06/02 10Q 08/14/02
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
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Commission File Number: 000-20872
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 1100, 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 the number of shares outstanding of each of the registrant's classes of
common stock as of the latest practicable date.
As of August 12, 2002, the registrant had 27,857,141 shares of common stock,
$.01 par value, outstanding.
ST. MARY LAND & EXPLORATION COMPANY
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INDEX
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Part I. FINANCIAL INFORMATION PAGE
----
Item 1. Financial Statements (Unaudited)
Consolidated Balance
Sheets - June 30, 2002 and
December 31, 2001.....................................3
Consolidated Statements of
Operations - Three and Six Months Ended
June 30, 2002 and 2001................................4
Consolidated Statements of
Cash Flows - Six Months Ended
June 30, 2002 and 20010...............................5
Consolidated Statements of
Stockholders' Equity - June 30, 2002
and December 31, 2001.................................7
Notes to Consolidated Financial
Statements - June 30, 2002............................8
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations........................................11
Item 3. Quantitative and Qualitative Disclosures
About Market Risk....................................21
Part II. OTHER INFORMATION
Item 1. Legal Proceedings....................................22
Item 2. Changes in Securities and Use of Proceeds............23
Item 4. Submission of Matters to a Vote of
Security Holders.....................................23
Item 6. Exhibits and Reports on Form 8-K.....................24
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
ASSETS June 30, December 31,
------------ ------------
2002 2001
------------ ------------
Current assets:
Cash and cash equivalents $ 47,856 $ 4,116
Short term investments 9,376 -
Accounts receivable 35,041 46,484
Prepaid expenses and other 4,002 2,337
Accrued derivative asset 4,292 8,194
Refundable income taxes 1,009 11,090
Deferred income taxes 29 -
------------ ------------
Total current assets 101,605 72,221
------------ ------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 567,965 523,823
Less accumulated depletion, depreciation and amortization (237,685) (216,288)
Unproved oil and gas properties, net of impairment
allowance of $9,402 in 2002 and $8,908 in 2001 45,203 48,143
Other property and equipment, net of accumulated depreciation of $3,499
in 2002 and $3,120 in 2001 3,544 3,252
------------ ------------
Total property and equipment 379,027 358,930
------------ ------------
------------ ------------
Other assets 10,165 5,838
------------ ------------
------------ ------------
Total assets $ 490,797 $ 436,989
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 39,914 $ 34,858
Deferred tax liability 1,711 3,363
------------ ------------
Total current liabilities 41,625 38,221
------------ ------------
Long-term liabilities:
Long-term credit facility - 64,000
Convertible notes, issued at par 99,554 -
Deferred income taxes 52,458 47,685
Other noncurrent liabilities 867 255
------------ ------------
Total long-term liabilities 152,879 111,940
------------ ------------
Commitments and contingencies
------------ ------------
Minority interest 668 711
------------ ------------
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares: Issued and
outstanding - 28,867,041 shares in 2002 and 28,779,808 shares in 2001 289 288
Additional paid-in capital 138,567 137,384
Treasury stock - at cost: 1,009,900 shares in 2002 and 2001 (16,210) (16,210)
Retained earnings 169,255 157,739
Accumulated other comprehensive income 3,724 6,916
------------ ------------
Total stockholders' equity 295,625 286,117
------------ ------------
------------ ------------
Total Liabilities and Stockholders' Equity $ 490,797 $ 436,989
============ ============
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,
----------------------------- ----------------------------
2002 2001 2002 2001
------------ ----------- ----------- -----------
Operating revenues:
Oil and gas production $ 46,197 $ 55,421 $ 87,290 $ 123,336
Gain on sale of proved properties 449 48 413 50
Marketed gas revenue 2,939 - 3,444 -
Other oil and gas revenue 397 203 747 565
Gain on sale of KMOC stock - - 836 -
Other revenues 46 104 71 172
------------ ----------- ----------- -----------
Total operating revenues 50,028 55,776 92,801 124,123
------------ ----------- ----------- -----------
Operating expenses:
Oil and gas production 11,531 13,436 25,561 25,493
Depletion, depreciation and amortization 13,279 12,884 26,333 24,172
Exploration 4,297 2,149 11,213 10,511
Impairment of proved properties - 73 - 244
Abandonment and impairment of unproved properties 622 608 1,319 1,074
General and administrative 3,015 3,536 6,156 7,557
Unrealized derivative loss (gain) (2,327) - (1,975) -
Marketed gas system operating expense 2,662 - 3,086 -
Minority interest and other 243 118 620 379
------------ ----------- ----------- -----------
Total operating expenses 33,322 32,804 72,313 69,430
------------ ----------- ----------- -----------
Income from operations 16,706 22,972 20,488 54,693
Nonoperating income (expense):
Interest income 170 147 280 335
Interest expense (1,018) - (1,470) (35)
------------ ----------- ----------- -----------
Income before income taxes 15,858 23,119 19,298 54,993
Income tax expense 5,269 8,885 6,391 20,366
------------ ----------- ----------- -----------
Net income $ 10,589 $ 14,234 $ 12,907 $ 34,627
============ =========== =========== ===========
Basic net income per common share $ 0.38 $ 0.51 $ 0.46 $ 1.23
============ =========== =========== ===========
Diluted net income per common share $ 0.37 $ 0.50 $ 0.46 $ 1.20
============ =========== =========== ===========
Basic weighted average common shares outstanding 27,825 28,135 27,805 28,185
============ =========== =========== ===========
Diluted weighted average common shares outstanding 28,428 28,717 28,347 28,826
============ =========== =========== ===========
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,
-----------------------------
2002 2001
------------ ------------
Reconciliation of net income to net cash provided by operating activities:
Net income $ 12,907 $ 34,627
Adjustments to reconcile net income to net
cash provided by operating activities:
Gain on sale of proved properties (413) (50)
Gain on sale of KMOC stock (836) -
Depletion, depreciation and amortization 26,333 24,172
Exploratory dry hole expense 6,133 4,418
Impairment of proved properties - 244
Abandonment and impairment of unproved properties 1,319 1,074
Unrealized derivative loss (gain) (1,975) -
Deferred income taxes 4,989 10,841
Minority interest and other 288 442
------------ ------------
48,745 75,768
Changes in current assets and liabilities:
Accounts receivable 12,490 (2,394)
Prepaid expenses and other 8,436 (2,030)
Accounts payable and accrued expenses 6,399 1,530
------------ ------------
Net cash provided by operating activities 76,070 72,874
------------ ------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 122 660
Capital expenditures (42,577) (63,335)
Acquisition of oil and gas properties (13,643) 1,590
Proceeds from distribution and sale of KMOC stock 3,114 7,009
Short term investments available-for-sale (9,370) -
Other (2,122) 69
------------ ------------
Net cash used in investing activities (64,476) (54,007)
------------ ------------
Cash flows from financing activities:
Proceeds from credit facility 16,000 41,750
Repayment of credit facility (80,000) (50,350)
Proceeds from issuance of convertible notes, net 96,754 -
Proceeds from sale of common stock 783 1,721
Repurchase of common stock - (10,949)
Dividends paid (1,391) (1,413)
------------ ------------
Net cash provided by (used in) financing activities 32,146 (19,241)
------------ ------------
Net change in cash and cash equivalents 43,740 (374)
Cash and cash equivalents at beginning of period 4,116 6,619
------------ ------------
Cash and cash equivalents at end of period $ 47,856 $ 6,245
============ ============
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,
-----------------------------
2002 2001
------------ ------------
(In thousands)
Cash paid for interest $ 478 $ 284
Cash paid (received) for income taxes (8,699) 10,386
Cash paid for exploration expenses 14,155 10,499
In June 2002 the Company issued 800 shares of common stock to a director
and recorded compensation expense of $14,763.
