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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 September 30, 2003
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Commission file number: 001-31539
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 41-0518430
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1776 Lincoln Street, Suite 700, Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [ |X| ] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ |X| ] No [ ]
Indicate the number of shares outstanding of each of the registrant's classes of
common stock as of the latest practicable date.
As of October 31, 2003, the registrant had 31,537,477 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 - September 30, 2003 and
December 31, 2002..........................................3
Consolidated Statements of
Operations - Three and Nine Months Ended
September 30, 2003 and 2002................................4
Consolidated Statements of
Cash Flows - Nine Months Ended
September 30, 2003 and 2002................................5
Consolidated Statements of
Stockholders' Equity and
Comprehensive Income - September 30,
2003 and December 31, 2002.................................7
Notes to Consolidated Financial
Statements - September 30, 2003............................8
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations..............................................16
Item 3. Quantitative and Qualitative Disclosures
About Market Risk..........................................31
Item 4. Controls and Procedures....................................32
Part II. OTHER INFORMATION
Item 1. Legal Proceedings..........................................32
Item 5. Other Information..........................................33
Item 6. Exhibits and Reports on Form 8-K...........................34
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
September 30, December 31,
------------------------------
ASSETS 2003 2002
------------- ------------
Current assets:
Cash and cash equivalents $ 7,114 $ 11,154
Short term investments 2,519 1,933
Accounts receivable 58,745 35,399
Prepaid expenses and other 4,712 6,510
Accrued derivative asset 1,956 -
Refundable income taxes 2,395 1,031
Deferred income taxes 4,529 3,520
------------- ------------
Total current assets 81,970 59,547
------------- ------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 831,642 683,752
Less accumulated depletion, depreciation and amortization (296,543) (263,436)
Unproved oil and gas properties, net of impairment
allowance of $11,720 in 2003 and $8,865 in 2002 61,533 47,984
Other property and equipment, net of accumulated depreciation
of $4,351 in 2003 and $3,586 in 2002 4,301 3,639
------------- ------------
Total property and equipment 600,933 471,939
------------- ------------
------------- ------------
Other noncurrent assets 6,557 5,653
------------- ------------
------------- ------------
Total Assets $ 689,460 $ 537,139
============= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 76,130 $ 48,790
Accrued hedge liability 13,118 8,707
------------- ------------
Total current liabilities 89,248 57,497
------------- ------------
Noncurrent liabilities:
Long-term credit facility 13,000 14,000
Convertible notes 99,672 99,601
Deferred income taxes 80,972 60,156
Asset retirement obligation liability 24,635 -
Other noncurrent liabilities 9,763 5,727
------------- ------------
Total noncurrent liabilities 228,042 179,484
------------- ------------
Commitments and contingencies
------------- ------------
Minority interest 602 645
------------- ------------
Temporary equity (Note 9):
Common stock subject to put and call options, $0.01 par value
issued and outstanding - 3,380,818 shares in 2003 and -0-
shares in 2002 71,594 -
Note receivable from Flying J (71,594) -
------------- ------------
Total Temporary Equity - -
------------- ------------
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares;
issued - 29,155,441 shares in 2003 and 28,983,110 shares in
2002; outstanding, net of treasury shares - 28,152,741 shares
in 2003 and 27,973,210 shares in 2002 292 290
Additional paid-in capital 144,816 140,688
Treasury stock - at cost: 1,002,700 shares in 2003 and 1,009,900
shares in 2002 (16,057) (16,210)
Retained earnings 251,839 182,512
Accumulated other comprehensive loss (9,322) (7,767)
------------- ------------
Total stockholders' equity 371,568 299,513
------------- ------------
------------- ------------
Total Liabilities, Temporary Equity and Stockholders' Equity $ 689,460 $ 537,139
============= ============
The accompanying notes are an integral part
of these consolidated financial statements.
-3-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per share amounts)
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
Operating revenues:
Oil and gas production $ 86,414 $ 45,121 $ 278,236 $ 132,411
Loss on sale of proved properties (343) (503) (221) (90)
Marketed gas system revenue 3,911 3,366 11,019 6,810
Other oil and gas revenue 481 185 2,521 932
Derivative gain 325 2,619 358 4,594
Other revenues 211 166 3,994 1,073
------------- ------------- ------------- -------------
Total operating revenues 90,999 50,954 295,907 145,730
------------- ------------- ------------- -------------
Operating expenses:
Oil and gas production 23,914 12,392 68,304 37,953
Depletion, depreciation, amortization and abandonment
liability accretion 20,765 12,836 61,251 39,169
Exploration 9,883 4,219 20,668 15,432
Abandonment and impairment of unproved properties 2,300 587 4,003 1,906
General and administrative 5,535 4,388 17,699 10,544
Marketed gas system operating expense 3,584 3,545 10,041 6,631
Minority interest and other 707 286 1,202 906
------------- ------------- ------------- -------------
Total operating expenses 66,688 38,253 183,168 112,541
------------- ------------- ------------- -------------
Income from operations 24,311 12,701 112,739 33,189
Nonoperating income (expense):
Interest income 73 288 647 568
Interest expense (1,833) (1,110) (6,416) (2,580)
------------- ------------- ------------- -------------
Income before income taxes and cumulative effect of
change in accounting principle 22,551 11,879 106,970 31,177
Income tax expense 8,765 4,205 41,505 10,596
------------- ------------- ------------- -------------
Income before cumulative effect of change in accounting
principle 13,786 7,674 65,465 20,581
Cumulative effect of change in accounting principle, net - - 5,435 -
------------- ------------- ------------- -------------
Net income $ 13,786 $ 7,674 $ 70,900 $ 20,581
============= ============= ============= =============
Basic earnings per common share:
Income before cumulative effect of change in accounting
principle $ 0.44 $ 0.28 $ 2.11 $ 0.74
Cumulative effect of change in accounting principle - - 0.17 -
------------- ------------- ------------- -------------
Basic net income per common share $ 0.44 $ 0.28 $ 2.28 $ 0.74
============= ============= ============= =============
Diluted earnings per common share:
Income before cumulative effect of change in accounting
principle $ 0.41 $ 0.27 $ 1.93 $ 0.72
Cumulative effect of change in accounting principle - - 0.15 -
------------- ------------- ------------- -------------
Diluted net income per common share $ 0.41 $ 0.27 $ 2.08 $ 0.72
============= ============= ============= =============
Basic weighted average common shares outstanding 31,529 27,873 31,126 27,828
============= ============= ============= =============
Diluted weighted average common shares outstanding 35,828 28,448 35,426 28,388
============= ============= ============= =============
Cash dividends declared per common share $ - $ - $ 0.05 $ 0.05
============= ============= ============= =============
The accompanying notes are an integral part
of these consolidated financial statements.
