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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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
of incorporation or organization) Identification No.)
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 issuers classes of
common stock as of the latest practicable date.
As of May 13, 2002, the registrant had 27,821,480 shares of common stock, $.01
par value, outstanding.
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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 - March 31, 2002 and
December 31, 2001.................................3
Consolidated Statements of
Operations - Three Months Ended
March 31, 2002 and 2001...........................4
Consolidated Statements of
Cash Flows - Three Months Ended
March 31, 2002 and 2001...........................5
Consolidated Statements of
Stockholders' Equity and Comprehensive
Income - March 31, 2002
and December 31, 2001.............................7
Notes to Consolidated Financial
Statements - March 31, 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................................19
Part II. OTHER INFORMATION
Item 1. Legal Proceedings.............................20
Item 2. Changes in Securities and Use of Proceeds.....20
Item 6. Exhibits and Reports on Form 8-K..............21
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 March 31, December 31,
------------- -------------
2002 2001
------------- -------------
Current assets:
Cash and cash equivalents $ 63,191 $ 4,116
Accounts receivable 32,334 46,484
Prepaid expenses and other 6,673 2,337
Accrued derivative asset 9,845 8,194
Refundable income taxes 1,945 11,090
Deferred income taxes 29 -
------------- -------------
Total current assets 114,017 72,221
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Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 551,600 518,915
Less accumulated depletion, depreciation and amortization (228,876) (216,288)
Unproved oil and gas properties, net of impairment
allowance of $9,116 in 2002 and $8,908 in 2001 47,448 53,054
Other property and equipment, net of accumulated depreciation of $3,299
in 2002 and $3,120 in 2001 3,432 3,252
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Total property and equipment 373,604 358,930
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Other assets:
Khanty Mansiysk Oil Corporation stock - 1,651
Other assets 9,110 4,187
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Total other assets 9,110 5,838
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Total Assets $ 496,731 $ 436,989
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 33,777 $ 34,858
Deferred tax liability 3,640 3,363
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Total current liabilities 37,417 38,221
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Long-term liabilities:
Long-term credit facility 20,000 64,000
Convertible notes (net of discount of $470,000 in 2002) 99,530 -
Deferred income taxes 48,174 47,685
Other noncurrent liabilities 1,981 255
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Total long-term liabilities 169,685 111,940
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Commitments and contingencies
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Minority interest 623 711
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Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares: Issued and
outstanding - 28,818,051 shares in 2002 and 28,779,808 shares in 2001 288 288
Additional paid-in capital 137,929 137,384
Treasury stock - at cost: 1,009,900 shares in 2002 and 2001 (16,210) (16,210)
Retained earnings 160,057 157,739
Accumulated other comprehensive income 6,942 6,916
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Total stockholders' equity 289,006 286,117
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Total Liabilities and Stockholders' Equity $ 496,731 $ 436,989
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3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per share amounts)
For the Three Months Ended
March 31,
------------------------------------
2002 2001
--------------- ---------------
Operating revenues:
Oil and gas production $ 41,093 $ 67,915
Gain (loss) on sale of proved properties (36) 2
Other oil and gas revenue 855 362
Gain on sale of KMOC stock 836 -
Other revenues 25 68
--------------- ---------------
Total operating revenues 42,773 68,347
--------------- ---------------
Operating expenses:
Oil and gas production 14,030 12,057
Depletion, depreciation and amortization 13,054 11,288
Exploration 6,916 8,362
Impairment of proved properties - 171
Abandonment and impairment of unproved properties 697 466
General and administrative 3,141 4,021
Unrealized derivative loss 352 -
Minority interest and other 801 261
--------------- ---------------
Total operating expenses 38,991 36,626
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Income from operations 3,782 31,721
Nonoperating income (expense):
Interest income 110 188
Interest expense (452) (35)
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Income before income taxes 3,440 31,874
Income tax expense 1,122 11,481
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Net income $ 2,318 $ 20,393
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Basic net income per common share $ .08 $ .72
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Diluted net income per common share $ .08 $ .71
=============== ===============
Basic weighted average common shares outstanding 27,786 28,236
=============== ===============
Diluted weighted average common shares outstanding 28,294 28,932