In January 2002 the Company issued 7,200 shares of common stock to its
directors and recorded compensation expense of $129,683.
In January 2001 the Company issued 8,400 shares of common stock to its
directors and recorded compensation expense of $237,852.
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 Equity
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Balances, December 31, 2000 28,553,826 $ 286 $ 132,973 $ 120,075 (395,600) $ (3,339) $ 141 $ 250,136
Comprehensive income:
Net Income - - - 40,459 - - - 40,459
Unrealized net loss on marketable
equity securities available
for sale - - - - - - (132) (132)
Adoption of SFAS No. 133 - - - - - - (28,587) (28,587)
Change in derivative instrument
fair value - - - - - - 35,494 35,494
----------
Total comprehensive income 47,234
----------
Cash dividends, $ 0.10 per share - - - (2,795) - - - (2,795)
Treasury stock purchases - - - - (614,300) (12,871) - (12,871)
Issuance for Employee Stock
Purchase Plan 29,772 - 575 - - - - 575
Sale of common stock, including
income tax benefit of stock
option exercises 187,810 2 3,598 - - - - 3,600
Directors' stock compensation 8,400 - 238 - - - - 238
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
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 - - - 12,907 - - - 12,907
Unrealized net loss on marketable
equity securities available
for sale - - - - - - (151) (151)
Change in derivative instrument
fair value - - - - - - (3,041) (3,041)
----------
Total comprehensive income 9,715
----------
Cash dividends, $0.05 per share - - - (1,391) - - - (1,391)
ESPP disqualified disposition - - 20 - - - - 20
Sale of common stock, including
income tax benefit of stock
option exercises 79,233 1 1,018 - - - - 1,019
Directors' stock compensation 8,000 - 145 - - - - 145
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Balances, June 30, 2002 28,867,041 $ 289 $ 138,567 $ 169,255 (1,009,900) $ (16,210) $ 3,724 $ 295,625
========== ========== ========== ========== ========== ========== ========== ==========
The accompanying notes are an integral part of thest
consolidated financial statements.
7
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
---------------------------
June 30, 2002
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, 2001. 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, 2001. 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.
Certain amounts in the 2001 unaudited condensed consolidated financial
statements have been reclassified to correspond to the 2002 presentation.
Note 2 - Income Taxes
Federal income tax expense for the three and six months ended June 30,
2002 and 2001 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 Section 29 credits, percentage depletion, interest expense on convertible
debt with contingent interest provisions, and the effect of state income taxes.
For the six months ended June 30, 2002 the Company's current portion of income
tax expense was $1.5 million.
Note 3 - Long-term Debt
In March 2002 the Company issued in a private placement a total of
$100,000,000 of 5.75% senior convertible notes due 2022 (the "Notes") with a
1/2% contingent interest provision (see Note 4). Interest payments will be made
on March 15 and September 15 of every year beginning September 15, 2002. The
Company received net proceeds of $96,754,000 after deducting the initial
purchasers' discount and offering expenses paid by the Company. The Notes are
general unsecured obligations and rank on a parity in right of payment with all
existing and future senior indebtedness and other general unsecured obligations.
They are senior in right of payment with all future subordinated indebtedness.
The Notes are convertible into the Company's common stock at a conversion price
of $26.00 per share, subject to adjustment. The Company 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 the
Company 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, the Company may pay
the repurchase price with cash, shares of its common stock valued at a discount
to the market price at the time of repurchase or any combination of cash and its
discounted common stock. St. Mary is not restricted from paying dividends,
8
incurring debt, or issuing or repurchasing its securities under the indenture
for the Notes. There are no financial covenants in the indenture. The Company
used a portion of the net proceeds from the Notes to repay its credit facility
balance and will use the remaining net proceeds to fund a portion of its 2002
capital budget. On March 25, 2002 the Company entered into a five-year
fixed-rate to floating-rate interest rate swap on $50,000,000 of Notes. The
floating rate for each applicable six-month period will be determined as LIBOR
plus 0.36%. For the initial six-month calculation period this rate was 2.69%.
See "Note 4 - Financial Instruments" for a discussion of the derivative
accounting for the interest rate swap.
The stated total borrowing base under the Company's current long-term
revolving credit agreement was decreased to $160,000,000 in April 2002. Pursuant
to a March 4, 2002 amendment to the credit agreement, during the revolving
period of the loan, loan balances will accrue interest at the Company's option
of either (1) the higher of the federal funds rate plus 1/2% or the prime rate,
plus an additional 1/4% when the Company's debt to capitalization ratio is
greater than 50%, or (2) the LIBOR rate plus (a) 1% when the Company's debt to
total capitalization ratio is less than 30%, (b) 1 1/4% when the Company's debt
to capitalization ratio is greater than or equal to 30% but less than 40%, (c) 1
3/8% when the Company's debt to capitalization ratio is greater than or equal to
40% but less than 50%, or (d) 1 5/8% when the Company's debt to capitalization
ratio is greater than 50%. At June 30, 2002 the Company's debt to capitalization
ratio as defined under the credit agreement was 25.2%.
