Back to GetFilings.com
----------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
------------
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 700, Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
1776 Lincoln Street, Suite 1100, Denver, Colorado 80203
(Former address, changed since last report)
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 issuer's classes of
common stock as of the latest practicable date.
As of November 8, 2002, the issuer had 27,931,780 shares of common stock, $.01
par value, outstanding.
----------------------------------------------------------------------
ST. MARY LAND & EXPLORATION COMPANY
---------------------------------------
INDEX
-----
Part I. FINANCIAL INFORMATION PAGE
----
Item 1. Financial Statements (Unaudited)
Consolidated Balance
Sheets - September 30, 2002, and
December 31, 2001.................................3
Consolidated Statements of
Operations - Three and Nine Months Ended
September 30, 2002, and 2001......................4
Consolidated Statements of
Cash Flows - Nine Months Ended
September 30, 2002, and 2001......................5
Consolidated Statements of
Stockholders' Equity - September 30, 2002,
and December 31, 2001.............................7
Notes to Consolidated Financial
Statements - September 30, 2002...................8
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................................12
Item 3. Quantitative and Qualitative Disclosures
About Market Risk................................24
Item 4. Controls and Procedures..........................25
Part II. OTHER INFORMATION
Item 1. Legal Proceedings................................25
Item 5. Other Information................................26
Item 6. Exhibits and Reports on Form 8-K.................26
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
September 30, December 31,
------------- -------------
2002 2001
------------- -------------
Current assets:
Cash and cash equivalents $ 49,070 $ 4,116
Short term investments available-for-sale 10,474 -
Accounts receivable 34,598 46,484
Prepaid expenses and other 3,780 2,337
Accrued derivative asset 5,973 8,194
Refundable income taxes 1,894 11,090
------------- -------------
Total current assets 105,789 72,221
------------- -------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 593,361 523,823
Less accumulated depletion, depreciation and amortization (249,860) (216,288)
Unproved oil and gas properties, net of impairment
allowance of $9,025 in 2002 and $8,908 in 2001 42,412 48,143
Other property and equipment, net of accumulated depreciation
of $3,285 in 2002 and $3,120 in 2001 3,519 3,252
------------- -------------
Total property and equipment 389,432 358,930
------------- -------------
------------- -------------
Other noncurrent assets 9,135 5,838
------------- -------------
------------- -------------
Total Assets $ 504,356 $ 436,989
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 41,602 $ 34,858
Deferred tax liability 979 3,363
------------- -------------
Total current liabilities 42,581 38,221
------------- -------------
Long-term liabilities:
Long-term credit facility - 64,000
Convertible notes 99,578 -
Deferred income taxes 57,197 47,685
Other noncurrent liabilities 1,914 255
------------- -------------
Total long-term liabilities 158,689 111,940
------------- -------------
Commitments and contingencies
------------- -------------
Minority interest 712 711
------------- -------------
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares: Issued and
outstanding - 28,907,736 shares in 2002 and 28,779,808 shares in 2001 289 288
Additional paid-in capital 139,351 137,384
Treasury stock - at cost: 1,009,900 shares in 2002 and 2001 (16,210) (16,210)
Retained earnings 176,929 157,739
Accumulated other comprehensive income 2,015 6,916
------------- -------------
Total stockholders' equity 302,374 286,117
------------- -------------
------------- -------------
Total Liabilities and Stockholders' Equity $ 504,356 $ 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 Nine Months Ended
September 30, September 30,
------------------------------- -------------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Operating revenues:
Oil and gas production $ 45,121 $ 41,859 $ 132,411 $ 165,195
Loss on sale of proved properties (503) (71) (90) (21)
Marketed gas revenue 3,366 - 6,810 -
Other oil and gas revenue 185 374 932 939
Gain on sale of KMOC stock - - 836 -
Other revenues 166 494 237 666
------------- ------------- ------------- -------------
Total operating revenues 48,335 42,656 141,136 166,779
------------- ------------- ------------- -------------
Operating expenses:
Oil and gas production 12,392 14,756 37,953 40,249
Depletion, depreciation and amortization 12,836 13,704 39,169 37,876
Exploration 4,219 4,347 15,432 14,858
Impairment of proved properties - 576 - 820
Abandonment and impairment of unproved properties 587 659 1,906 1,733
General and administrative 4,388 2,804 10,544 10,361
Unrealized derivative loss (gain) (2,619) - (4,594) -
Marketed gas expense 3,545 - 6,631 -
Minority interest and other 286 283 906 662
------------- ------------- ------------- -------------
Total operating expenses 35,634 37,129 107,947 106,559
------------- ------------- ------------- -------------
Income from operations 12,701 5,527 33,189 60,220
Nonoperating income (expense):
Interest income 288 73 568 408
Interest expense (1,110) (5) (2,580) (40)
------------- ------------- ------------- -------------
Income before income taxes 11,879 5,595 31,177 60,588
Income tax expense 4,205 734 10,596 21,100
------------- ------------- ------------- -------------
Net income $ 7,674 $ 4,861 $ 20,581 $ 39,488
============= ============= ============= =============
Basic net income per common share $ 0.28 $ 0.17 $ 0.74 $ 1.41
============= ============= ============= =============
Diluted net income per common share $ 0.27 $ 0.17 $ 0.72 $ 1.38
============= ============= ============= =============
Basic weighted average common shares outstanding 27,873 27,790 27,828 28,052
============= ============= ============= =============
Diluted weighted average common shares outstanding 28,448 28,252 28,388 28,620
============= ============= ============= =============
The accompanying notes are an integral part of these
consolidated financial statements.