-4-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
For the Nine Months Ended
September 30,
------------------------------
Reconciliation of net income to net cash provided 2003 2002
by operating activities: ------------- ------------
Net income $ 70,900 $ 20,581
Adjustments to reconcile net income to net
cash provided by operating activities:
Loss on sale of proved properties 221 90
Depletion, depreciation and amortization 61,251 39,169
Exploratory dry hole expense 7,497 7,293
Abandonment and impairment of unproved properties 4,003 1,906
Unrealized derivative gain (358) (4,594)
Mark to market of long-term net profit plans 2,406 860
Deferred income taxes 15,612 10,016
Minority interest and other (1,324) (2,904)
Cumulative effect of change in accounting principle,
net of tax (5,435) -
------------- ------------
154,773 72,417
Changes in current assets and liabilities:
Accounts receivable (23,346) 12,962
Prepaid expenses and other 1,798 (1,442)
Refundable income taxes 1,943 9,215
Accounts payable and accrued expenses 15,746 13,000
------------- ------------
Net cash provided by operating activities 150,914 106,152
------------- ------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 2,717 166
Capital expenditures (81,218) (65,106)
Acquisition of oil and gas properties, including related
$71,594 loan to Flying J in 2003 (75,234) (21,574)
Proceeds from distribution and sale of KMOC stock - 3,114
Deposits to short term investments available-for-sale (1,029) (11,484)
Proceeds from short term investments available-for-sale 950 1,000
Other 166 26
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Net cash used in investing activities (153,648) (93,858)
------------- ------------
Cash flows from financing activities:
Proceeds from credit facility 120,011 16,000
Repayment of credit facility (122,020) (80,000)
Proceeds (costs) from issuance of convertible notes (78) 96,661
Proceeds from sale of common stock 2,354 1,390
Dividends paid (1,573) (1,391)
------------- ------------
Net cash provided by (used in) financing activities (1,306) 32,660
------------- ------------
Net change in cash and cash equivalents (4,040) 44,954
Cash and cash equivalents at beginning of period 11,154 4,116
------------- ------------
Cash and cash equivalents at end of period $ 7,114 $ 49,070
============= ============
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,
------------------------------
2003 2002
------------- ------------
(In thousands)
Cash paid for interest, including amounts capitalized $ 7,245 $ 284
Cash paid for income taxes 23,208 10,386
In January 2003 the Company issued 7,200 shares of common stock from
treasury to its non-employee directors and recorded compensation expense
of $153,000.
In January 2003 the Company issued 3,380,818 restricted shares of common
stock to Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
(collectively, "Flying J") and entered into a put and call option agreement
with Flying J with respect to those shares in connection with the
acquisition of oil and gas properties and related assets and liabilities.
In June 2002 the Company issued 800 shares of common stock to a
non-employee director and recorded compensation expense of $14,763.
In April 2002 the Company accepted 9,472,562 shares of common stock in
Constellation Copper Corporation ("Constellation", formerly known as Summo
Minerals Corporation) in lieu of cash payment for the relief of a
$1,400,000 loan and $15,311 in interest due to the Company.
In January 2002 the Company issued 7,200 shares of common stock to its
non-employee directors and recorded compensation expense of $129,683.
The accompanying notes are an integral part
of these consolidated financial statements.
-6-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock Other Total
------------------ Paid-in --------------------- Retained Comprehensive Stockholders'
Shares Amount Capital Shares Amount Earnings Income (Loss) Equity
---------- ------- ---------- ---------- --------- ---------- ------------- -------------
---------- ------- ---------- ---------- --------- ---------- ------------- -------------
Balances, December 31, 2001 28,779,808 $ 288 $ 137,384 (1,009,900) $(16,210) $ 157,739 $ 6,916 $ 286,117
---------- ------- ---------- ---------- --------- ---------- ------------- -------------
Comprehensive income:
Net Income - - - - - 27,560 - 27,560
Unrealized net loss on marketable
equity securities available for
sale - - - - - - (725) (725)
Change in derivative instrument
fair value - - - - - - (14,644) (14,644)
Reclass to earnings - - - - - - 1,447 1,447
Minimum pension liability
adjustment - - - - - - (761) (761)
------------- -------------
Total comprehensive income 12,877
-------------
Cash dividends, $ 0.10 per share - - - - - (2,787) - (2,787)
Issuance for Employee Stock Purchase
Plan 18,217 - 344 - - - - 344
ESPP disqualified distribution - - 21 - - - - 21
Sale of common stock, including
income tax benefit of stock
option exercises 177,085 2 2,743 - - - - 2,745
Accelerated vesing of retiring
director option - - 52 - - - - 52
Directors' stock compensation 8,000 - 144 - - - - 144
---------- ------- ---------- ---------- --------- ---------- ------------- -------------
Balances, December 31, 2002 28,983,110 $ 290 $ 140,688 (1,009,900) $(16,210) $ 182,512 $ (7,767) $ 299,513
---------- ------- ---------- ---------- --------- ---------- ------------- -------------
Comprehensive income:
Net Income - - - - - 70,900 - 70,900
Unrealized net gain on marketable
equity securities available for
sale - - - - - - 716 716
Change in derivative instrument
fair value - - - - - - (14,248) (14,248)
Reclass to earnings - - - - - - 11,977 11,977
-------------
Total comprehensive income 69,345
-------------
Cash dividends, $ 0.05 per share - - - - - (1,573) - (1,573)
Issuance for Employee Stock Purchase
Plan 10,018 - 213 - - - - 213
Value of net option rights granted
to Flying J - - 995 - - - - 995
Sale of common stock, including
income tax benefit of stock option
exercises 162,313 2 2,920 - - - - 2,922
Directors' stock compensation - - - 7,200 153 - - 153
---------- ------- ---------- ---------- --------- ---------- ------------- -------------
Balances, September 30, 2003 29,155,441 $ 292 $ 144,816 (1,002,700) $(16,057) $ 251,839 $ (9,322) $ 371,568
========== ======= ========== ========== ========= ========== ============= =============
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, 2003
Note 1 - The Company and Business
St. Mary Land & Exploration Company ("St. Mary" or the "Company") is an
independent energy company engaged in the exploration, development, acquisition
and production of natural gas and crude oil. The Company's operations are
conducted entirely in the United States.
Note 2 - Basis of Presentation
The accompanying unaudited condensed consolidated financial statements of
St. Mary have been prepared in accordance with accounting principles generally
accepted in the United States for interim financial information. They do not
include all information and notes required by generally accepted accounting
principles for complete financial statements. However, except as disclosed
herein, there has been no material change in the information disclosed in the
notes to consolidated financial statements included in St. Mary's Annual Report
on Form 10-K for the year ended December 31, 2002. In the opinion of management,
all adjustments (consisting of normal recurring accruals) considered necessary
for a fair presentation have been included. Operating results for the periods
presented are not necessarily indicative of the results that may be expected for
the full year.
The accounting policies followed by the Company are set forth in Note 1 to
the Company's consolidated financial statements in the Form 10-K for the year
ended December 31, 2002. It is suggested that these unaudited condensed
consolidated financial statements be read in conjunction with the consolidated
financial statements and notes included in the Form 10-K.
Note 3 - Earnings Per Share
Basic net income per common share of stock is calculated by dividing net
income by the weighted average of common shares outstanding during each period.
During the first quarter of 2003, the Company issued 3,380,818 shares of common
stock as part of an acquisition (see Note 9). These shares are considered
outstanding for purposes of calculating basic and diluted net income per common
share and are weighted accordingly in the calculation of common shares
outstanding. These shares are included in the temporary equity section of the
accompanying consolidated balance sheets. Following is a reconciliation of total
shares outstanding as of September 30, 2003.