The Company had no outstanding borrowings under its revolving credit
agreement and $100,000,000 in outstanding borrowings under the Notes as of June
30, 2002. The weighted average interest rate paid for the second quarter of 2002
was 4.6 % including commitment fees paid on the unused portion of the borrowing
base.
Note 4 - Financial Instruments
The Company seeks to protect its rate of return on acquisitions of
producing properties by hedging cash flow when the economic criteria from its
evaluation and pricing model indicate it would be appropriate. Management's
strategy is to hedge cash flows from investments requiring a gas price in excess
of $3.25 per Mcf and an oil price in excess of $22.50 per Bbl in order to meet
minimum rate-of-return criteria. The Company anticipates this strategy will
result in the hedging of future cash flow from acquisitions. St. Mary generally
limits its aggregate hedge position to no more than 35% of its total production
but will hedge up to 50% of total production in certain circumstances. The
Company seeks 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 its areas of gas production.
On February 4, 2002 the Company entered into an agreement to monetize
its unrealized hedge gain receivable due from Enron for $1.1 million. This
amount was included in other comprehensive income at December 31, 2001, is
recorded in oil hedge gain and is reported in oil and gas production revenues in
the consolidated statements of operations. Amortization of $609,000 of other
comprehensive income related to commodity positions with Enron is also recorded
in oil hedge gain. Additional amortization will be recorded in oil hedge gain in
future months. Unrealized derivative loss on the consolidated statements of
operations includes $54,000 of net loss from oil and gas hedge ineffectiveness.
The Notes contain a provision for payment of contingent interest if
certain conditions are met. Under Statement of Financial Accounting Standards
("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 from the Notes 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 an adjustment to the Notes on the
consolidated balance sheets. Of this amount, $28,000 has been amortized through
interest expense. Unrealized derivative loss on the consolidated statements of
operations includes $245,000 of net loss from mark-to-market adjustments for
this derivative.
9
The fixed-rate to floating-rate interest rate swap on $50,000,000 of
Notes did not qualify for fair value hedge treatment under SFAS No. 133.
Unrealized derivative gain on the consolidated statements of operations includes
$2,244,000 of net gain from mark-to-market adjustments for this derivative
instrument.
The Company anticipates that all oil and gas hedge transactions will
occur as expected. Based on current prices we anticipate that $3,228,000 of the
after tax gain amount included in accumulated and other comprehensive income
will be included in earnings during the next 12 months.
Note 5 - Short-term Investments Available-for-Sale
The following short-term interest-bearing investment-grade securities
available for sale will mature within one year:
Amortized Gross Unrealized Aggregate
Major security type Cost Basis Holding Gains Fair Value
--------------------------------------------------------------------------------
Mortgaged-backed securities $ 995,000 $ - $ 995,000
8,375,000
Corporate debt securities 6,000 8,381,000
------------------------------------------------
Total securities $ 9,370,000 $ 6,000 $ 9,376,000
------------------------------------------------
Note 6 - Newly Issued Accounting Standards
In June 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." This statement addresses financial accounting and reporting for
costs associated with exit or disposal activities and nullifies EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in Restructuring)."
This statement requires recognition of a liability for a cost associated with an
exit or disposal activity when the liability is incurred, as opposed to when the
entity commits to an exit plan under EITF No. 94-3. SFAS No. 146 is to be
applied prospectively to exit or disposal activities initiated after December
31, 2002. The Company does not have any pending or planned exit or disposal
activities and does not expect a material effect on its financial position or
results of operations from the adoption of this statement.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." FASB No. 4 required all gains or losses from extinguishment of
debt to be classified as extraordinary items net of income taxes. SFAS No. 145
requires that gains and losses from extinguishment of debt be evaluated under
the provisions of Accounting Principles Board Opinion No. 30, and be classified
as ordinary items unless they are unusual or infrequent or meet the specific
criteria for treatment as an extraordinary item. This statement is effective
January 1, 2003. The Company does not anticipate that the adoption of this
statement will have a material effect on its financial position or results of
operations.
On January 1, 2002 the Company adopted SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." There was no impact on the
Company's financial position or results of operations as a result of the
adoption of this statement.
In June 2001 FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement requires companies to recognize the fair value of
an asset retirement liability in the financial statements by capitalizing that
cost as part of the cost of the related long-lived asset. The asset retirement
liability should then be allocated to expense by using a systematic and rational
method. The statement is effective January 1, 2003. The Company has not yet
determined the impact of adoption of this statement.
10
On January 1, 2002 the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets." There was no impact on the Company's financial
position or results of operations as a result of the adoption of this statement.
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, 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 2001 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.
Overview
When comparing the quarter ended June 30, 2002 to activity in 2001 the
focus will again be on oil and gas prices. Prices decreased compared to last
year but were higher this quarter than they were in the first quarter of 2002.
Our experience in the acquisition market during the quarter suggests to us that
this market may be moving toward our opinion of rationality. We remain hopeful
of meeting our acquisition budget this year. We continue to have a strong
balance sheet as a result of the $100.0 million senior convertible note private
placement we completed in the first quarter.
11
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, 2001.
Results of Operations
The following table sets forth selected operating data for the periods
indicated:
Three Months Six Months
---------------------- ----------------------
Ended June 30, Ended June 30,
---------------------- ----------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(In thousands, except per volume data)
Oil and gas production revenues:
Gas production $ 29,113 $ 40,970 $ 53,734 $ 93,350
Oil production 17,084 14,451 33,556 29,986
---------- ---------- ---------- ----------
Total $ 46,197 $ 55,421 $ 87,290 $ 123,336
========== ========== ========== ==========
Net production:
Gas (MMcf) 9,618 10,041 19,173 19,650
Oil (MBbls) 673 595 1,378 1,203
MCFE 13,655 13,611 27,440 26,868
Average sales price (1):
Gas (per Mcf) $ 3.03 $ 4.08 $ 2.80 $ 4.75
Oil (per Bbl) $ 25.39 $ 24.30 $ 24.35 $ 24.92
Oil and gas production costs:
Lease operating expense $ 8,177 $ 9,826 $ 18,626 $ 17,364
Transportation costs 761 541 1,577 6,991 2,593 3,069 1,138
Production taxes 2,593 3,069
---------- ---------- ---------- ----------
Total $ 11,531 $ 13,436 $ 25,561 $ 25,493
========== ========== ========== ==========
Additional per MCFE data:
Sales price $ 3.38 $ 4.07 $ 3.18 $ 4.59
Lease operating expense 0.60 0.72 0.68 0.65
Transportation costs 0.06 0.04 0.06 0.04
Production taxes 0.18 0.23 0.19 0.26
---------- ---------- ---------- ----------
Operating margin $ 2.54 $ 3.08 $ 2.25 $ 3.64
========== ========== ========== ==========
Depletion, depreciation and amortization $ 0.97 $ 0.95 $ 0.96 $ 0.90
Impairment of proved properties $ - $ 0.01 $ - $ 0.01 -
General and administrative $ 0.22 $ 0.26 $ 0.22 $ 0.28
------------
(1)Includes the effects of St. Mary's hedging activities.