4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
For the Nine Months Ended
September 30,
-------------------------------
2002 2001
------------- -------------
Reconciliation of net income to net cash provided by operating activities:
Net income $ 20,581 $ 39,488
Adjustments to reconcile net income to net
cash provided by operating activities:
Loss on sale of proved properties 90 21
Gain on sale of KMOC stock (836) -
Depletion, depreciation and amortization 39,169 37,876
Impairment of proved properties - 820
Abandonment and impairment of unproved properties 1,906 1,733
Unrealized derivative gain (4,594) -
Deferred income taxes 10,287 18,700
Exploratory dry hole expense 7,293 5,914
Minority interest and other (1,208) (199)
------------- -------------
72,688 104,353
Changes in current assets and liabilities:
Accounts receivable 12,962 9,647
Prepaid expenses and other (1,442) (741)
Refundable income taxes 9,215 (7,029)
Accounts payable and accrued expenses 13,000 5,476
Current deferred income taxes (271) 163
------------- -------------
Net cash provided by operating activities 106,152 111,869
------------- -------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 166 1,469
Capital expenditures (65,106) (99,844)
Acquisition of oil and gas properties (21,574) (1,620)
Proceeds from distribution and sale of KMOC stock 3,114 7,371
Deposits to short term investments available-for-sale (11,484) -
Receipts from short term investments available-for-sale 1,000 -
Other 26 (118)
------------- -------------
Net cash used in investing activities (93,858) (92,742)
------------- -------------
Cash flows from financing activities:
Proceeds from credit facility 16,000 75,200
Repayment of credit facility (80,000) (82,850)
Proceeds from issuance of convertible notes 96,661 -
Proceeds from sale of common stock 1,390 2,381
Repurchase of common stock - (12,871)
Dividends paid (1,391) (1,408)
------------- -------------
Net cash provided by (used in) financing activities 32,660 (19,548)
------------- -------------
Net change in cash and cash equivalents 44,954 (421)
Cash and cash equivalents at beginning of period 4,116 6,619
------------- -------------
Cash and cash equivalents at end of period $ 49,070 $ 6,198
============= =============
The accompanying notes are an integral part of these
consolidated financial statements.
5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Continued)
Supplemental schedule of additional cash flow information and noncash
investing and financing activities:
For the Nine Months Ended
September 30,
-------------------------------
2002 2001
------------- -------------
(In thousands)
Cash paid for interest $ 2,795 $ 284
Cash paid (received) for income taxes (8,635) 10,386
Cash paid for exploration expenses 18,616 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 - - - 20,581 - - - 20,581
Unrealized net loss on marketable
equity securities available for
sale - - - - - - (452) (452)
Change in derivative instrument
fair value - - - - - - (4,449) (4,449)
-------------
Total comprehensive income 15,680
-------------
Cash dividends, $ 0.05 per share - - - (1,391) - - - (1,391)
Issuance for Employee Stock Purchase
Plan 9,294 - 167 - - - - 167
ESPP disqualified distribution - - 21 - - - - 21
Sale of common stock, including
income tax benefit of stock option
exercises 110,634 1 1,634 - - - - 1,635
Directors' stock compensation 8,000 - 145 - - - - 145
---------- ---------- ---------- ---------- ---------- ---------- ------------- -------------
Balances, September 30, 2002 28,907,736 $ 289 $ 139,351 $ 176,929 (1,009,900) $ (16,210) $ 2,015 $ 302,374
========== ========== ========== ========== ========== ========== ============= =============
The accompanying notes are an integral part of these
consolidated financial statements.
7
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
--------------------------
September 30, 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.
Note 2 - Income Taxes
Federal income tax expense for the three and nine months ended September
30, 2002, and 2001 differs from the amounts that would be provided by applying
the statutory U.S. Federal income tax rate to income before income taxes
primarily due to Section 29 credits, percentage depletion, interest expense on
convertible debt with contingent interest provisions, and the effect of state
income taxes. For the nine months ended September 30, 2002, the Company's
current portion of income tax expense was $502,000.
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
0.5% contingent interest provision (see Note 4). The contingent interest
provision did not apply to St. Mary's first interest payment on September 15,
2002, but it will apply to the payment due on March 15, 2003. Interest payments
will be made on March 15 and September 15 in subsequent years. The Company
received net proceeds of $96,661,000 after deducting the initial purchasers'
discount and offering expenses paid by the Company. The Notes are general
unsecured obligations and rank on parity in right of payment with all existing
and future unsecured senior indebtedness and other general unsecured
obligations. They are senior in right of payment to 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 require 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
8
from paying dividends, 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 current six-month calculation
period this rate is 2.19%. 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 $10,000,000 to $160,000,000 in April
2002. The accepted borrowing base is currently $40,000,000. 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 0.5% or the prime rate, plus an
additional 0.25% 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) 1.25% when the Company's debt to
capitalization ratio is greater than or equal to 30% but less than 40%, (c)
1.375% when the Company's debt to capitalization ratio is greater than or equal
to 40% but less than 50%, or (d) 1.625% when the Company's debt to
capitalization ratio is greater than 50%. At September 30, 2002, the Company's
debt to capitalization ratio as defined under the credit agreement was 25.0%.