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4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
For the Three Months Ended
March 31,
--------------------------------
2002 2001
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Reconciliation of net income to net cash provided by operating activities:
Net income $ 2,318 $ 20,393
Adjustments to reconcile net income to net
cash provided by operating activities:
Gain on sale of KMOC stock (836) -
(Gain) loss on sale of proved properties 36 (2)
Unrealized derivative loss 352 262
Depletion, depreciation and amortization 13,054 11,288
Exploratory dry hole expense 4,178 4,961
Impairment of proved properties - 171
Abandonment and impairment of unproved properties 697 466
Deferred income taxes 840 6,504
Minority interest and other (791) 414
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19,848 44,457
Changes in current assets and liabilities:
Accounts receivable 12,956 (4,020)
Prepaid expenses and refundable income taxes 4,829 (1,577)
Accounts payable and accrued expenses 4,159 9,720
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Net cash provided by operating activities 41,792 48,580
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Cash flows from investing activities:
Proceeds from sale of oil and gas properties - 201
Capital expenditures (26,564) (36,013)
Acquisition of oil and gas properties (12,726) (1,213)
Proceeds from distribution and sale of KMOC stock 3,114 7,009
Other 274 (19)
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Net cash used in investing activities (35,902) (30,035)
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Cash flows from financing activities:
Proceeds from credit facility 16,000 13,550
Repayment of credit facility (60,000) (35,550)
Proceeds from issuance of convertible notes 96,854 -
Proceeds from sale of common stock 331 1,405
Repurchase of common stock - (1,787)
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Net cash provided by (used in) financing activities 53,185 (22,382)
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Net change in cash and cash equivalents 59,075 (3,837)
Cash and cash equivalents at beginning of period 4,116 6,619
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Cash and cash equivalents at end of period $ 63,191 $ 2,782
============= =============
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 Three Months Ended
March 31,
--------------------------------
2002 2001
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(In thousands)
Cash paid for interest $ 322 $ 225
Cash paid (received) for income taxes (8,883) 3,523
Cash paid for exploration expenses 6,916 8,479
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
6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(unaudited)
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock 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 - - - 2,318 - - - 2,318
Unrealized net loss on marketable equity
securities available for sale - - - - - - (148) (148)
Change in derivative instrument fair value - - - - - - 174 174
Total comprehensive income 2,344
Sale of common stock, including income
tax benefit of stock option exercises 31,043 - 415 - - - - 415
Directors' stock compensation 7,200 - 130 - - - - 130
---------- -------- -------- ------- --------- ------- ------ --------
Balances, March 31, 2002 28,818,051 $288 $137,929 $160,057 (1,009,900) $(16,210) $6,942 $289,006
========== ======== ======== ======= ========= ======= ====== ========
7
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
------------------------------
March 31, 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 period
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 months ended March 31, 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. At
March 31, 2002 the Company's current portion of income tax expense was $197,000.
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). The Company received net
proceeds of $96,900,000 after deducting the initial purchasers' discount and
estimated offering expenses payable 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 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 or any combination of cash and its common
stock. St. Mary is not restricted from paying dividends, incurring debt, or
8
issuing or repurchasing its securities under the indenture. 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 swap
on $50 million of Notes. The floating rate for each applicable six-month period
will be determined as LIBOR plus 0.38%. For the initial six-month calculation
period this rate was 2.69%.
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, 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 March 31, 2002 the Company's debt to capitalization ratio as defined
under the credit agreement was 29.3%.
The Company had $20,000,000 in outstanding borrowings under its revolving
credit agreement and $100,000,000 in outstanding borrowings under the Notes as
of March 31, 2002. The weighted average interest rate paid for the first quarter
of 2002 was 3.4% 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 indexes 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 area of gas production.
On February 4, 2002 St. Mary 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 in the current quarter and is reported in oil and gas production
revenues for this quarter in the consolidated statements of operations. Future
amortization of amounts in other comprehensive income related to commodity
positions with Enron will be recorded in oil hedge gain in future months.