Three-Month Comparison
Oil and Gas Production Revenues. Our quarterly oil and gas production
revenues decreased $9.2 million, or 17% to $46.2 million for the three months
ended June 30, 2002, compared with $55.4 million for the same period in 2001.
12
The following table presents the components of increases or (decreases) between
2002 and 2001:
Production Price Price
% Change $ Change % Change
------------------------------------
o Natural Gas (4%) ($1.05)/Mcf (26%)
o Oil 13% $1.09/Bbl 4%
Average net daily production increased to 150.1 MMCFE for 2002 compared
with 149.6 MMCFE in 2001. Our acquisition of properties from Choctaw in November
2001 added $3.4 million of revenue and average net daily production of 12.0
MMCFE to the second quarter of 2002. Other acquisitions and wells completed
during 2002 added average net daily production of 16.9 MMCFE. These increases in
average net daily production offset decreases from older properties.
We hedged approximately 39% or 260 MBbls of our oil production for the
three months ended June 30, 2002, and realized a $1.2 million increase in oil
revenue attributable to hedging compared with a $775,000 decrease in 2001.
Without these contracts our average price would have been $23.64 per Bbl in the
second quarter of 2002 compared to $25.60 per Bbl in 2001. We also hedged 44% of
our 2002 second quarter gas production or 4.6 million MMBtu and realized a $1.5
million decrease in gas revenue compared with a $5.1 million decrease in gas
revenue in 2001. Without these contracts our average price would have been $3.18
per Mcf for the three months ended June 30, 2002, compared to $4.51 per Mcf for
the same period in 2001.
Marketed Gas Revenue and Gas System Operating Expense. As a result of
our acquisition of gas gathering system lines in Cole County, Oklahoma in
February 2002 we started taking title to and marketing natural gas for third
parties. For the three months ended June 30, 2002 we received $2.9 million from
the sale of this natural gas. Operating costs associated with these revenues
totaled $2.7 million and resulted in gross margin to us of $277,000. 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 marketing.
Oil and Gas Production Costs. Oil and gas production costs consist of
lease operating expense, production taxes and transportation expenses. Total
production costs decreased $1.9 million or 14% to $11.5 million for the three
months ended June 30, 2002, from $13.4 million in 2001. In the second quarter of
2002 our Gulf Coast region experienced a $2.7 million decrease in LOE that was
comprised of a decrease in expense for non-recurring LOE and an adjustment due
to the issuance of a revised Authorization For Expenditure by the operator of
the Judge Digby field. This AFE indicated that non-recurring LOE we previously
expensed under the original AFE should be recorded as property, plant and
equipment. Our acquisition of properties from Choctaw in November 2001 added
$1.7 million of production costs in 2002 that were not reflected in 2001. Total
oil and gas production costs per MCFE decreased 15% to $0.84 for the three
months ended June 30, 2002 compared with $0.99 for 2001. A $0.07 per MCFE
decrease was due to the decrease in Gulf Coast non-recurring LOE. The Judge
Digby adjustment caused another $0.05 decrease. A $0.01 per MCFE increase was
due to the acquisitions previously discussed. A net $0.03 per MCFE decrease was
due to decreased production taxes partially offset by increased transportation
expenses.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion and amortization expense ("DD&A") increased $395,000 or 3% to
$13.3 million for the three months ended June 30, 2002, from $12.9 million in
2001. DD&A per MCFE increased by 2% to $0.97 for the second quarter of 2002
compared with $0.95 in 2001. This increase reflects acquisitions and drilling
results in 2001 and 2002 that have added costs at a higher per-unit rate.
13
Exploration. Exploration expense increased $2.1 million or 100% to $4.3
million for the three months ended June 30, 2002, compared with $2.1 million in
2001. Percentages of total exploration expense are as follows:
2002 2001
---- ----
o Geological and geophysical expenses 12% 26%
o Exploratory dry holes 46% -14%
o Overhead and other expenses 42% 88%
Oil and gas exploration is imprecise, and success can be affected by
numerous factors. Not every likely geological structure contains oil or natural
gas. Even when oil or natural gas is discovered there are no guarantees that
sufficient quantities can be produced to justify the completion of an
exploratory well. We have budgeted for additional geological and geophysical
expenses and expect to incur additional overhead and other expenses in the
pursuit of exploration, but we generally explore with an expectation of success.
General and Administrative. General and administrative expenses
decreased $521,000 or 15% to $3.0 million for the three months ended June 30,
2002, compared with $3.5 million in 2001. We experienced a $491,000 increase in
COPAS overhead reimbursement from operations in this quarter.
Interest Expense. Interest expense increased to $1.0 million for the
quarter ended June 30, 2002. This amount reflects accrued interest on our senior
convertible notes and will increase significantly on a comparative basis with
last year as we accrue and pay the interest due on the notes. The amount we
accrue and pay will be affected by the fixed-rate to floating-rate interest rate
swap we entered into in March 2002.
Income Taxes. Income tax expense totaled $5.3 million for the three
months ended June 30, 2002, and $8.9 million in 2001, resulting in effective tax
rates of 33.2% and 38.4%, respectively. This decrease is a result of the tax
effect of interest expense on convertible debt with contingent interest
provisions combined with a lesser effect of state income taxes and an increase
in the effect on Section 29 credits on a lesser net income in 2002.