The Company had no outstanding borrowings under its revolving credit
agreement and $100,000,000 in outstanding borrowings under the Notes as of
September 30, 2002. The weighted average interest rate paid for the third
quarter of 2002 was 4.38% including commitment fees paid on the unused portion
of the revolving credit facility accepted borrowing base. 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.
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 larger percentages 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 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 $1,118,000. This amount was
included in other comprehensive income at December 31, 2001, and was recorded as
a hedge gain in the first quarter of 2002. Hedge gains and losses are reported
in oil and gas production revenues in the consolidated statements of operations.
Amortization of $1,242,000 of other comprehensive income related to commodity
positions with Enron is also recorded as a hedge gain in oil and gas production
revenue in the consolidated statements of operations for the nine months ended
September 30, 2002. Additional amortization will be recorded in hedge gains in
future months. Unrealized derivative loss in the consolidated statements of
operations includes $4,000 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.
9
This amount was recorded as an adjustment to the Notes in the consolidated
balance sheets in the first quarter of 2002. Of this amount, $51,000 has been
amortized through interest expense for the nine months ended September 30, 2002.
Unrealized derivative loss in the consolidated statements of operations includes
$239,000 of net loss from mark-to-market adjustments for this derivative for the
nine months ended September 30, 2002.
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 in the consolidated statements of operations includes $4,838,000
of net gain from mark-to-market adjustments for this derivative instrument for
the nine months ended September 30, 2002.
The Company anticipates that all oil and gas hedge transactions will occur
as expected. Based on current prices we anticipate that $2,399,000 of the after
tax gain amount included in accumulated 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
---------------------------------------------------------------------------
Debt securities issued by
government agencies
$ 991,396 $ 382 $ 991,778
Corporate debt securities 9,478,123 3,695 9,481,818
---------------------------------------------------------------------------
Total securities $ 10,469,519 $ 4,077 $ 10,473,596
---------------------------------------------------------------------------
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 Emerging Issue Task Force
("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." 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
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 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. The Company has not yet
determined the impact of adoption of this statement.
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.
Note 7 - Subsequent Events
On October 1, 2002, the Company entered into a Purchase and Sale Agreement
with Burlington Resources Oil & Gas Company LP to acquire an estimated 61
BCFE of proved reserves for $76.4 million in cash. The properties are in the
Williston Basin of Montana and North Dakota. The effective date of the
acquisition will be July 1, 2002, and the transaction is expected to close in
December 2002.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 forecasts, expects, believes or anticipates will or may occur in the
future are forward-looking statements. 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, completion of pending acquisition transactions, 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 nine months ended September 30, 2002, to activity in
2001 the focus will be on natural gas prices. Prices decreased compared to last
year but were higher this quarter than they were in the first six months of
2002. We anticipate that the current historically strong prices for both natural
gas and oil will continue through the end of the year and into 2003. Lease
operating expense remained lower than in 2001 for both the quarter and the
nine-month period. General and administrative expense on a per MCFE basis rose
during the quarter but remained flat for the nine-months. In October 2002 we
signed a purchase and sale agreement with Burlington Resources Oil & Gas
Company LP to acquire an estimated 61 BCFE of proved reserves for $76.4 million
in cash. This purchase is expected to close in December 2002.
Critical Accounting Policies and Estimates
We refer you to the corresponding section of our Annual Report on Form 10-K
for the year ended December 31, 2001.
12
Results of Operations
The following table sets forth selected operating data for the periods
indicated:
Three Months Nine Months
------------ -----------
Ended September 30, Ended September 30,
------------------- -------------------
2002 2001 2002 2001
---- ---- ---- ----
(In thousands, except per volume data)
Oil and gas production revenues:
Gas production $ 27,103 $ 27,044 $ 80,837 $120,394
Oil production 18,018 14,815 51,574 44,801
--------- --------- --------- ---------
Total $ 45,121 $ 41,859 $132,411 $165,195
========= ========= ========= =========
Net production:
Gas (Mcf) 9,111 9,754 28,283 29,404
Oil (Bbls) 679 609 2,057 1,812
--------- --------- --------- ---------
MCFE 13,186 3,405 40,625 40,274
========= ========= ========= =========
Average sales price (1):
Gas (per Mcf) $ 2.97 $ 2.77 $ 2.86 $ 4.09
Oil (per Bbl) $ 26.54 $ 24.35 $ 25.07 $ 24.73
Oil and gas production costs:
Lease operating expense $ 9,021 $ 11,441 $ 27,647 $ 28,805
Transportation costs 790 601 2,367 9,705
Production taxes 2,581 2,714 7,939
--------- --------- --------- ---------
Total $ 12,392 $ 14,756 $ 37,953 $ 40,249
========= ========= ========= =========
Additional per MCFE data:
Sales price $ 3.42 $ 3.12 $ 3.26 $ 4.10
Lease operating expense 0.68 0.85 0.68 0.72
Transportation costs 0.06 0.04 0.06 0.04
Production taxes 0.20 0.20 0.19 0.24
--------- --------- --------- ---------
Operating margin $ 2.48 $ 2.03 $ 2.33 $ 3.10
========= ========= ========= =========
Depletion, depreciation and amortization $ 0.97 $ 1.02 $ 0.96 $ 0.94
Impairment of proved properties $ - $ 0.04 $ - $ 0.02
General and administrative $ 0.33 $ 0.21 $ 0.26 $ 0.26
---------------------
(1)Includes the effects of St. Mary's hedging activities.