Common shares outstanding in Stockholders' equity 28,152,741
Restricted common shares outstanding in Temporary equity 3,380,818
-------------
Total common shares outstanding 31,533,559
=============
Diluted net income per common share of stock is calculated by dividing
adjusted net income by the weighted average of common shares outstanding and
other dilutive securities. Adjusted net income is used for the if-converted
method discussed below and is derived by adding interest expense paid on the
Company's 5.75% Senior Convertible Notes due 2022 (the "Convertible Notes") back
to net income and then adjusting for nondiscretionary items including the
related income tax effect. Potentially dilutive securities of the Company
consist of in-the-money outstanding options to purchase the Company's common
stock, shares into which the Convertible Notes may be converted, and any
incremental shares that based on current market prices are assumed will be
issued under the reverse-treasury method assumptions if the put option described
in Note 9 is exercised.
-8-
The treasury stock method is used to measure the dilutive impact of stock
options. The following table details the weighted-average dilutive and
anti-dilutive securities related to stock options for the periods presented.
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Dilutive 453,208 394,008 453,905 399,676
Anti-dilutive 794,455 1,163,790 673,807 843,936
Shares associated with the conversion feature of the Convertible Notes are
accounted for using the if-converted method. Under the if-converted method,
income used to calculate diluted earnings per share is adjusted for the interest
charges and nondiscretionary adjustments based on income that would have changed
had the Convertible Notes been converted at the beginning of the period.
Potentially dilutive shares of 3,846,153 related to the Convertible Notes were
included in the calculation of diluted net income per share for the three and
nine months ended September 30, 2003. The Convertible Notes were issued in March
2002. Shares related to the put option that was granted on January 29, 2003 are
accounted for using the reverse-treasury method. There is no dilutive effect for
the put option in the current quarter or year to date as the average market
value of the Company's stock exceeded the strike price of the put option.
Note 4 - Compensation Plans
The Company accounts for stock-based compensation using the intrinsic value
recognition and measurement principles prescribed in Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25"), and
related interpretations. No stock-based employee compensation expense is
reflected in net income as all options granted under those plans had an exercise
price equal to the market value of the underlying common stock on the date of
grant. The following table illustrates the effect on net income and earnings per
share if the Company had applied the fair value recognition provisions of
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for
Stock-Based Compensation," to stock-based employee compensation for the periods
presented (in thousands, except per share amounts).
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------- -------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Net income
As reported $13,786 $ 7,674 $70,900 $20,581
Pro forma 12,096 6,355 66,606 17,078
Basic earnings per share
As reported $ 0.44 $ 0.28 $ 2.28 $ 0.74
Pro forma 0.38 0.23 2.14 0.61
Diluted earnings per share
As reported $ 0.41 $ 0.27 $ 2.08 $ 0.72
Pro forma 0.36 0.22 1.96 0.60
For purposes of pro forma disclosures, the estimated fair values of the
options are amortized to expense over the options' vesting periods. The effects
of applying SFAS No. 123 in the pro forma disclosure are not necessarily
indicative of actual future amounts.
-9-
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair value of options granted in 2003
and 2002 were estimated using the following weighted-average assumptions.
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------- -------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Risk free interest rate 3.84% 2.68% 3.28% 4.02%
Dividend yield 0.39% 0.42% 0.39% 0.43%
Volatility factor of the
expected market price of
the Company's common
stock 49.41% 49.81% 48.70% 47.32%
Expected life of the options
(in years) 7.7 5.0 6.7 6.1
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options that have no vesting restrictions,
are fully transferable, and are not subject to trading restrictions or black out
periods. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Since the
Company's employee stock options have characteristics significantly different
from those of traded options, and because changes in the subjective input
assumptions can materially affect the fair value estimate, it is management's
opinion that the existing models do not necessarily provide a reliable single
measure of the fair value of St Mary's employee stock options.
In December 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure: an amendment of FASB Statement No. 123." This statement provided for
transition methods for adopting the fair value accounting model of accounting
for the issuance of stock options. The statement provides for three alternative
adoption methods: (1) The retroactive method - where all prior periods are
restated to reflect the expensing of all options granted on a retroactive basis,
(2) The modified-prospective method-where a company begins expensing all prior
and current option grants in the current year, and (3) The prospective
method-where a company begins expensing all current period option grants in the
current year. St. Mary is continuing to evaluate these adoption alternatives and
current FASB discussions as well as considering the issuance of restricted stock
for its equity component of employee compensation.
Note 5 - Income Taxes
Income tax expense for the three and nine months ended September 30, 2003
and 2002 differ from the amounts that would be provided by applying the
statutory U.S. Federal income tax rate to income before income taxes primarily
due to the effect of state income taxes, percentage depletion, Internal Revenue
Code Section 29 credits, valuation allowance adjustments against prior year
credits, and changes in the composition of income tax rates. For the three and
nine month periods ended September 30, 2003, the Company's current portion of
income tax expense was $4,038,000 and $25,892,000 respectively, compared to a
benefit of $900,000 and expense of $502,000 for the same respective periods in
2002.
-10-
Note 6 - Long-term Debt
In January 2003 the Company replaced its revolving credit facility with a
new long-term revolving credit agreement with a group of banks. The new credit
agreement specifies a maximum loan amount of $300,000,000 and has a maturity
date of January 27, 2006. Borrowings under the facility are secured by a pledge
in favor of the lenders of collateral that includes certain oil and gas
properties and the common stock of the material subsidiaries of the Company. A
borrowing base of $275,000,000 was determined by the bank group at the end of
October 2003 under a normal semi-annual determination. The borrowing base
determination process considers the value of St. Mary's oil and gas properties
and other assets, as determined by the bank syndicate. We have elected an
aggregate commitment amount of $150,000,000. The Company must comply with
certain financial and non-financial covenants. Interest and commitment fees are
accrued based on the borrowing base utilization percentage table below.
Eurodollar loans accrue interest at LIBOR plus the applicable margin from the
utilization table, and Alternative Base Rate (ABR) loans accrue interest at
Prime plus the applicable margin from the utilization table. Commitment fees are
accrued on the unused portion of the aggregate commitment amount and are
included in interest expense in the consolidated statements of operations.
Borrowing base
utilization percentage <50% =>50%<75% =>75%<90% >90%
---------------------------------------------------------------------------
Eurodollar Loans 1.25% 1.50% 1.75% 2.00%
ABR Loans 0.00% 0.25% 0.50% 0.75%
Commitment Fee Rate 0.30% 0.38% 0.38% 0.50%
At September 30, 2003, the Company's borrowing base utilization percentage
as defined under the credit agreement was 9%. The Company had $13,000,000 in
Eurodollar loans and no ABR loans outstanding under its revolving credit
agreement as of September 30, 2003. Had the Company desired to incur additional
borrowings to increase its current assets, it could have elected to borrow an
amount necessary to ensure a net working capital position. As of November 5,
2003, the Company has repaid an additional $8,000,000 of the credit facility
resulting in an outstanding balance of $5,000,000.
As of September 30, 2003, the Company also had $100,000,000 in outstanding
borrowings under the Convertible Notes. The Convertible Notes provide for the
payment of contingent interest of up to an additional 0.5% during six-month
interest periods based on the note trading price before the beginning of the
particular six-month period. Under that provision, interest was accrued at a
total rate of 6.25% for the quarter and nine-month periods ended September 30,
2003. Based on the trading price of the Convertible Notes over the determination
period, the Company will be subject to the contingent interest payments for the
period from September 16, 2003, to March 15, 2004.
On October 3, 2003, the Company entered into fixed to floating interest
rate swaps for a total notional amount of $50,000,000 through March 20, 2007.