Net Income. Net income for the three months ended June 30, 2002
decreased $3.6 million to $10.6 million compared with $14.2 million in 2001. A
26% decrease in gas prices and a 4% increase in oil prices combined with a 13%
increase in oil production and a 4% decrease in gas production resulted in a
$9.2 million decrease in oil and gas production revenue. This decrease was
offset by decreases of $1.9 million in oil and gas production costs and $3.6
million in income tax expense.
Six-Month Comparison
Oil and Gas Production Revenues. We experienced a decrease in oil and
gas production revenues of $36.0 million, or 29% to $87.3 million for the six
months ended June 30, 2002, compared with $123.3 million for the same period in
2001. The following table presents the components of increases or (decreases)
between 2002 and 2001:
Production Price Price
%Change $ Change % Change
------------------------------------
o Natural Gas (2%) ($1.95)/Mcf (41%)
o Oil 15% ($0.57)/Bbl (2%)
Average net daily production increased to 151.6 MMCFE for the first six
months of 2002 compared with 148.4 MMCFE in 2001. Our acquisition of properties
from Choctaw in November 2001 added $6.7 million of revenue and average net
daily production of 12.1 MMCFE to the first six months of 2002. Other
14
acquisitions and wells completed during 2002 added average net daily production
of 9.6 MMCFE. These increases offset declines in average net daily production
from older properties.
We hedged approximately 39% or 542 MBbls of our oil production for the
six months ended June 30, 2002, and realized a $2.6 million increase in oil
revenue attributable to hedging compared with a $1.9 million decrease in 2001.
Without these contracts we would have received an average price of $22.46 per
Bbl for the six months ended June 30, 2002 compared to $26.48 per Bbl in 2001.
We also hedged 43% of our gas production or 9.0 million MMBtu and realized a
$904,000 increase in gas revenue for the six months ended June 30, 2002 compared
with a $20.4 million decrease in gas revenue in 2001. Without these contracts we
would have received an average price of $2.76 per Mcf for the six months ended
June 30, 2002, compared to $5.79 per Mcf for the same period in 2001.
Marketed Gas Revenue and Gas System Operating Expense. As a result of
our acquisition of gas gathering system lines in Cole County, Oklahoma in
February 2002 we started taking title to and marketing natural gas for third
parties. For the six months ended June 30, 2002 we received $3.4 million from
the sale of this natural gas. Costs associated with these revenues totaled $3.1
million and resulted in gross margin to us of $358,000.
Oil and Gas Production Costs. Total production costs increased slightly
to $25.6 million for the six months ended June 30, 2002, from $25.5 million in
2001. Our acquisition of properties from Choctaw added 2.6 million of LOE in
2002 that was not reflected in 2001. In the second quarter of 2002 our Gulf
Coast region experienced a $2.7 million decrease in LOE that was comprised of a
decrease in expense for non-recurring LOE and an adjustment due to the issuance
of a revised AFE by the Operator at Judge Digby. This AFE indicated that
non-recurring LOE we previously expensed under the original AFE should be
recorded as property, plant and equipment. This decrease offset $1.4 million of
increases we expected from general inflation. The decrease in oil and gas
production revenues caused a corresponding $1.6 million decrease in production
taxes. Total oil and gas production costs per MCFE decreased 2% to $0.93 for the
six months ended June 30, 2002 compared with $0.95 for 2001. A $0.07 per MCFE
decrease in production taxes offset a $0.05 per MCFE increase in LOE and
transportation costs. We continue to concentrate on these costs in an effort to
decrease the per MCFE amounts using a cost-benefit approach that will still
justify additional expenditures when appropriate.
Depreciation, Depletion, Amortization and Impairment. DD&A
increased $2.2 million or 9% to $26.3 million for the six months ended June 30,
2002, from $24.2 million in 2001. DD&A per MCFE increased by 7% to $0.96 for
the six months ended June 30, 2002 compared with $.90 in 2001. This increase
reflects acquisitions and drilling results in 2001 and 2002 that added costs at
a higher per unit rate.
Exploration. Exploration expense increased $701,000 or 7% to $11.2
million for the six months ended June 30, 2002, compared with $10.5 million in
2001. Percentages of total exploration expense are as follows:
2002 2001
---- ----
o Geological and geophysical expenses 11% 22%
o Exploratory dry holes 55% 42%
o Overhead and other expenses 34% 36%
General and Administrative. General and administrative expenses
decreased $1.4 million or 19% to $6.2 million for the six months ended June 30,
2002, compared with $7.6 million in 2001. We experienced a $955,000 increase in
COPAS overhead reimbursement from operations in this period and a $275,000
decrease in compensation expense caused primarily by decreased compensation
related to our incentive plans.
15
Interest Expense. Interest expense increased to $1.5 million for the
six months ended June 30, 2002. This amount reflects accrued interest on our
senior convertible notes and will increase significantly on a comparative basis
with last year as we accrue and pay the interest due on the notes in 2002. The
amount we accrue and pay will be affected by the fixed-rate to floating-rate
interest rate swap we entered into in March 2002.
Income Taxes. Income tax expense totaled $6.4 million for the six
months ended June 30, 2002, and $20.4 million in 2001, resulting in effective
tax rates of 33.1% and 37.0%, respectively. This decrease is a result of the tax
effect of interest expense on convertible debt with contingent interest
provisions combined with a lesser effect of state income taxes and an increase
in the effect on Section 29 credits on a lesser net income in 2002.
Net Income. Net income for the six months ended June 30, 2002 decreased
$21.7 million or 63% to $12.9 million compared with $34.6 million in 2001. A 41%
decrease in gas prices and a 2% decrease in oil prices combined with a 14%
increase in oil production and a 2% decrease in gas production resulted in a
$36.0 million decrease in oil and gas production revenue. This decrease was
offset by a corresponding $14.0 million decrease in income tax expense.
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. An unexpected decrease in 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. In the event of an unexpected decrease in oil and gas
prices, cash uses such as the acquisition of oil and gas properties and the
payment of stockholder dividends are discretionary and can be reduced or
eliminated. 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. An unexpected increase in oil and gas prices provides flexibility
to modify our uses of cash flow.
We continually review our capital expenditure budget to reflect changes
in current and projected cash flow, acquisition opportunities, debt requirements
and other factors.
Cash Flow. Net cash provided by operating activities increased $3.2
million or 4% to $76.1 million for the six months ended June 30, 2002 compared
with $72.9 million in 2001. The increase reflects the effect of a change between
years of $14.9 million from the collection of receivables and $15.1 million in
decreases of cash spent for other current assets and liabilities offset by the
effect of the decrease in oil and gas production revenues.