13
Three-Month Comparison
Oil and Gas Production Revenues. Our quarterly oil and gas production
revenues increased $3.3 million or 8% to $45.1 million for the three months
ended September 30, 2002 compared with $41.9 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 ( 7 %) $0.20/Mcf 7 %
o Oil 11 % $2.19/Bbl 9 %
Average net daily production decreased slightly to 143.3 MMCFE for 2002
compared with 145.7 MMCFE in 2001. Our acquisition of properties from Choctaw in
November 2001 added $3.6 million of revenue and average net daily production of
11.8 MMCFE to the three months ended September 30, 2002. Other acquisitions and
wells completed during 2002 added average net daily production of 17.0 MMCFE.
These increases helped to offset declines in average net daily production from
older properties that include an average 8.5 MMCFE/day decline at Judge Digby.
We hedged approximately 55% or 376 MBbls of our oil production for the
three months ended September 30, 2002, and realized a $167,000 decrease in oil
revenue attributable to hedging compared with a $460,000 decrease in 2001.
Without these contracts we would have received an average price of $26.78 per
Bbl in the third quarter of 2002 compared to $25.11 per Bbl in 2001. We also
hedged 47% of our 2002 third quarter gas production or 4.8 million MMBtu and
realized a $560,000 decrease in gas revenue from hedging compared with a
$187,000 increase in 2001. Without these contracts we would have received an
average price of $3.04 per Mcf for the three months ended September 30, 2002
compared to $2.75 per Mcf for the same period in 2001.
Marketed Gas Revenue and Expense. As a result of our acquisition of gas
gathering system lines in Coal County, Oklahoma in February 2002 we began taking
title to and marketing natural gas for third parties. For the three months ended
September 30, 2002, we received $3.4 million from the sale of this natural gas.
Operating costs associated with these revenues totaled $3.5 million and resulted
in a negative gross margin to us of $179,000. Due to pipeline imbalances, cost
inflation and fluctuations in natural gas prices we may not always have a
positive gross margin from gas marketing activities.
Oil and Gas Production Costs. Total production costs decreased $2.4 million
or 16% to $12.4 million for the three months ended September 30, 2002 from $14.8
million in 2001. In the third quarter of 2002 our Gulf Coast region experienced
a $2.2 million decrease in LOE reflecting decreased workover expense. Other core
areas combined reflect an additional $1.1 million decrease in LOE that also
reflects decreased workover expense. These decreases were offset by activity
from our acquisition of properties from Choctaw that added $1.2 million of LOE
in the third quarter of 2002 that was not reflected in 2001.
Total oil and gas production costs per MCFE decreased 15% to $0.94 for the
three months ended September 30, 2002, compared with $1.10 for 2001. The
decrease is comprised of the following:
o A $0.25 per MCFE decrease due to company-wide decreases in workover expense
between the comparative quarters.
o A $0.08 per MCFE increase caused by increased activity in the higher-cost
Williston Basin.
o A $0.02 increase in transportation costs.
14
Depreciation, Depletion, Amortization and Impairment. DD&A decreased
$868,000 or 6% to $12.8 million for the three months ended September 30, 2002,
from $13.7 million in 2001. DD&A per MCFE decreased by 5% to $0.97 for the
third quarter of 2002 compared with $1.02 in 2001. DD&A per MCFE is affected
by changes in estimated reserve quantities. At the end of each quarter we adjust
our most recent engineered reserve estimate for anticipated production, new well
additions and changes in oil and gas prices from the date of that estimate to
the end of the quarter. Adjustments to economic quantities of reserves resulting
from lower pricing at September 30, 2001, caused a large per MCFE increase in
the third quarter of 2001 while higher pricing at September 30, 2002, caused a
per MCFE decrease for the third quarter of 2002.
Exploration. Exploration expense decreased $128,000 or 3% to $4.2 million
for the three months ended September 30, 2002, compared with $4.3 million in
2001. Percentages of total exploration expense are as follows:
2002 2001
---- ----
o Geological and geophysical expenses 20% 27%
o Exploratory dry holes 28% 31%
o Overhead and other expenses 52% 42%
General and Administrative. General and administrative expenses increased
$1.6 million or 56% to $4.4 million for the three months ended September 30,
2002, compared with $2.8 million in 2001. Increases in compensation expense
associated with increased personnel, our incentive plans and general cost
inflation were partially offset by a $334,000 increase in COPAS overhead
reimbursement from operations.
Interest Expense. Interest expense increased to $1.1 million for the
quarter ended September 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 is affected by the fixed-rate to floating-rate interest rate swap
we entered into in March 2002. Without this swap interest expense for the
quarter ended September 30, 2002, would have been $1.6 million.
