of April 2003
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.
-32-
(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, 2003:
o On April 21, 2003, we filed a current report on Form 8-K
reporting under Item 9 pursuant to Item 12 that we had issued a
press release announcing an update of our operations for the
first quarter of 2003.
o On April 29, 2003, 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 5-cent per share cash dividend.
o On May 7, 2003, we filed a current report on Form 8-K reporting
under Item 9 pursuant to Item 12that we had issued a press
release announcing our first quarter 2003 financial results and
an updated forecast of our second quarter and full year of 2003.
-33-
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 12, 2003 By: /s/ MARK A. HELLERSTEIN
------------------------------------
Mark A. Hellerstein
President and Chief Executive Officer
August 12, 2003 By: /s/ DAVID W. HONEYFIELD
-------------------------------------
David W. Honeyfield
Vice President - Finance, Secretary
and Treasurer
August 12, 2003 By: /s/ GARRY A. WILKENING
-------------------------------------
Garry A. Wilkening
Vice President - Administration and
Controller