This date is the first date on which the Convertible Notes can be redeemed
solely at St. Mary's option for 100% of the principal amount plus accrued and
unpaid interest. Under the swaps St. Mary will be paid a fixed interest rate of
5.75% and will pay a variable interest rate of 235 basis points above the six
month LIBOR rate as determined on the semi-annual settlement date. The 6-month
LIBOR rate on October 3, 2003 was 1.16%. The payment dates of the swaps match
exactly with the interest payment dates of the Convertible Notes.
The weighted average interest rates paid for the third quarter of 2003 and
for the nine months ended September 30, 2003 were 7.0% and 6.1%, respectively,
including commitment fees paid on the unused portion of the credit facility
aggregate commitment, amortization of deferred financing costs, and amortization
of the contingent interest embedded derivative. The impact of the commitment
fees over a lower average outstanding balance results in a higher weighted
average interest rate despite lower LIBOR interest rates than in previous
quarters.
-11-
Note 7 - Derivative Financial Instruments
The Company recognized a net loss of $19,284,000 from its derivative
contracts for the nine months ended September 30, 2003, and a net gain of
$7,329,000 for the nine months ended September 30, 2002. Comparative amounts for
the three months ended September 30, 2003 and 2002 were a net loss of $4,216,000
and a net gain of $1,868,000, respectively.
The Convertible Notes contain a provision for payment of contingent
interest if certain conditions are met. Under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," this provision is considered an
embedded equity-related derivative that is not clearly and closely related to
the fair value of an equity interest and therefore must be separately treated as
a derivative instrument. The value of the derivative at issuance of the
Convertible Notes in March 2002 was $474,000. This amount was recorded as a
decrease to the Convertible Notes payable in the consolidated balance sheets. Of
this amount, $71,000 and $51,000 were amortized through interest expense for the
nine-month periods ended September 30, 2003 and 2002, respectively. Interest
expense for each of the three-month periods ended September 30, 2003 and 2002
includes $24,000 of amortization. Derivative gain in the consolidated statements
of operations for the nine-month periods ended September 30, 2003 and 2002
includes net gain of $247,000 and a net loss of $239,000, respectively, from
mark-to-market adjustments for this derivative. Derivative gain for the three
month periods ended September 30, 2003 and 2002 includes net gains of $261,000
and $83,000, respectively, from mark-to-market adjustments.
The Company's previous fixed-rate to floating-rate interest rate swap on
$50,000,000 of the Convertible Notes did not qualify for cash flow or fair value
hedge accounting treatment under SFAS No. 133. This contract was entered into on
March 25, 2002, and was closed out on December 3, 2002. Derivative gain in the
consolidated statement of operations for the period ended September 30, 2002,
includes $4,838,000 of net unrealized mark-to-market gain from the interest rate
swap contract.
The Company has in place derivative contracts for the sale of oil and
natural gas. These contracts include traditional swap and collar arrangements.
The Company attempts to qualify the majority of these instruments as cash flow
hedges for accounting purposes.
The following table summarizes all derivative instrument activity (in
thousands).
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Gain (Loss) Gain (Loss)
Derivative contract settlements included in
oil and gas production revenues $ (4,517) $ (727) $(19,571) $ 2,786
Ineffective portion of hedges qualifying for
hedge accounting included in derivative loss 28 (58) 75 (4)
Non-qualified derivative contracts included
in derivative gain (loss) 297 2,677 283 4,598
Amortization of contingent interest derivative
through interest expense (24) (24) (71) (51)
------------ ------------ ------------ ------------
Total $ (4,216) $ 1,868 $(19,284) $ 7,329
============ ============ ============ ============
-12-
On September 30, 2003, St. Mary's remaining cash flow hedge positions
resulted in a net pre-tax liability of $14,157,000. The Company anticipates it
will reclassify $13,983,000 of this amount to gains or losses included in oil
and gas production operating revenues as the hedged production quantity is
produced. The remaining amount relates to an undesignated collar that will be
marked to market through the consolidated statements of operations until it
expires on December 31, 2003. Based on current prices the net amount of existing
unrealized after-tax loss as of September 30, 2003, to be reclassified from
accumulated other comprehensive income to oil and gas production operating
revenues in the next twelve months would be $6,831,000, net of deferred income
taxes. The Company anticipates that all original forecasted transactions will
occur by the end of the originally specified time periods.
Note 8 - Asset Retirement Obligations
Effective January 1, 2003, the Company adopted the provisions of SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
applies to legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or the normal
operation of a long-lived asset. SFAS No. 143 requires the Company to recognize
an estimated liability for costs associated with the abandonment of its oil and
gas properties.
As of January 1, 2003, the Company recognized the future cost to abandon
oil and gas properties over the estimated economic life of the oil and gas
properties in accordance with the provisions of SFAS No. 143. A liability for
the fair value of an asset retirement obligation with a corresponding increase
to the carrying value of the related long-lived asset is recorded at the time a
well is completed or acquired. The Company depletes the amount added to proved
oil and gas property costs and recognizes accretion expense in connection with
the discounted liability over the remaining life of the respective oil and gas
properties. Prior to the adoption of SFAS No. 143 the Company had recognized an
abandonment liability for its offshore wells. These offshore liabilities were
reversed upon adoption of SFAS No. 143, and the methodology described above was
used to determine the liability associated with abandoning all wells, including
those offshore.
The estimated liability is based on historical experience in abandoning
wells, estimated economic lives, external estimates as to the cost to abandon
the wells in the future and federal and state regulatory requirements. The
liability is discounted using a credit-adjusted risk-free rate of approximately
7.25%. Revisions to the liability could occur due to changes in estimated
abandonment costs or well economic lives, or if federal or state regulators
enact new requirements regarding the abandonment of wells.
Upon adoption of SFAS No. 143, the Company recorded a discounted liability
of $21,403,000, reversed the existing offshore abandonment liability of
$9,144,000, increased property and equipment by $12,827,000, decreased
accumulated Depreciation, Depletion and Amortization ("DD&A") by $8,280,000
and recognized a one-time cumulative effect gain of $5,435,000 (net of deferred
tax benefit of $3,414,000).
The Company estimates that the salvage value of equipment included in its
oil and gas properties is $43,934,000 as of September 30, 2003. This amount is
excluded from the Company's DD&A calculation.
-13-
A reconciliation of the Company's liability for the three and nine months
ended September 30, 2003, is as follows (in thousands).
Three Months Ended Nine Months Ended
September 30, 2003 September 30, 2003
-------------------- --------------------
Beginning Asset Retirement Obligation $ 24,603 $ -
Liability from SFAS 143 adoption - 21,403
Liabilities incurred 522 3,415
Liabilities settled (925) (1,456)
Accretion expense 435 1,273
-------------------- --------------------
Ending Asset Retirement Obligation $ 24,635 $ 24,635
==================== ====================
The following tables illustrate the pro forma effect on the asset
retirement obligation liability, net income and earnings per share if the
Company had adopted the provisions of SFAS No. 143 on January 1, 2002. The pro
forma amounts of the liability are measured using current information,
assumptions and interest rates as of January 1, 2003 (in thousands, except per
share amounts).