Income Taxes. Income tax expense totaled $4.2 million for the three months
ended September 30, 2002, and $734,000 in 2001, resulting in effective tax rates
of 35.4% and 13.1%, respectively. The difference in rates between the two
periods reflects the cumulative effect on temporary differences in the quarter
ended September 30, 2001 for changes to estimates of percentage depletion and
our state income tax rate based on tax filings completed in that quarter.
Net Income. Net income for the three months ended September 30, 2002,
increased $2.8 million or 58% to $7.7 million compared with $4.9 million in
2001. An 8% increase in oil and gas revenue combined with an unrealized
derivative gain of $2.6 million, decreased oil and gas production costs and
increased general and administrative expense resulted in an increase to net
income before income tax of $6.7 million for the third quarter of 2002 compared
with the third quarter of 2001. Income tax expense for the third quarter of 2002
is higher by $3.5 million due to a $2.2 million effect of applying the current
rate to the increase in net income and due to a $1.3 million effect from the
difference in income tax rates between the quarters.
15
Nine-Month Comparison
Oil and Gas Production Revenues. We experienced a decrease in oil and gas
production revenues of $32.8 million, or 20% to $132.4 million for the nine
months ended September 30, 2002, compared with $165.2 million for the same
period in 2001. The following table presents the components of increases
(decreases) between 2002 and 2001:
Production Price Price
% Change $ Change % Change
---------------------------------------
o Natural Gas (4%) ($1.24)/Mcf (30%)
o Oil 14% $0.34/Bbl 1%
Average net daily production increased slightly to 148.8 MMCFE for the
first nine months of 2002 compared with 147.5 MMCFE in 2001. Our acquisition of
properties from Choctaw in November 2001 added $10.5 million of revenue and
average net daily production of 12.0 MMCFE to the first nine months of 2002.
Other acquisitions and wells completed during 2002 added average net daily
production of 13.3 MMCFE. These increases offset declines in average net daily
production from older properties that include an average 4.2 MMCFE/day decline
at Judge Digby.
We hedged approximately 45% or 917 MBbls of our oil production for the nine
months ended September 30, 2002, and realized a $2.4 million increase in oil
revenue attributable to hedging compared with a $2.3 million decrease in oil
revenue in 2001. Without these contracts we would have received an average price
of $23.89 per Bbl for the nine months ended September 30, 2002, compared to
$26.02 per Bbl in 2001. We also hedged 44% of our gas production or 13.8 million
MMBtu and realized a $344,000 increase in gas revenue for the nine months ended
September 30, 2002, compared with a $20.3 million decrease in gas revenue in
2001. Without these contracts we would have received an average price of $2.85
per Mcf for the nine months ended September 30, 2002, compared to $4.78 per Mcf
for the same period in 2001.
Marketed Gas Revenue and Expense. For the nine months ended September 30,
2002, we received $6.8 million from the sale of this natural gas. Costs
associated with these revenues totaled $6.6 million and resulted in gross margin
to us of $179,000.
Oil and Gas Production Costs. Total production costs decreased $2.3 million
or 6% to $38.0 million for the nine months ended September 30, 2002, from $40.2
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 workover
expense and an adjustment due to the issuance of a revised Authorization For
Expenditure by the Operator at Judge Digby. This AFE indicated that workover LOE
we previously expensed under the original AFE should be recorded as property,
plant and equipment. In the third quarter of 2002 we experienced a $3.3 million
decrease in LOE due to more decreases in workover expense. This decrease was
offset by a $1.4 million general inflation increase we expected and activity
from our acquisition of properties from Choctaw that added $4.2 million of LOE
in 2002 that was not reflected in 2001. The $1.8 million decrease in production
taxes reflects the decrease in revenue discussed above.
16
Total oil and gas production costs per MCFE decreased 7% to $0.93 for the
nine months ended September 30, 2002, compared with $1.00 for 2001. This
decrease is comprised of the following:
o A $0.05 per MCFE decrease in production taxes due to lower per MCFE prices.
o A $0.19 per MCFE decrease in LOE attributable to decreases in workover
expense in the Gulf Coast and Permian regions in excess of general cost
inflation increases.
o A $0.01 per MCFE increase in LOE attributable to general cost inflation
increases in excess of decreases in workover expense in the Mid-Continent
and ArkLaTex regions.
o A $0.14 per MCFE increase in LOE attributable to increased activity in the
higher cost Williston Basin.
Although we continue to monitor these costs, we believe that the trend of
decreases in LOE on an absolute basis and on a per MCFE basis will not continue
into the future. New workover activity is always a possibility in our Gulf Coast
region and it is likely that future acquisitions of producing properties in the
Williston Basin will lead to additional workover activities as we attempt to
enhance the performance and lengthen the lives of those properties.
Depreciation, Depletion, Amortization and Impairment. DD&A increased
$1.3 million or 3% to $39.2 million for the nine months ended September 30,
2002, from $37.9 million in 2001. This increase reflects both the increase in
production between the respective periods for 2002 and 2001 and acquisitions and
drilling results from both years that caused DD&A per MCFE to increase by 3%
to $0.96 in 2002 compared with $0.94 in 2001.