Net cash used in investing activities increased $10.5 million or 19% to
$64.5 million for the six months ended June 30, 2002, compared with $54.0
million in 2001. This increase is due to a $9.4 million investment in short-term
securities in 2002 and a $3.9 million decrease in receipts from sales of KMOC
stock offset by decreased capital expenditures. Total capital expenditures,
including acquisitions of oil and gas properties, in the first six months of
2002 decreased $5.5 million or 9% to $56.2 million compared with $61.7 million
in the first half of 2001.
16
Net cash provided by financing activities increased $51.4 million to
$32.1 million for the six months ended June 30, 2002, compared with net cash
used in financing activities of $19.2 million in 2001. This increase reflects
our March 2002 private placement of $100.0 million of 5.75% senior convertible
notes due 2022. A portion of the net proceeds of $96.8 million was used to repay
the balance due on the credit facility. We have not repurchased any common stock
in the first six months of 2002.
St. Mary had $47.9 million in cash and cash equivalents and had working
capital of $60.0 million as of June 30, 2002, compared with $4.1 million in cash
and cash equivalents and working capital of $34.0 million at December 31, 2001.
The increase in cash and cash equivalents reflects our issuance of $100.0
million of senior convertible notes during the first quarter of 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 1/2% contingent interest provision. Interest payments will commence
September 15, 2002 and will be made 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 will use the remaining net proceeds to
fund a portion of our 2002 capital budget. 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 for each applicable six-month period will be determined
as LIBOR plus 0.36%. For the initial calculation period this rate was 2.69%.
Credit Facility. The maximum loan amount under our long-term revolving
credit facility is $200.0 million. The amount actually available depends upon a
borrowing base that the lenders periodically redetermine based on the value of
our oil and gas properties and other assets. Since we pay commitment fees based
on the unused portion of the borrowing base, we have generally limited the
borrowing base which we have accepted to correspond to our actual funding
requirements. On April 10, 2002 the stated total possible borrowing base was
reduced by $10.0 million to $160.0 million and the accepted borrowing base was
reduced by $60.0 million to $40.0 million. The facility has a maturity date of
December 31, 2006, and includes a revolving period that matures on June 30, 2003
at which time all outstanding borrowings convert to a term loan payable in
quarterly installments through the facility maturity date. We must comply with
certain covenants including maintenance of stockholders' equity at a specified
level, restrictions on additional indebtedness, sales of oil and gas properties,
activities outside our ordinary course of business and certain merger
transactions. Borrowings under the facility are secured by a pledge of
collateral in favor of the banks and guarantees by subsidiaries. Such collateral
consists primarily of security interests in the oil and gas properties of St.
Mary and its subsidiaries.
As of June 30, 2002 we had no balance outstanding under this credit
agreement, compared to $64 million at December 31, 2001. Pursuant to a March 4,
2002 amendment to the credit agreement, during the revolving period of the loan,
loan balances will accrue interest at our option of either (1) the higher of the
federal funds rate plus 1/2% or the prime rate, plus an additional 1/4% when our
debt to capitalization ratio is greater than 50%, or (2) the LIBOR rate plus (a)
1% when our debt to total capitalization ratio is less than 30%, (b) 1 1/4 %
when our debt to capitalization ratio is greater than or equal to 30% but less
than 40%, (c) 1 3/8% when our debt to capitalization ratio is greater than or
17
equal to 40% but less than 50%, or (d) 1 5/8% when our debt to capitalization
ratio is greater than 50%. At June 30, 2002 our debt to capitalization ratio as
defined under the credit agreement was 25.2%.
Schedule of Contractual Obligations. The following table summarizes our
future estimated principal payments for the periods specified:
Contractual Total Cash
Obligations Long-Term Debt Operating Leases Obligation
----------- -------------- ---------------- --------------
Less than 1 year - $1.1 million $ 1.1 million
1-3 years - $1.2 million $ 1.2 million
4-5 years - $1.4 million $ 1.4 million
After 5 years $100.0 million $3.2 million $103.2 million
-------------- ------------ --------------
Total $100.0 million $6.9 million $106.9 million
============== ============ ==============
In the period from 1-3 years, we have two leases 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
senior convertible notes will not exercise the conversion feature.
Common Stock. In August 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, 2002 we have repurchased a cumulative total of 1,009,900 shares
of St. Mary's common stock under the program for $16.2 million at a weighted
average price of $15.86 per share, net of put option sale premiums received. 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.
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.
Capital and Exploration Expenditures
------------------------------------
Six Months Ended June 30,
-------------------------
2002 2001
---- ----
(In thousands)
Development $ 30,444 $ 43,451
Domestic Exploration 9,034 14,639
Acquisitions:
Proved 7,040 301
Unproved 8,597 10,110
-------- --------
Total $ 55,115 $ 68,501
======== ========
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 smaller niche acquisitions
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.
18
St. Mary's total costs incurred in the first six months of 2002
decreased $13.4 million or 20% compared to the first six months of 2001. We
spent $48.1 million in the first six months of 2002 for unproved property
acquisitions and domestic exploration and development compared to $68.2 million
for the comparable period in 2001. This decrease was a result of planned
decreases in drilling activity and a $1.5 million decrease in unproved leasehold
acquisition activity. We successfully obtained permits to begin producing our
two coalbed methane pilot programs located on fee acreage in the Hanging Woman
Basin. A total of 17 wells are being equipped for production and dewatering
began in May. In April we were successful in obtaining an additional 10,000
acres of leases bringing our total to 127,000 acres in the Hanging Woman Basin.
We are subject to an environmental public interest group lawsuit on 47,500 of
these acres. See "Legal Proceedings" for a discussion of this lawsuit.
On April 26, 2002 the Interior Board of Land Appeals of the U.S.
Department of the Interior issued an order that reversed a decision by the U.S.
Bureau of Land Management dismissing a protest by the Wyoming Outdoor Council
and Powder River Basin Resource Council of the offer for sale in February 2000
of three oil and gas leases in the Powder River Basin in Wyoming. The Board held
that the BLM determination to allow the offer for sale of the three particular
leases did not comply with environmental laws since the environmental analysis
used by the BLM in making that determination did not contain a discussion of the
unique potential impacts associated with coalbed methane extraction and
development or consider reasonable alternatives relevant to a pre-leasing
environmental analysis. The order addressed only three particular leases
covering approximately 2,600 acres that are not included in our Hanging Woman
Basin project. However, we cannot assure you that other leases, including issued
leases that we hold in the Hanging Woman Basin, will not be challenged on a
similar basis.