January 1, 2002 December 31, 2002
-------------------- --------------------
Asset retirement
obligation liability $ 20,358 $ 21,829
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
-------------------- --------------------
Net Income
As reported $ 7,674 $ 20,581
Pro forma $ 7,435 $ 19,872
Basic EPS
As reported $ 0.28 $ 0.74
Pro forma $ 0.27 $ 0.71
Diluted EPS
As reported $ 0.27 $ 0.72
Pro forma $ 0.26 $ 0.69
Note 9 - Flying J Acquisition
On January 29, 2003, the Company acquired oil and gas properties from
Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. (collectively,
"Flying J"). St. Mary issued 3,380,818 restricted shares of its common stock to
Flying J. In addition, St. Mary made a non-recourse loan to Flying J of
$71,594,000 at LIBOR plus 2% for up to a 39-month period. This loan is secured
by a pledge of the shares of common stock issued to Flying J, with the final
nine months of interest on that loan to be subject to recourse to Flying J. St.
Mary also entered into a put and call option agreement with Flying J whereby
during the 39-month loan period Flying J can elect to put their shares of St.
Mary common stock to the Company for $71,594,000 plus accrued interest on the
loan during the first thirty months of the loan period, and St. Mary can elect
to call the shares for $97,447,000, with the proceeds from the exercise of
either the put option or the call option to be applied to the repayment of the
loan plus accrued and unpaid interest. The shares issued are restricted for a
period
-14-
of two years, and Flying J may not resell the shares during that period. If
neither Flying J nor St. Mary exercise their respective option rights, the loan
plus accrued interest will have to be repaid prior to the release of the
security interest in the shares.
Final valuation determinations for accounting purposes were made in the
third quarter of 2003 for this transaction. The net option with respect to
Flying J's contractual rights to obtain additional value from any appreciation
of the shares over the put amount up to the call amount was valued at $995,000.
For accounting purposes, the effect of the above arrangements is that we have
acquired properties in exchange for $71,594,000 of cash plus a net option to
Flying J valued at $995,000, resulting in a total valuation of $72,589,000. The
allocation of the purchase price for the net assets acquired was $72,357,000 of
proved reserves and unproved acreage, $445,000 of other assets, a $1,936,000
asset retirement liability, a $2,012,000 hedge liability, and $3,735,000 in net
cash received for purchase price adjustments. The allocation is subject to
change due to final determination of items such as the valuation of current
assets, exercises of preferential rights on properties acquired or final
settlements and adjustments to revenue and expenses relating to the period
between the effective date of the acquisition agreement and the closing date.
St. Mary expects to have the allocation finalized within the one year window
allowed for purchase price allocation adjustments. The acquisition was accounted
for using the purchase method of accounting. Operating results from the acquired
properties have been included in the consolidated statements of operations only
from the date of closing.
The shares of common stock that were issued in this transaction have been
recorded as temporary equity since they are subject to the put option whereby
the Company may be required to repurchase these shares. The shares of common
stock are considered outstanding for basic and diluted earnings per share
calculations. These shares could potentially become part of permanent
stockholders' equity in the future. The loan arising from this transaction is
considered a contra-temporary equity item on the consolidated balance sheets, as
opposed to an asset, since the loan is non-recourse to Flying J except with
respect to interest accrued after the first thirty months and is secured by the
restricted common stock issued as part of this transaction. Interest is not
being accrued for accounting purposes because of the non-recourse nature of the
loan. Interest income will only be recorded during the last nine months of the
loan period. Any interest amounts received related to the first thirty months of
the loan period will be recorded as an increase to additional paid-in capital.
For accounting purposes the net option is reflected in the equity section of our
consolidated balance sheets as additional paid-in capital.
Note 10 - Recently Issued Accounting Standards
In May 2003 the Financial Accounting Standards Board ("FASB") issued SFAS
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity." This Statement establishes standards for how an
issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity and requires that such financial
instruments be classified as a liability (or as an asset in certain
circumstances). SFAS No. 150 is effective for all freestanding instruments
entered into or modified after May 31, 2003. Otherwise, it became effective for
the Company as of July 1, 2003. St. Mary currently has no financial instruments
that fall within the scope of this Statement.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 addresses
accounting and reporting for business combinations and is effective for all
business combinations initiated after June 30, 2001. SFAS No. 142 addresses the
accounting and reporting for goodwill subsequent to acquisition and other
intangible assets. The new standard eliminates the requirement to amortize
acquired goodwill; instead, such goodwill is required to be reviewed at least
annually for impairment. The new standard also requires that, at a minimum, all
intangible assets be aggregated and presented as a separate line item in the
balance sheet. The adoption of SFAS No. 141 and SFAS No. 142 had no impact on
St. Mary's financial position or results of operations.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
requires companies to classify the costs of mineral rights held under lease or
other contractual arrangements associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
-15-
property costs, and provide specific footnote disclosures. Historically, St.
Mary has included the costs of such mineral rights associated with extracting
oil and gas as a component of oil and gas properties. If it is ultimately
determined that SFAS No. 142 requires oil and gas companies to classify costs of
mineral rights held under lease or other contractual arrangements associated
with extracting oil and gas as a separate intangible assets line item on the
balance sheet, St. Mary will reclassify these amounts out of oil and gas
properties and into a separate intangible assets line item. St. Mary's cash
flows and results of operations would not be affected since such intangible
assets would continue to be depleted and assessed for impairment. Further, St.
Mary does not believe the classification of the costs of mineral rights
associated with extracting oil and gas as intangible assets would have any
impact on compliance with covenants under its debt agreements.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Cautionary Note About Forward - Looking Statements
This Quarterly Report on Form 10-Q includes certain statements that may be
deemed to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. All statements, other than statements of historical facts, included in
this Form 10-Q that address activities, events or developments that St. Mary
management expects, believes or anticipates will or may occur in the future are
forward-looking statements. The words "will," "believe," "anticipate," "intend,"
"estimate," "expect," "project," and similar expressions are intended to
identify forward - looking statements, although not all forward - looking
statements contain such identifying words. Examples of forward-looking
statements may include discussion of such matters as:
o the amount and nature of future capital, development and exploration
expenditures,
o the drilling of wells,
o reserve estimates and the estimates of both future net revenues and the
present value of future net revenues that are included in their
calculation,
o future oil and gas production estimates,
o repayment of debt,
o business strategies,
o expansion and growth of operations,
o recent legal developments, and
o other similar matters.
These statements are based on certain assumptions and analyses made by us
in light of our experience and our perception of historical trends, current
conditions, expected future developments and other factors we believe are
appropriate in the circumstances. Such statements are subject to a number of
assumptions, risks and uncertainties, including such factors as the volatility
and level of oil and natural gas prices, unexpected drilling conditions and
results, production rates and reserve replacement, reserve estimates, drilling
and operating service availability and risks, uncertainties in cash flow, the
financial strength of hedge contract counterparties, the availability of
attractive exploration, development and property acquisition opportunities,
financing requirements, expected acquisition benefits, competition, litigation,
environmental matters, the potential impact of government regulations, and other
matters discussed in the "Risk Factors" section of our 2002 Annual Report on
Form 10-K. Readers are cautioned that forward-looking statements are not
guarantees of future performance and that actual results or developments may
differ materially from those expressed or implied in the forward-looking
statements. Although we may from time to time voluntarily update our prior
forward - looking statements, we disclaim any commitment to do so except as
required by securities laws.
-16-
The Company and Business
St. Mary Land & Exploration Company is an independent energy company
engaged in the exploration, development, acquisition and production of natural
gas and crude oil. Principal drivers to St. Mary's business are its ability to
replace oil and gas reserves, the rate at which it can produce oil and gas, the
prices received for products and its ability to control costs. Our operations
are conducted entirely in the United States.