Exploration. Exploration expense increased $574,000 or 4% to $15.4 million
for the nine months ended September 30, 2002, compared with $14.9 million in
2001. Percentages of total exploration expense are as follows:
2002 2001
---- ----
o Geological and geophysical expenses 14% 23%
o Exploratory dry holes 47% 39%
o Overhead and other expenses 39% 38%
General and Administrative. General and administrative expenses increased
$183,000 to $10.5 million for the nine months ended September 30, 2002, compared
with $10.4 million in 2001. Increases in compensation expense associated with
increased personnel, our incentive plans and general cost inflation were
partially offset by a $1.2 million increase in COPAS overhead reimbursement from
operations and costs allocated to exploration expense. We anticipate that
general and administrative expense on a per MCFE basis will be 10% to 20% higher
for the entire year of 2002 than it was for the entire year of 2001.
Interest Expense. Interest expense increased to $2.6 million for the nine
months ended September 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 is affected by the fixed-rate to floating-rate interest
rate swap we entered into in March 2002. Without this swap interest expense for
the period ending September 30, 2002, would have been $3.3 million.
Income Taxes. Income tax expense totaled $10.6 million for the nine months
ended September 30, 2002, and $21.1 million in 2001, resulting in effective tax
rates of 34% and 34.8%, 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 of Section 29 credits on a lesser net income in 2002.
17
Net Income. Net income for the nine months ended September 30, 2002,
decreased $18.9 million to $20.6 million compared with $39.5 million in 2001. A
30% decrease in gas prices and a 4% decrease in gas production offset in part by
a 14% increase in oil production resulted in a $32.8 million decrease in oil and
gas production revenue between the two periods. This decrease caused a
corresponding and partially offsetting decrease of $10.5 million in income tax
expense. We also had $4.6 million of unrealized derivative gain that helped to
offset a portion of the difference.
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 fluctuation
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 decreased $5.7 million
or 5% to $106.2 million for the nine months ended September 30, 2002, compared
with $111.9 million in 2001. The decrease reflects the effect of lower gas
production revenues and the effect on deferred income tax expense of a reduced
exploration and development capital expenditures budget in 2002. This decrease
was offset by changes in current assets and liabilities of $25.9 million.
Net cash used in investing activities increased $1.1 million to $93.8
million for the nine months ended September 30, 2002, compared with $92.7
million in 2001. This increase is due to our net $10.5 million short-term
investment in this quarter and a net $5.6 million decrease in sales proceeds
between the two periods offset by a $14.8 million decrease in capital
expenditures. Total capital expenditures, including acquisitions of oil and gas
properties, in the first nine months of 2002 decreased 15% to $86.7 million
compared with $101.5 million in the first nine months of 2001.
Net cash provided by financing activities increased $52.2 million to $32.7
million for the nine months ended September 30, 2002, compared with cash used in
financing activities of $19.5 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 $96.7 million was used to repay the
balance due on the credit facility. We have not repurchased any common stock in
the first nine months of 2002.
St. Mary had $49.1 million in cash and cash equivalents and had working
capital of $40.4 million as of September 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.
18
Senior Convertible Notes. In March 2002 we issued in a private placement a
total of $100.0 million of 5.75% senior convertible notes due 2022 with a 0.5%
contingent interest provision. The contingent interest provision did not apply
to our first interest payment on September 15, 2002, but it will apply to the
payment due on March 15, 2003. Interest payments on the notes will be made on
March 15 and September 15 in subsequent years. We received net proceeds of $96.7
million after deducting the initial purchasers' discount and estimated offering
expenses payable by us. The notes are general unsecured obligations and rank on
parity in right of payment with all our existing and future unsecured senior
indebtedness and other general unsecured obligations, and are senior in right of
payment to 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 require 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 current calculation period this rate is 2.19%.
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 that 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 September 30, 2002, we had no balance outstanding under this credit
agreement compared to $64.0 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 0.5% or the prime rate, plus an additional 0.25%
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)
1.25 % when our debt to capitalization ratio is greater than or equal to 30% but
less than 40%, (c) 1.375% when our debt to capitalization ratio is greater than
or equal to 40% but less than 50%, or (d) 1.625% when our debt to capitalization
ratio is greater than 50%. Our debt to capitalization ratio as defined under the
credit agreement was 25% as of September 30, 2002.
19
Schedule of Contractual Obligations. The following table summarizes our
future estimated principal payments for the periods specified (in millions):
Contractual Total Cash
Obligations Long-Term Debt Operating Leases Obligation
----------- -------------- ---------------- ----------
Less than 1 year $ - $1.1 $ 1.1
1-3 years - 1.7 1.7
4-5 years - 1.4 1.4
After 5 years 100.0 3.0 103.0
------ ----- ------
Total $100.0 $7.2 $107.2
====== ===== ======
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 September 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 St. Mary's credit facility.
Capital and Exploration Expenditures Incurred. St. Mary's expenditures for
exploration and development of oil and gas properties and acquisitions are the
primary use of its capital resources. The following table sets forth certain
information regarding the costs incurred by St. Mary in its oil and gas
activities during the periods indicated:
Capital and Exploration Expenditures
------------------------------------
Nine Months Ended September 30,
-------------------------------
2002 2001
---- ----
(In thousands)
Development $ 52,584 $ 74,346
Domestic Exploration 12,704 18,451
Acquisitions:
Proved 7,886 3,819
Unproved 10,582 18,188
--------- ---------
Total $ 83,756 $ 114,804
========= =========
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 actively seeking larger acquisitions of assets or companies
that would afford opportunities to expand our existing core areas, add
geoscientists and/or engineers, or gain a significant acreage and production
foothold in a new basin.