Unrealized derivative loss on the consolidated statements of operations includes
$187,000 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 was $474,000. This amount
9
was recorded as an adjustment to the Notes on the consolidated balance sheets.
Of this amount, $3,000 has been amortized through interest expense. Unrealized
derivative loss on the consolidated statements of operations includes $121,000
of net loss from mark-to-market adjustments for this derivative
The fixed-rate to floating-rate interest rate swap on $50 million of Notes
did not qualify for fair value hedge treatment under SFAS No. 133. Unrealized
derivative loss on the consolidated statements of operations includes $44,000 of
net loss 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 $6,285,000 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 - Recently Issued Accounting Standards
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.
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 July 2001 the Financial Accounting Standards Board ("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.
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.
10
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 expression 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,
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 and developments, the
potential impact of government regulations, and other matters such as those
discussed in the "Risk Factors" section of our 2001 Annual Report on Form 10-K,
many of which are beyond our control. 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
In the quarter ended March 31, 2002 the focus was on oil and gas prices,
especially with respect to comparisons with activity in 2001. We anticipated
that prices would decrease compared to last year and they did. Toward the end of
the quarter prices began to rebound as a result of the conflict in the Middle
East and declining natural gas supplies. Last year we saw increases in drilling
and completion costs and an overheated acquisition market which made reserve
additions costly. In addition, we saw inflation of operating costs. We have
recently experienced decreases in rig service rates, but caution that higher oil
and gas prices could cause those rate decreases to reverse. We completed a $100
million senior convertible note private placement during the quarter that has
helped to provide us with the strongest balance sheet in our history.
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 Ended March 31,
----------------------------
2002 2001
----- ----
(In thousands, except per volume data)
Oil and gas production revenues:
Gas production $ 24,621 $ 52,380
Oil production 16,472 15,535
----------- ------------
Total $ 41,093 $ 67,915
=========== ============
Net production:
Gas (MMcf) 9,555 9,609
Oil (MBbls) 705 608
MMCFE 13,785 13,257
Average sales price (1):
Gas (per Mcf) $ 2.58 $ 5.45
Oil (per Bbl) $ 23.37 $ 25.54
Oil and gas production costs:
Lease operating expense $ 10,449 $ 7,538
Transportation costs 816 597
Production taxes 2,765 3,922
----------- ------------
Total $ 14,030 $ 12,057
=========== ============
Additional per MCFE data:
Sales price $ 2.98 $ 5.12
Lease operating expense 0.76 0.56
Transportation costs 0.06 0.05
Production taxes 0.20 0.30
----------- ------------
Operating margin $ 1.96 $ 4.21
=========== ============
Depletion, depreciation and amortization $ 0.95 $ 0.85
Impairment of proved properties $ 0.00 $ 0.01
General and administrative $ 0.23 $ 0.30
------------------------
(1) Includes the effects of the St. Mary's hedging activities.
Oil and Gas Production Revenues. Our quarterly oil and gas production
revenues decreased $26.8 million or 39% to $41.1 million for the three months
ended March 31, 2002 compared with $67.9 million for the same period in 2001.
The decrease was the result of decreases in the average price received for both
oil and gas in the first quarter of 2002 compared to 2001. The average realized
gas price decreased 53% to $2.58 per Mcf, while the average realized oil price
decreased 8% to $23.37 per Bbl. Current projections of pricing for the remainder
of 2002 lead us to believe that the difference between average realized prices
for oil and gas between comparable periods of 2002 and 2001 will decrease. Gas
production decreased 1% but oil production increased 16% and helped average net
12
daily production increase to 153.2 MMCFE for 2002 compared with 147.3 MMCFE in
2001. Our acquisition of properties from Choctaw in November 2001 added $3.0
million of revenue and average net daily production of 12.3 MMCFE to the first
quarter of 2002 that offset declines in average net daily production from older
properties. Other acquisitions and wells completed during 2002 added average net
daily production of 5.8 MMCFE.
We hedged approximately 40% or 282 MBbls of our oil production for the
three months ended March 31, 2002, and realized a $1.4 million increase in oil
revenue attributable to hedging compared with a $1.1 million decrease in 2001.