Financial Results
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
(In thousands, except per share data)
Oil and gas production revenues $ 86,414 $ 45,121 $ 278,236 $ 132,411
Net income $ 13,786 $ 7,674 $ 70,900 $ 20,581
Net income per share - basic $ 0.44 $ 0.28 $ 2.28 $ 0.74
Net income per share - diluted $ 0.41 $ 0.27 $ 2.08 $ 0.72
Net Income
We generated net income of $13.8 million or $0.41 per diluted share for the
third quarter of 2003 compared with net income of $7.7 million or $0.27 per
diluted share for the same quarter of 2002. Comparing the nine months ended
September 30, 2003 to the nine months ended September 30, 2002, net income and
diluted earnings per share were $70.9 million and $2.08 per share versus $20.6
million and $0.72 per share, respectively. Included in net income for the nine
months ended September 30, 2003, is a $5.4 million gain, or $0.15 per diluted
share, associated with the cumulative effect of a change in accounting principle
required upon the adoption of Statement of Financial Accounting Standards No.
143 "Accounting for Asset Retirement Obligations." The increase in net income
over the comparative prior-year periods is a result of higher production volumes
associated with successful drilling results and the acquisition of the
Burlington properties in December 2002 and the Flying J properties in January
2003 as well as increased oil and gas prices. We have had notable drilling
success in the N.E. Mayfield area of western Oklahoma and in our ArkLaTex area,
and we continue to integrate and evaluate the acreage and property obtained from
Flying J in Wyoming and Montana.
-17-
Results of Operations
The following table sets forth selected operating data for the periods
indicated.
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
(In thousands, except volume and per volume data)
Oil and gas production revenues (1):
Gas production $ 56,134 $ 27,103 $ 187,715 $ 80,837
Oil production 30,280 18,018 90,521 51,574
------------ ------------ ------------ ------------
Total $ 86,414 $ 45,121 $ 278,236 $ 132,411
============ ============ ============ ============
Net production:
Gas (MMcf) 12,378 9,111 37,696 28,283
Oil (MBbls) 1,147 679 3,352 2,057
MMCFE 19,262 13,186 57,808 40,625
Net daily production:
Gas (MMcf) 134.5 99.0 138.1 103.6
Oil (MBbls) 12.5 7.4 12.3 7.5
MMCFE 209.4 143.3 211.8 148.8
Average realized sales price (1):
Gas (per Mcf) $ 4.53 $ 2.97 $ 4.98 $ 2.86
Oil (per Bbl) $ 26.39 $ 26.54 $ 27.01 $ 25.07
Oil and gas production costs:
Lease operating expense $ 16,282 $ 9,021 $ 45,302 $ 27,647
Transportation costs 1,751 790 5,082 2,367
Production taxes 5,881 2,581 17,920 7,939
------------ ------------ ------------ ------------
Total $ 23,914 $ 12,392 $ 68,304 $ 37,953
============ ============ ============ ============
Additional per MCFE data:
Sales price $ 4.49 $ 3.42 $ 4.81 $ 3.26
Lease operating expense 0.85 0.68 0.78 0.68
Transportation costs 0.09 0.06 0.09 0.06
Production taxes 0.31 0.20 0.31 0.19
------------ ------------ ------------ ------------
Operating margin $ 3.24 $ 2.48 $ 3.63 $ 2.33
============ ============ ============ ============
Depletion, depreciation and amortization $ 1.08 $ 0.97 $ 1.06 $ 0.96
General and administrative $ 0.29 $ 0.33 $ 0.31 $ 0.26
--------------------
(1)Includes the effects of St. Mary's hedging activities.
-18-
Three-Month Comparison
Oil and Gas Production Revenues. Our quarterly oil and gas production
revenues increased $41.3 million, or 92% to $86.4 million for the three months
ended September 30, 2003. The following table presents components of the
increase in total production revenues between 2003 and 2002.
Production Price Price
% Change $ Change % Change
---------- -------- --------
Natural Gas 36% $1.56/Mcf 53%
Oil 69% ($0.15)/Bbl (1%)
Following is our product mix.
Percentage of Revenue Percentage of Production
--------------------- ------------------------
Three Months Ended September 30, 2003 2002 2003 2002
------------------------------------------------------------------------------------------
Natural Gas 65% 60% 64% 69%
Oil 35% 40% 36% 31%
Average net daily production was 209.4 MMCFE for 2003 compared with 143.3
MMCFE in 2002, an increase of 46%. Included in our 2003 production volumes are
10.4 MMcf per day and 4.8 MBbls per day from the Burlington and Flying J
acquisitions. Wells completed in 2002 and 2003 and properties acquired in the
last quarter of 2002 and during 2003 have added revenue of $32.9 million and
average net daily production of 68.1 MMCFE in 2003 over the comparable 2002
period.
Projections of pricing for oil and natural gas for the remainder of the
year lead us to believe that our average realized price for each product will be
higher in 2003 than for comparable periods of 2002. The prices we receive
reflect the impact of market forces, which are influenced by many factors
including: political events, economic growth, supply, fuel demand, electricity
demand, weather, Organization of Petroleum Exporting Countries policies and
others.
Information regarding the current effects of oil and gas hedging activity
is included in the table below, which reflects increased hedging of oil
production as a result of our Burlington and Flying J acquisitions and a small
component of discretionary hedging.
Three Months Ended September 30 2003 2002
-------------------------------------------------------------------------------------------
o Percentage of oil production hedged 55% 55%
o Oil volumes hedged (MBbls) 636 376
o Decrease in oil revenue ($2.6 million) ($167,000)
o Average realized oil price per Bbl without hedging $28.66 $26.78
o Percentage of gas production hedged 44% 47%
o Natural gas MMBtu hedged 6.0 million 4.8 million
o Decrease in gas revenue ($1.9 million) ($560,000)
o Average realized gas price per Mcf without hedging $4.69 $3.04
Marketed Gas Revenue and Gas System Operating Expense. As a result of our
acquisition of gas gathering system lines in Coal County, Oklahoma, in February
2002 we began taking title to and marketing natural gas for third parties. For
the three months ended September 30, 2003, we received $3.9 million from the
sale of this natural gas compared to $3.4 million for the same period in 2002.
Operating costs associated with these revenues totaled $3.6 million for the
three months ended September 30, 2003 compared to $3.5 million for the same
period in 2002. The higher natural gas prices in 2003 are the primary reason the
-19-
revenues and costs are higher in 2003. Due to fluctuations in natural gas
prices, cost inflation, the composition of distillates in the processed gas, and
the variability of production from oil and gas wells, we may not always have a
positive gross margin from gas marketing.
Oil and Gas Production Expenses. Oil and gas production costs consist of
lease operating expense, production taxes and transportation expenses. Total
production costs increased $11.5 million or 93% to $23.9 million for the three
months ended September 30, 2003, from $12.4 million in the same period of 2002.
Our acquisition of properties from Burlington and Flying J added $7.2 million of
production costs, and wells completed in late 2002 and in 2003 added $1.7
million of production costs in 2003 that were not reflected in 2002.
Additionally, we experienced an increase in production taxes consistent with the
increase in revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.31 to $1.25 for
the third quarter of 2003 compared with $0.94 for the third quarter of 2002.
This increase is comprised of the following:
o An $0.11 increase in production taxes due to higher realized per MCFE
prices.
o A $0.03 increase due to rising transportation costs in our Rockies and
Mid-Continent regions.
o A $0.02 increase in LOE relating to one-time workover charges for projects
in our ArkLaTex region.
o A $0.19 increase in LOE that reflects our additions of higher cost oil
production properties in our Rockies region through our acquisitions from
Burlington and Flying J.
o A $0.04 decrease reflecting general decreases in LOE per MCFE in our other
core areas.