St. Mary's total costs incurred for capital and exploration activities in
the first nine months of 2002 decreased $28.0 million or 24% compared to the
first nine months of 2001. We spent $75.9 million in the first nine months of
20
2002 for unproved property acquisitions and domestic exploration and development
compared to $111.0 million for the comparable period in 2001. This decrease was
a result of planned decreases in the drilling activity budget and a $7.6 million
decrease in unproved property acquisition activity. Well testing continues on
our two coalbed methane pilot programs located on fee acreage in the Hanging
Woman Basin. All wells are currently shut-in while we evaluate the data from
dewatering. Prior to shut-in, production from the Anderson coal averaged 250
Mcf/day. During the year, one of our partners exercised their right to
participate in a leasehold acquisition bringing our total to 123,000 net acres
in the project. We are subject to an environmental public interest group lawsuit
on 46,000 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. On October 15, 2002, the Board refused to reconsider
this holding period. 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.
On October 2, 2002, we signed a purchase and sale agreement with Burlington
Resources Oil & Gas Company LP to acquire oil and gas properties in the
Williston Basin of Montana and North Dakota for $76.4 million in cash. The
effective date of this acquisition is July 1, 2002. We intend to finance this
acquisition using cash on hand and our bank credit facility. These properties
currently produce an estimated 3.1 MBbls of oil per day and 3.3 MMcf of natural
gas per day. This transaction is expected to close December 3, 2002, upon
completion of customary due diligence.
Capital Expenditure Budget. We anticipate spending approximately $189
million for capital and exploration expenditures in 2002 with $104 million
allocated for ongoing exploration and development and $85 million for
acquisitions of producing properties. Anticipated ongoing exploration and
development expenditures for each of St. Mary's core areas is as follows (in
millions):
o Mid-Continent region $ 42
o Gulf Coast and Gulf of Mexico region 20
o ArkLaTex region 12
o Williston Basin 18
o Permian Basin and other 6
o Other 6
-----
Total $ 104
=====
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
21
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.
We seek to protect our 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. We anticipate this strategy will result in the hedging
of future cash flow from acquisitions. We generally limit St. Mary's aggregate
hedge position to no more than 35% of total production but will hedge larger
percentages of total production in certain circumstances. We seek to minimize
basis risk and index the majority of oil hedges to NYMEX prices and the majority
of gas hedges to various regional index prices associated with pipelines in
proximity to our areas of gas production. Including hedges entered into since
September 30, 2002 we have hedged as follows:
Swaps:
------
Average Quantity Average
Product Volumes/month Type Fixed price Duration
------- ------------- -------- ----------- --------
Natural Gas 1,696,000 MMBtu $2.87 10/02 - 12/02
Natural Gas 565,000 MMBtu $3.38 01/03 - 12/03
Natural Gas 299,000 MMBtu $3.66 01/04 - 12/04
Oil 200,300 Bbls $27.07 10/02 - 12/02
Oil 146,500 Bbls $24.88 01/03 - 12/03
Oil 65,500 Bbls $23.80 01/04 - 12/04
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, and was
recorded as a hedge gain in the first quarter of 2002. Hedge gains and losses
are reported in oil and gas production revenues in our consolidated statements
of operations. Amortization of $1.2 million of other comprehensive income
related to our commodity positions with Enron is also recorded in hedge gain.
Additional amortization will be recorded in hedge gain in future months.
Unrealized derivative gain in the consolidated statements of operations includes
$4,000 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 a decrease to the convertible notes payable in the
consolidated balance sheets. Of this amount, $51,000 has been amortized through
interest expense. Unrealized derivative gain in the consolidated statements of
operations includes $239,000 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 in the consolidated statements of
operations includes $4.8 million of net gain from mark-to-market adjustments for
this derivative.
We anticipate that all hedge transactions will occur as expected.
22
Accounting Matters
New 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 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. SFAS No. 146 is
to be applied prospectively to exit or disposal activities initiated after
December 31, 2002. We do not have any pending or planned exit or disposal
activities and do not expect a material effect on our 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." 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 generally
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.
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
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.
23
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 and the audit committee periodically review 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 values 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 values of the futures are
based on quoted market prices obtained from the New York Mercantile Exchange.
A hypothetical $0.10 per MMBtu change in St. Mary's quarter-end market
prices for natural gas swaps and futures contracts on a notional amount of 15.5
million MMBtu would cause a potential $1.1 million change in net income before
income taxes for contracts in place on September 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 3.1 MMBbls would cause a potential $2.9
million change in net income before income taxes for oil contracts in place on
September 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 September 30, 2002, that are sensitive to changes in interest rates. For
fixed-rate debt, interest rate changes affect the fair market value but do not
impact results of operations or cash flows. Conversely 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. We had floating rate debt of $50.0 million and fixed rate debt of
$50.0 million at September 30, 2002. 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
$125,000 before taxes.