Without these contracts our average price would have been $21.33 per Bbl in the
first quarter of 2002 compared to $27.34 per Bbl in 2001. We also hedged 42% of
our 2002 first quarter gas production or 4.4 million MMBtu and realized a $2.4
million increase in gas revenue compared with a $15.3 million decrease in gas
revenue in 2001. Without these contracts our average price would have been $2.66
per Mcf for the three months ended March 31, 2002, compared to $7.04 per Mcf for
the same period in 2001. Current projections of pricing for oil and gas appear
to indicate that we could be recording decreases in oil and gas revenues for the
remainder of 2002 from hedging contracts we have in place at March 31, 2002.
Oil and Gas Production Costs. Oil and gas production costs consist of lease
operating expense, production taxes and transportation expenses. Total
production costs increased $2.0 million or 16% to $14.0 million for the three
months ended March 31, 2002, from $12.1 million in 2001. Since the first quarter
of 2001 we have experienced higher recurring LOE costs as a result of increased
competition for limited availability of services and general cost inflation. Our
acquisition of properties from Choctaw added $1.7 million of production costs in
2002 that were not reflected in 2001. Total oil and gas production costs per
MCFE increased 12% to $1.02 for the first quarter of 2002 compared with $0.91
for the first quarter of 2001. A $0.13 per MCFE increase this quarter over the
first quarter of 2001 was due to the Williston Basin, a higher cost oil
producing region for us with average LOE per MCFE of $1.28. The Williston Basin
represents 26% of total production in 2002 compared to 18% in 2001. This growth
is primarily a result of our acquisition of properties from Choctaw in late
2001. Net LOE and transportation expense increases in other core areas were
offset by a company wide $0.10 per MCFE decrease in production taxes from lower
of decreased revenue caused by price decreases. 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. Depreciation,
depletion and amortization expense ("DD&A") increased $1.8 million or 16% to
$13.1 million for the three months ended March 31, 2002, from $11.3 million in
2001. DD&A expense per MCFE increased by 11% to $0.95 for the first quarter
of 2002 compared with $0.85 in 2001. This increase reflects acquisitions and
drilling results in 2001 and early 2002 that added costs at a higher per unit
rate.
Exploration. Exploration expense decreased $1.4 million or 17% to $6.9
million for the three months ended March 31, 2002, compared with $8.4 million in
2001. Percentages of total exploration expense are as follows:
2002 2001
---- ----
o Geological and geophysical expenses 11% 21%
o Exploratory dry holes 60% 56%
o Overhead and other expenses 29% 23%
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
13
pursuit of exploration, but we generally explore with an expectation of success.
General and Administrative. General and administrative expenses decreased
$880,000 or 22% to $3.1 million for the three months ended March 31, 2002,
compared with $4.0 million in 2001. Decreases in compensation expense associated
with our incentive plans were partially offset by increases in compensation
expense associated with increased personnel. The remaining decrease of $464,000
resulted from an increase in COPAS overhead reimbursement from operations.
Interest Expense. Interest expense increased to $452,000 for the quarter
ended March 31, 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 $1.1 million for the three months
ended March 31, 2002, and $11.5 million in 2001, resulting in effective tax
rates of 32.6% and 36.0% respectively. The decrease between years is the
effect of Section 29 credits, percentage depletion, interest expense on
convertible debt with contingent interest provisions and state income taxes on
lower net income before tax for the period ended March 31, 2002.
Net Income. Net income for the three months ended March 31, 2002 decreased
$18.1 million or 89% to $2.3 million compared with $20.4 million in 2001. A 53%
decrease in gas prices and a 8% decrease in oil prices combined with a 16%
increase in oil production and a 1% decrease in gas production resulted in a
$26.8 million decrease in oil and gas production revenue. This decrease was
offset by a corresponding $10.4 million decrease in income tax expense.
Increases in oil and gas production costs and DD&A were offset by decreases
in exploration expense and general and administrative expenses and explain the
remaining decrease in net income.
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.