The benefit to production from workover activity in the second and third
quarters of 2003 is not expected to be realized until later in the year and
early 2004. We believe that our LOE per MCFE will increase during the remainder
of 2003 as a result of the impact of our acquisitions from Burlington and Flying
J. These increases could be offset in part by decreases in production taxes due
to possible decreases in oil and gas prices.
Depreciation, Depletion, Amortization and abandonment liability accretion.
Depreciation, depletion and amortization expense ("DD&A") increased $7.9
million or 62% to $20.8 million for the three months ended September 30, 2003,
from $12.8 million in the same period of 2002. DD&A per MCFE increased by
11% to $1.08 for the third quarter of 2003 compared with $0.97 in 2002. The
increase in expense is a result of both higher production volumes in 2003 and a
higher per unit rate which reflects costs of acquisitions and higher finding
costs associated with drilling results in 2002 and 2003.
Exploration. Exploration expense increased $5.7 million or 134% to $9.9
million for the three months ended September 30, 2003, compared with $4.2
million in 2002. The most significant component of our increase to exploration
expense was $6.4 million for the unsuccessful exploratory Duchesne prospect.
This amount does not include the $1.4 million impairment of the associated
nonproducing leasehold costs discussed below. The drilling results did not
confirm the geologic exploration model used to evaluate the Duchesne prospect,
and the well produced at below commercial rates. Also in 2003 we have increased
exploration overhead due to increases in our geologic and exploration staff as a
result of the acreage we have acquired in the Williston, Green River and Powder
River basins. Components of total exploration expense are as follows (in
thousands).
-20-
Three Months Ended
September 30,
--------------------------
2003 2002
------------ ------------
o Geological and geophysical expenses $ 687 $ 809
o Exploratory dry holes 6,355 1,160
o Overhead and other expenses 2,841 2,250
------------ ------------
$ 9,883 $ 4,219
============ ============
Abandonment and Impairment of Unproved Properties. Abandonment and
impairment of unproved properties increased $1.7 million to $2.3 million for the
quarter ended September 30, 2003 compared to $587,000 for the same quarter of
2002. The change includes our third quarter 2003 impairment of $1.4 million
relating to the Duchesne prospect described in exploration expense above.
General and Administrative. General and administrative expenses increased
$1.1 million or 26% to $5.5 million for the three months ended September 30,
2003, compared with $4.4 million in 2002. Approximately $709,000 of the 2003
expense is accrued and relates to the mark-to-market effect of the Company's net
profits interest bonus program. The decrease in cost on a per MCFE basis
reflects the higher proportionate increase in production, 46%, than the
percentage increase in G&A this quarter.
Our employee count increased by 22% from September 30, 2002, to September
30, 2003, due largely to the Burlington and Flying J property acquisitions. This
change has resulted in a general increase in G&A of $1.0 million between the
quarters ending on those dates. That increase plus a $1.3 million increase in
compensation expense associated with our incentive compensation plans and a
$111,000 increase in charitable contributions expense were offset by a $1.4
million increase in COPAS overhead reimbursement from operations and G&A we
allocated to exploration expense. COPAS overhead reimbursement from operations
has increased as a result of an increase in the number of properties we operate
in our Rockies region due to our Burlington and Flying J acquisitions. The
increase in compensation expense associated with our incentive compensation
plans reflects both the benefit we have received from the current price
environment for past employee performance and the performance of our employees
during the current year.
Interest Expense. Interest expense increased by $723,000 to $1.8 million
for the quarter ended September 30, 2003 compared to $1.1 million for the
quarter ended September 30, 2002. This difference reflects the benefit of an
interest rate swap on our 5.75% convertible notes in the third quarter of 2002
that reduced interest expense by $393,000 in that period, the 0.5% contingent
interest provision on our convertible notes which applied for all of the 2003
period but only for 15 days in the 2002 period, and increased borrowings under
our credit facility in 2003. On October 3, 2003, we entered into fixed to
floating interest rate swaps for a total notional amount of $50,000,000 through
March 20, 2007. This date is the first date on which we are entitled to redeem
the convertible notes solely at our option for 100 percent of the principal
amount plus accrued and unpaid interest. Under the swaps, St. Mary will receive
payments at a fixed interest rate of 5.75% in exchange for making payments at a
variable interest rate of 235 basis points above the six month LIBOR rate as
determined on the semi-annual settlement date. The payment dates of the swaps
match exactly with the interest payment dates of the convertible notes. The
6-month LIBOR rate on October 3, 2003 was 1.16%.
Income Taxes. Income tax expense totaled $8.8 million for the three months
ended September 30, 2003, and $4.2 million in 2002, resulting in effective tax
rates of 38.8% and 35.4%, respectively. The effective rate change from 2002
reflects an increase in our highest marginal federal tax rate, the expiration of
the Section 29 tax credit, adjustments to valuation allowances to reflect the
likelihood that prior Alternative Minimum Tax credits created by Section 29
credits will not be used, changes in the composition of the highest marginal
-21-
state tax rates as a result of our recent acquisitions and the 2002 adjustment
to valuation allowances against state income taxes from net operating loss
carryovers.
Nine-Month Comparison
Oil and Gas Production Revenues. We experienced an increase in oil and gas
production revenues of $145.8 million, or 110% to $278.2 million for the nine
months ended September 30, 2003, compared with $132.4 million for the same
period in 2002. The following table presents the components of increases or
(decreases) between 2003 and 2002.
Production Price Price
% Change $ Change % Change
---------- -------- --------
Natural Gas 33% $2.12/Mcf 74%
Oil 63% $1.93/Bbl 8%
Following is our product mix.
Percentage of Revenue Percentage of Production
--------------------- ------------------------
Nine Months Ended September 30, 2003 2002 2003 2002
----------------------------------------------------------------------------------------
Natural Gas 67% 61% 65% 70%
Oil 33% 39% 35% 30%
Average net daily production increased 42% to 211.8 MMCFE for the first
nine months of 2003 compared with 148.8 MMCFE in 2002. Included in our 2003
production volumes are 9.9 MMcf per day and 4.4 Mbbls per day from the
Burlington and Flying J acquisitions. Wells completed in 2002 and 2003 and
properties acquired in the last two quarters of 2002 and during 2003 have added
revenue of $103.4 million and average net daily production of 71.2 MMCFE in the
first nine months of 2003 over the comparable 2002 period.
Information regarding the current effects of oil and gas hedging activity
is included in the table below, which reflects increased hedging of oil
production as a result of our Burlington and Flying J acquisitions.
Nine Months Ended September 30 2003 2002
------------------------------------------------------------------------------------------
o Percentage of oil production hedged 57% 45%
o Oil volumes hedged (MBbls) 1,898 917
o Increase (decrease) in oil revenue ($7.8 million) $2.4 million
o Average realized oil price per Bbl without hedging $29.33 $23.89
o Percentage of gas production hedged 38% 44%
o Natural gas MMBtu hedged 15.7 million 13.8 million
o Increase (decrease) in gas revenue ($11.8 million) $344,000
o Average realized gas price per Mcf without hedging $5.29 $2.85
Marketed Gas System Revenue and Gas System Operating Expense. For the nine
months ended September 30, 2003, we received $11.0 million from the sale of this
natural gas compared to $6.8 million in the same period of 2002. Operating costs
associated with these revenues totaled $10.0 million for the period ended
September 30, 2003, compared to $6.6 million for the same period in 2002. Our
gas marketing activities for third parties began in February 2002. The increase
in 2003 as compared to 2002 is a result of a full nine months of activity and
higher average natural gas prices.