24
ITEM 4. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are
designed for the purposes of ensuring that information required to be disclosed
in our SEC reports is recorded, processed, summarized and reported within the
time periods specified in the SEC's rules and forms, and that such information
is accumulated and communicated to our management, including the Chief Executive
Officer and the Vice-President - Finance, as appropriate to allow timely
decisions regarding required disclosure.
Within the 90-day period prior to the filing of this report, we carried out
an evaluation, under the supervision and with the participation of our
management, including the Chief Executive Officer and the Vice-President -
Finance, of the effectiveness of the design and operation of our disclosure
controls and procedures. Based upon that evaluation, the Chief Executive Officer
and the Vice-President - Finance concluded that our disclosure controls and
procedures are effective for the purposes discussed above. There have been no
significant changes in our internal controls or in other factors that could
significantly affect these controls subsequent to the date of their evaluation.
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 in the U.S. District Court for the District of
Montana on June 12, 2001. The plaintiff, the Northern Plains Resource
Council, Inc. ("NPRC"), an environmental public interest group, sued
the U.S. Bureau of Land Management, the U.S. Secretary of the
Interior, the Montana BLM State Director and Fidelity Exploration
& Production Company. The lawsuit, which was reported in our 2001
Form 10-K and our first and second quarter 2002 Form 10-Qs, seeks the
cancellation of all federal leases related to coalbed methane
development in Montana issued by the BLM since January 1, 1997. This
cancellation is sought primarily on the grounds of an alleged failure
of the BLM to comply with federal environmental laws. NPRC alleges
that the environmental impacts of coalbed methane development were not
properly analyzed before the challenged leases were issued. The
Montana portion of our Hanging Basin Woman coalbed methane project
contains approximately 123,000 total net acres. The lawsuit
potentially affects the approximately 46,000 net acres that are
subject to federal leases. Based on information presently available,
we believe that the BLM complied with the applicable environmental
laws. Nevertheless, there is no assurance as to the outcome of the
lawsuit, and therefore, there is no assurance that it will not
adversely affect our coalbed methane project. Even if the federal
leases in Montana become unavailable, we 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.
As previously reported in our first and second quarter 2002 Form
10-Qs, 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. This
suit was filed 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. These
leases were acquired by the exercise of a contractual preferential
right to purchase. This right was triggered by the plaintiff in its
attempt to acquire these same leasehold positions from the party that
ultimately sold these positions to GNK Acquisition Corp. Samson
alleges that it is entitled to acquire a portion of such lease
25
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 5. Other Information
-----------------
As previously reported in Part III, Item 13 of our Annual Report
on Form 10-K/A No. 2 for the year ended December 31, 2001, St. Mary
made an interest-free relocation loan of $200,000 to an executive
officer in July 2000. The loan was due and payable in full upon the
earlier of thirty days after a termination of employment or July 15,
2005. The loan was repaid in full in October 2002 and is no longer
outstanding, notwithstanding the continued employment of the executive
officer.
On October 31, 2002, the Audit Committee of the Board of
Directors of St. Mary approved in advance certain non-audit services
to be performed by Deloitte & Touche LLP, St. Mary's independent
auditor. These non-audit services are to consist primarily of
corporate tax compliance and tax consultation services.
ITEM 6. Exhibits and Reports on Form 8-K
--------------------------------
(b) Reports on Form 8-K
St. Mary Land & Exploration Company filed the
following current reports on Form 8-K during the quarter ended
September 30, 2002:
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 update of the 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.
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.
On August 14, 2002, we filed a current report on Form
8-K reporting under Item 9 that in connection with the filing
of the Form 10-Q, on August 14, 2002, the Chief Executive
Officer and the Vice-President - Finance of the registrant
each signed a Certification pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
On August 28, 2002, we filed a current report on Form
8-K reporting under Item 9 that in connection with the filing
of the amended Annual Report on Form 10-K/A No. 2, on August
28, 2002, the Chief Executive Officer and the Vice-President -
Finance of the registrant each signed a Certification pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
26
On September 24, 2002, we filed a current report on
Form 8-K reporting under Item 5 that we had issued a press
release announcing the retirement of Thomas E. Congdon as
Board Chairman.
27
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
November 13, 2002 By /s/ MARK A. HELLERSTEIN
--------------------------------
Mark A. Hellerstein
Chairman of the Board, President
and Chief Executive Officer
November 13, 2002 By /s/ RICHARD C. NORRIS
--------------------------------
Richard C. Norris
Vice-President - Finance, Secretary
and Treasurer
November 13, 2002 By /s/ GARRY A. WILKENING
--------------------------------
Garry A. Wilkening
Vice-President - Administration
and Controller
CERTIFICATION
I, Mark A. Hellerstein, certify that:
1. I have reviewed this quarterly report on Form 10-Q of St. Mary Land
& Exploration Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 13, 2002
/s/ MARK A. HELLERSTEIN
------------------------------------
Mark A. Hellerstein
Chairman of the Board, President and
Chief Executive Officer
CERTIFICATION
I, Richard C. Norris, certify that:
1. I have reviewed this quarterly report on Form 10-Q of St. Mary Land
& Exploration Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 13, 2002
/s/ RICHARD C. NORRIS
------------------------------------
Richard C. Norris
Vice-President - Finance