In November 2001 we purchased oil and gas properties from Choctaw II
Oil & Gas, Ltd. for $40.5 million in cash. We used a portion of our credit
facility for this acquisition. The properties are primarily located in the
Williston Basin of Montana and North Dakota and in the Green River Basin of
Wyoming.
Capital Expenditure Budget. We anticipate spending approximately $164.0
million for capital and exploration expenditures in 2002 with $60.0 million for
acquisitions. Budgeted ongoing exploration and development expenditures in 2002
for each of our core areas is as follows (in millions):
o Mid-Continent region $ 40.0
o Gulf Coast and Gulf of Mexico region 15.0
o ArkLaTex region 14.0
o Williston Basin 20.0
o Permian Basin 8.0
o Other 7.0
-------
Total $ 104.0
=======
We believe the amount not funded from our internally generated cash
flow in 2002 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
19
strategy is to hedge cash flows from investments requiring a gas price in excess
of $3.25 per Mcf and an oil price in excess of $22.50 per Bbl in order to meet
minimum rate-of-return criteria. Management reviews these hedging parameters on
a quarterly basis. We anticipate this strategy will result in the hedging of
future cash flow from acquisitions. We generally limit our aggregate hedge
position to no more than 35% of total production but will hedge up to 50% 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. Including hedges entered into since June 30, 2002 we
have the following swaps in place:
Swaps:
Average Quantity Average
Product Volumes/month Type Fixed price Duration
------- ------------- -------- ----------- --------
Natural Gas 1,058,000 MMBtu $2.85 07/02 - 12/02
Natural Gas 468,000 MMBtu $3.34 01/03 - 12/03
Natural Gas 229,000 MMBtu $3.81 01/04 - 12/04
Oil 57,700 Bbls $24.77 07/02 - 12/02
Oil 49,800 Bbls $22.68 01/03 - 12/03
On February 4, 2002 we entered into an agreement to monetize our
unrealized hedge gain receivable due from Enron for $1.1 million. This amount
was included in other comprehensive income at December 31, 2001, is recorded in
oil hedge gain and is reported in oil and gas production revenues on our
consolidated statements of operations. Amortization of $609,000 of other
comprehensive income related to our commodity positions with Enron is also
recorded in oil hedge gain. Additional amortization will be recorded in oil
hedge gain in future months. Unrealized derivative gain on the consolidated
statements of operations includes $54,000 of net gain from oil and gas hedge
ineffectiveness.
Our senior convertible notes contain a provision for payment of
contingent interest if certain conditions are met. Under Statement of Financial
Accounting Standards 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 was $474,000.
This amount was recorded as a decrease to the convertible notes payable on the
consolidated balance sheets. Of this amount, $28,000 has been amortized through
interest expense. Unrealized derivative gain on the consolidated statements of
operations includes $245,000 of net loss from mark-to-market adjustments for
this derivative.
Our fixed-rate to floating-rate interest rate swap on $50.0 million of
senior convertible notes did not qualify for fair value hedge treatment under
SFAS No. 133. Unrealized derivative gain on the consolidated statements of
operations includes $2.2 million of net gain from mark-to-market adjustments for
this derivative.
We anticipate that all hedge transactions will occur as expected.
Accounting Matters
New Accounting Standards
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." FASB No. 146 requires recognition
of a liability for a cost associated with an exit or disposal activity when the
liability is incurred, as opposed to when the entity commits to an exit plan
under EITF No. 94-3. This statement is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. We have not determined
the impact of adoption of this statement.
20
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." FASB No. 4 required all gains or losses from extinguishment of
debt to be classified as extraordinary items net of income taxes. SFAS No. 145
requires that gains and losses from extinguishment of debt be evaluated under
the provisions of Accounting Principles Board Opinion No. 30, and be classified
as ordinary items unless they are unusual or infrequent or meet the specific
criteria for treatment as an extraordinary item. This statement is effective for
fiscal years beginning after May 15, 2002. We do not anticipate that the
adoption of this statement will have a material effect on our financial position
or results of operations.
In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires companies to recognize the fair
value of an asset retirement liability in the financial statements by
capitalizing that cost as part of the cost of the related long-lived asset. The
asset retirement liability should then be allocated to expense by using a
systematic and rational method. The statement is effective January 1, 2003. We
have not determined the impact of adoption of this statement.
Compensation Expense
We have a net profits interest incentive bonus plan for key employees
designated as participants by our board of directors. Under the plan oil and gas
wells that are completed or acquired during a year are designated as a pool.
Participants employed by us on the last day of that year vest and become
entitled to bonus payments after we recover net revenues generated by the pool
equal to 100% of our investment in that pool. Thereafter an amount equal to10%
of net revenues generated by the pool will be split among the participants and
paid on a quarterly basis. The percentage of net revenues from the pool to be
split among the participants increases to 20% after we recover net revenues
equal to 200% of our investment.
Beginning in 2002 we changed our method of accounting to record
estimated compensation expense related to future amounts payable to participants
under the plan on a quarterly basis in the plan year that the participants vest.
The estimated compensation expense will be based on a number of assumptions
including estimates of oil and gas production, oil and gas prices, recurring and
non-recurring lease operating expense and a present value discount factor. We
use a discount factor to calculate present value that reflects recovery of our
investment, the timing of payments to participants and uncertainties associated
with our estimates. The estimates we use will change from year-to-year based on
new information and any change in estimated compensation will be recorded in the
period that information becomes available.
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
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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 18.1 million
MMBtu would cause a potential $1.6 million change in net income before income
taxes for contracts in place on June 30, 2002. 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 1.4 million Bbls would cause a potential $1.3 million
change in net income before income taxes for oil contracts in place on June 30,
2002. 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, 2002, 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, 2002, we had floating rate debt of $50.0 million and
$50.0 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
$250,000 before taxes.