14
Cash Flow. Net cash provided by operating activities decreased $6.8 million
or 14% to $41.8 million for the three months ended March 31, 2002 compared with
$48.6 million in 2001. The decrease between years reflects the effect of the
decrease in oil and gas production revenues that were offset by a change between
years of $17.0 million from collection of receivables.
Net cash used in investing activities increased $5.9 million or 20% to
$35.9 million for the three months ended March 31, 2002, compared with $30.0
million in 2001. This increase results from additional capital expenditures and
acquisition costs and a decrease in receipts of $3.9 million from sales of KMOC
stock. Total capital expenditures, including acquisitions of oil and gas
properties, in the first three months of 2002 increased $2.1 million or 6% to
$39.3 million compared with $37.2 million in the first three months of 2001.
Net cash provided by financing activities increased $75.6 million to $53.2
million for the three months ended March 31, 2002, compared with net cash used
in financing activities of $22.4 million in 2001. This increase reflects our
private placement of $100 million of 5.75% senior convertible notes due 2022. A
portion of the net proceeds of $96.9 million was used to repay a portion of the
balance due on the credit facility.
St. Mary had $63.2 million in cash and cash equivalents and had working
capital of $76.6 million as of March 31, 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
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. We received net proceeds of $96.9 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 or any combination of
cash and our 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 swap on $50 million of the notes. The floating rate for each
applicable six-month period will be determined as LIBOR plus 0.38%. 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. 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
15
guarantees by subsidiaries. Such collateral consists primarily of security
interests in the oil and gas properties of St. Mary and its subsidiaries.
As of March 31, 2002 and December 31, 2001, $20.0 million and $64.0
million, respectively, was outstanding under this credit agreement. Pursuant to
a March 4, 2002 amendment, 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 equal
to 40% but less than 50%, or (d) 1 5/8% when our debt to capitalization ratio is
greater than 50%. At March 31, 2002 our debt to capitalization ratio as defined
under the credit agreement was 29.3%.
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 March 31, 2002 we have repurchased a 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
------------------------------------
Three Months Ended March 31,
----------------------------
2002 2001
---- ----
(In thousands)
Development $ 16,348 $ 24,730
Exploration 4,872 10,470
Acquisitions:
Proved 10,023 445
Unproved 4,277 6,810
-------- --------
Total $ 35,520 $ 42,455
======== ========
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 our
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 quarter of 2002 decreased $6.9
million or 16% compared to the first quarter of 2001. We spent $25.5 million in
the first quarter of 2002 for unproved property acquisitions and domestic
exploration and development compared to $42.0 million for the comparable quarter
in 2001. This decrease was a result of planned decreases in drilling activity
and a $2.5 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 will begin in May. In April we
16
were successful in obtaining an additional 10,000 acres of leases bringing our
total to 125,000 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
million for capital and exploration expenditures in 2002 with $60 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 $ 33.0
o Gulf Coast and Gulf of Mexico region $ 18.0
o ArkLaTex region $ 14.0
o Williston Basin $ 22.0
o Permian Basin $ 9.0
o Other $ 8.0
-------
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
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
17
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 March 31, 2002 we
have the following swaps in place:
Swaps:
- ------
Average Quantity Average
Product Volumes/month Type Fixed price Duration
------- ------------- -------- ----------- --------
Natural Gas 1,573,000 MMBtu $2.85 04/02 - 12/02
Natural Gas 268,000 MMBtu $2.96 01/03 - 12/03
Natural Gas 59,000 MMBtu $3.04 01/04 - 12/04
Oil 86,600 Bbls $24.77 04/02 - 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 in the current quarter and is reported in oil and gas production revenues
for this quarter on our consolidated statements of operations. Amortization of
amounts in other comprehensive income related to our commodity positions with
Enron will be recorded in oil hedge gain in future months. Unrealized derivative
loss on the consolidated statements of operations includes $187,000 of net loss
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 an adjustment to the convertible notes payable on
the consolidated balance sheets. Of this amount, $3,000 has been amortized
through interest expense. Unrealized derivative loss on the consolidated
statements of operations includes $121,000 of net loss from mark-to-market
adjustments for this derivative.