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
-----------------
On March 27, 2002 Nance Petroleum Corporation, a wholly owned
subsidiary, was named along with several other leaseholders and
interested parties as an additional co-defendant in a lawsuit that was
originally filed on June 12, 2001 in the U.S. District Court for the
District of Montana by the Northern Plains Resource Council, Inc., an
environmental public interest group, against the U.S. Bureau of Land
Management, the U.S. Secretary of the Interior, the Montana BLM State
Director and Fidelity Exploration & Production Company. The
lawsuit, which was reported in our 2001 Form 10-K and our first quarter
2002 Form 10-Q, seeks the cancellation of all federal leases related to
coalbed methane development issued by the BLM in Montana since January
1, 1997, primarily on the grounds of an alleged failure of the BLM to
comply with federal environmental laws by analyzing the environmental
impacts of coalbed methane development before issuing the challenged
leases. The lawsuit potentially affects 47,500 acres subject to federal
leases of the 127,000 total acres in our Hanging Woman Basin coalbed
methane project. While we believe, based on information presently
available to us that the applicable environmental laws have been
complied with, there is no assurance of the outcome of the lawsuit and
therefore there is no assurance that it will not adversely affect our
coalbed methane project. However, even if the federal leases in Montana
become unavailable, we anticipate continuing with the Hanging Woman
Basin project in Wyoming and obtaining additional non-federal leases in
Montana. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a discussion of other recent
coalbed methane legal developments.
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As previously reported in our first quarter 2002 Form 10-Q, on
May 1, 2002 GNK Acquisition Corp., a recently acquired wholly owned
subsidiary, was served in a lawsuit that was filed earlier in 2002 in
the District Court in Shelby County, Texas, by Samson Lone Star Limited
Partnership against GNK Acquisition Corp. and GNK, Inc., the previous
owner of GNK Acquisition Corp. The lawsuit primarily involves a claim
related to certain oil and gas leasehold positions acquired by GNK
Acquisition Corp. under a contractual preferential right to purchase
that was triggered by an attempt by Samson to acquire such leasehold
positions from the party that sold the positions to GNK Acquisition
Corp. Samson alleges that it should be entitled to acquire a portion of
such positions as a result of an agreement it had with GNK, Inc. An
answer by GNK Acquisition Corp. to the underlying petition by Samson
has been filed, and discovery has begun. Although the lawsuit is in a
very preliminary stage and there can be no assurance of the ultimate
outcome, we do not believe based on the information presently available
that the lawsuit will have a material adverse effect on our financial
condition or results of operations.
ITEM 2. Changes in Securities and Use of Proceeds
-----------------------------------------
(c) On June 4, 2002 St. Mary issued 800 restricted shares of common stock
to a newly elected director as compensation recorded in the amount of
$14,763 for services as a member of the board of directors. These
shares were not registered under the Securities Act of 1933 in reliance
on Rule 506 of Regulation D promulgated under the Securities Act since
the director is an accredited investor and certificates representing
the shares bear a legend restricting the transfer of those shares.
ITEM 4. Submission of Matters to a Vote of Security Holders
----------------------------------------------------
At the Company's annual stockholders' meeting on May 20, 2002, 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
-------- --- --------
Larry W. Bickle 19,273,354 558,050
Barbara M. Baumann 19,292,967 538,437
Ronald D. Boone 19,273,374 558,030
Thomas E. Congdon 18,913,554 917,850
William J. Gardiner 19,273,354 558,050
Mark A. Hellerstein 19,273,374 558,030
Robert L. Nance 19,273,354 558,050
Arend J. Sandbulte 19,273,354 558,050
John M. Seidl 19,273,354 558,050
Also at the Company's annual stockholders' meeting on May 20, 2002, the
stockholders did not approve a proposed amendment to the Company's
certificate of incorporation to authorize the issuance of up to a total
of 5,000,000 shares of preferred stock with such powers, preferences,
rights and limitations as the board of directors may designate from
time to time. The tabulation of votes for that proposal is as follows:
For: 7,822,200
Against: 8,963,607
Abstain: 377,120
Not Voted: 2,668,477
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ITEM 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits
The following exhibits are furnished as part of this report:
Exhibit Description
------- -----------
10.1 Security Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company, St. Mary Operating Company, St.
Mary Energy Company, Nance Petroleum Corporation, St. Mary
Minerals Inc., Parish Corporation, Four Winds Marketing,
LLC and Roswell, L.L.C. in favor of Bank of America, N.A.
10.2 Stock Pledge Agreement made as of May 1, 2002 by St. Mary
Land & Exploration Company in favor of Bank of America,
N.A.
10.3 LLC Pledge Agreement made as of May 1, 2002 by St. Mary
Land & Exploration Company in favor of Bank of America,
N.A.
10.4 Guaranty made as of May 1, 2002 by St. Mary Operating
Company, St. Mary Energy Company, Nance Petroleum
Corporation, St. Mary Minerals, Inc., Parish Corporation,
Four Winds Marketing LLC and Roswell LLC in favor of Bank of
America, N.A.
(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, 2002:
On April 30, 2002 we filed a current report on Form 8-K
reporting under Item 9 that we had issued a press release announcing an
update of our first quarter 2002 operations and an update of our 2002
forecast.
On May 10, 2002 we filed a current report on Form 8-K
reporting under Item 9 that we had issued a press release announcing
our earnings and financial highlights for the first quarter of 2002.
On May 30, 2002 we filed a current report on Form 8-K
reporting under Item 4 that we had dismissed Arthur Andersen LLP as our
independent accountants.
On June 4, 2002 we filed a current report on Form 8-K
reporting under Item 4 that we had engaged Deloitte & Touche LLP as
our new independent accountants.
On July 9, 2002 we filed a current report on Form 8-K
reporting under Item 9 that we had issued a press release announcing an
update of our operations for the second quarter of 2002 and an updating
of our 2002 forecast.
On August 8, 2002 we filed a current report on Form 8-K
reporting under Item 9 that we had issued a press release announcing
our earnings and financial highlights for the second quarter of 2002.
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On August 8, 2002 we filed an amended current report on Form
8-K/A to include a conformed signature for the Form 8-K filed August 8,
2002. The conformed signature was inadvertently omitted from the
originally-filed Form 8-K.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
August 14, 2002 By /s/ MARK A. HELLERSTEIN
-----------------------------------
Mark A. Hellerstein
President and Chief Executive Officer
August 14, 2002 By /s/ RICHARD C. NORRIS
-----------------------------------
Richard C. Norris
Vice President - Finance, Secretary
and Treasurer
August 14, 2002 By /s/ GARRY A. WILKENING
-----------------------------------
Garry A. Wilkening
Vice President - Administration and
Controller