Our fixed-rate to floating-rate interest rate swap on $50 million of
senior convertible notes did not qualify for fair value hedge treatment under
SFAS No. 133. Unrealized derivative loss on the consolidated statements of
operations includes $44,000 of net loss from mark-to-market adjustments for this
derivative.
We anticipate that all hedge transactions will occur as expected.
Accounting Matters
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.
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
18
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.
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 of 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 18.1 million
MMBtu would cause a potential $1.6 million change in net income before income
taxes for contracts in place on March 31, 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 March 31,
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 March 31, 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 March 31, 2002, we had $70.0 million floating rate debt
attributable to our credit facility and the fixed-rate to floating-rate interest
rate swap we entered into on March 25, 2002 and $50.0 million of fixed rate
debt. Assuming constant debt levels, the impact of a one- percent change in
interest rates on results of operations and cash flows for the remainder of the
year would be approximately $900,000 before taxes.
19
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 previously reported in our 2001 Form 10-K, 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
125,000 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.
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. Sampson 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 is
not due until May 27, 2002. 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 January 1, 2002 St. Mary issued a total of 7,200 restricted shares
of common stock to its directors as compensation recorded in the amount
of $129,683 for their services as members 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 directors are accredited investors and certificates
representing the shares bear a legend restricting the transfer of those
shares.
In March 2002, we issued $100 million in total principal amount of our
5.75% senior convertible notes due 2022. We received net proceeds,
after deducting the initial purchasers' discount and offering expenses,
of $96.7 million. The notes are convertible into shares of our common
stock, at any time prior to maturity or their prior redemption or
repurchase by us, at a conversion price of $26.00 per share. The notes
were issued in a private placement to initial purchasers who are
"qualified institutional buyers" as defined in Rule 144A under the
Securities Act, and the issuance of the notes was not registered under
the Securities Act in reliance on the exemption from registration
provided by Section 4(2) of the Securities Act for transactions by an
issuer not involving any public offering since the notes bear a legend
restricting the transfer of the notes expect pursuant to an effective
registration statement or an exemption from registration. The initial
purchasers resold the notes to qualified institutional buyers pursuant
to the exemption from registration provided by Rule 144A.
20
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports on Form 8-K
St. Mary Land &Exploration Company filed the following current year
reports on form 8-K during the quarter ended March 31, 2002:
On February 6, 2002, we filed a current year report on Form
8-K reporting under Item 9 that we had issued a press release
announcing our 2002 capital expenditure budget, year end 2001 reserves,
the sale of our remaining shares of KMOC stock, and accounting for
Enron hedges.
On February 21, 2002, we filed a current year report on Form
8-K reporting under Item 9 that we had issued a press release
announcing fourth quarter 2001 and year 2001 financial results and
conference call dates.
On March 5, 2002 we filed a current year report on Form 8-K
reporting under Item 5 that we had issued a press release announcing
our intent to offer $75 million of senior convertible notes.
On March 5, 2002 we also filed a current year report on Form
8-K reporting under Item 9 information for prospective purchasers of
our senior convertible notes that has not been previously publicly
reported.
On March 8, 2002 we filed a current year report on Form 8-K
reporting under Item 5 that we had issued a press release announcing
our agreement to sell, in a private placement, $75 million of 5.75%
senior convertible notes with a 30 day option to purchase an additional
$25 million of the notes.
On March 20, 2002 we filed a current year report on Form 8-K
reporting under Item 5 that we had issued a press release announcing
the completion of private placement of $100 million of 5.75% senior
convertible notes.
21
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
May 13, 2002 By /s/ MARK A. HELLERSTEIN
-----------------------------------
Mark A. Hellerstein
President and Chief Executive Officer
May 13, 2002 By /s/ RICHARD C. NORRIS
-----------------------------------
Richard C. Norris
Vice President - Finance, Secretary
and Treasurer
May 13, 2002 By /s/ GARRY A. WILKENING
-----------------------------------
Garry A. Wilkening
Vice President - Administration and
Controller
22