-22-
Oil and Gas Production Expenses. Total production costs increased $30.4
million to $68.3 million for the nine months ended September 30, 2003, from
$38.0 million in 2002. Our acquisition of properties from Burlington and Flying
J added $18.6 million of production costs, and wells completed in 2002 and 2003
added $5.3 million of production costs in 2003 that were not reflected in 2002.
Additionally, we experienced an increase in production taxes consistent with the
increase in revenue from higher realized prices.
Total oil and gas production costs per MCFE increased $0.25 to $1.18 for
the nine months ended September 30, 2003, compared with $0.93 for 2002. This
increase is comprised of the following:
o A $0.12 increase in production taxes due to higher realized per MCFE
prices.
o A $0.03 increase due to rising transportation costs in our Rockies and
Mid-Continent regions.
o A $0.04 increase in LOE relating to one-time workover charges for projects
in our Gulf Coast, Rockies and ArkLaTex regions.
o A $0.14 increase in LOE that reflects our additions of higher cost oil
properties in our Rockies region through our acquisitions from Burlington
and Flying J.
o A $0.08 decrease reflecting general decreases in LOE per MCFE in our other
core areas.
Depreciation, Depletion, Amortization and abandonment liability accretion.
DD&A increased $22.0 million or 56% to $61.3 million for the nine months
ended September 30, 2003, from $39.2 million in 2002. DD&A per MCFE
increased by 10% to $1.06 for the nine months ended September 30, 2003 compared
with $0.96 in 2002. The increase in expense is a result of both higher
production volumes in 2003 and a higher per unit rate which reflects the cost of
acquisitions and higher finding costs associated with drilling results in 2002
and 2003.
Exploration. Exploration expense increased $5.2 million or 34% to $20.7
million for the nine months ended September 30, 2003, compared with $15.4
million in 2002. The most significant component of our increase to exploration
expense was $6.4 million for the unsuccessful exploratory Duchesne prospect.
This amount does not include the $1.4 million impairment of the associated
nonproducing leasehold costs discussed below. The drilling results did not
confirm the geologic exploration model used to evaluate the Duchesne prospect,
and the well produced at below commercial rates. Also in 2003 we have increased
exploration overhead due to increases in our geologic and exploration staff as a
result of the acreage we have acquired in the Williston, Green River and Powder
River basins. Components of total exploration expense are as follows (in
millions).
Nine Months Ended
September 30,
--------------------------
2003 2002
------------ ------------
o Geological and geophysical expenses $ 4.4 $ 2.1
o Exploratory dry holes 7.5 7.3
o Overhead and other expenses 8.8 6.0
------------ ------------
$ 20.7 $ 15.4
============ ============
Abandonment and Impairment of Unproved Properties. Abandonment and
impairment of unproved properties increased $2.1 million or 110% to $4.0 million
for the period ended September 30, 2003 compared to $1.9 million for the same
quarter of 2002. The change reflects our third quarter 2003 impairment of $1.4
million relating to the Duchesne prospect described in exploration expense
above.
General and Administrative. General and administrative expenses increased
$7.2 million or 68% to $17.7 million for the nine months ended September 30,
2003, compared with $10.5 million in 2002. Approximately $2.4 million of the
2003 expense is non-cash and relates to the mark-to-market effect of St. Mary's
-23-
net profits interest bonus plan. The increase in cost on a per MCFE basis
reflects a higher percentage increase in G&A, primarily due to an increase
in our compensation expense, than the proportionate increase in production of
42% for the nine month period.
The increase in our employee count has resulted in a general increase in
G&A of $3.8 million between the nine-month periods ended on September 30,
2003 and September 30, 2002. That increase plus a $7.3 million increase in
expense associated with our incentive compensation plans, a $776,000 increase in
accrued charitable contributions expense and a $365,000 increase in insurance
and corporate governance costs were offset by a $5.3 million increase in COPAS
overhead reimbursement from operations and G&A we allocated to exploration
expense. COPAS overhead reimbursement from operations has increased due to an
increase in the number of properties we operate in our Rockies region as a
result of our Burlington and Flying J acquisitions. The increase in expense
associated with our incentive compensation plans reflects both the benefit we
have received from the current price environment for past employee performance
and the performance of our employees during the current year.
Interest Expense. Interest expense increased by $3.8 million to $6.4
million for the nine months ended September 30, 2003 compared to $2.6 million
for the period ended September 30, 2002. The increase reflects a full nine
months of accrued interest in 2003 on our 5.75% convertible notes that were
issued in March 2002, the benefit of an interest rate swap on those notes that
reduced interest expense in 2002 by $839,000, the 0.5% contingent interest
provision on the notes which applied in all of 2003 but for only 15 days during
the comparable period in 2002, and increased borrowings under our credit
facility in 2003 relative to the prior years. We anticipate that interest
expense for 2003 will be higher than the 2002 amount due to the termination of
the interest rate swap in December 2002 and since we have increased borrowings
under our credit facility in 2003. However, unless we access our credit facility
to make an acquisition or interest rates increase dramatically, interest expense
next year should decrease due to the fixed to floating interest rate swaps we
entered into on October 3, 2003.
Income Taxes. Income tax expense totaled $41.5 million for the nine months
ended September 30, 2003, and $10.6 million in 2002, resulting in effective tax
rates of 38.8% and 34.0%, respectively. The effective rate change from 2002
reflects an increase in our highest marginal federal tax rate, the expiration of
the Section 29 tax credit, adjustments to valuation allowances to reflect the
likelihood that prior Alternative Minimum Tax credits created by Section 29
credits will not be used, changes in the composition of the highest marginal
state tax rates as a result of our recent acquisitions and the 2002 adjustment
to valuation allowances against state income taxes from net operating loss
carryovers.
The current portion of the income tax expense in 2003 is $25.9 million
compared to $502,000 in 2002. These amounts are 62% and 5% of the total tax
for the respective periods. The difference results from increased taxable income
caused by significantly higher oil and gas prices and production, and a
reduction in the percentage of deductible intangible drilling costs relative to
total income.
Cumulative Effect of Change in Accounting Principle, net. On January 1,
2003, we adopted SFAS No. 143. The impact of adoption resulted in income to us
of $8.8 million offset by the deferred income tax effect of $3.4 million. See
Note 8 of the Notes to Consolidated Financial Statements under Part I, Item 1 of
this report.
Liquidity and Capital Resources
Our primary sources of liquidity are the cash provided by operating
activities, debt financing, sales of non-strategic properties and access to the
capital markets. All of these sources can be impacted by significant
fluctuations in oil and gas prices and the availability of financing to oil and
gas producers in the market. An unexpected decrease in oil and gas prices would
reduce expected cash flow from operating activities, might reduce the borrowing
base on our credit facility, could reduce the value of our properties and
historically has limited our industry's access to the capital markets.
-24-
We use cash for the acquisition, exploration and development of oil and gas
properties and for the payment of debt obligations, trade payables and
stockholder dividends. Exploration and development programs are generally
financed from internally generated cash flow, debt financing and cash and cash
equivalents on hand. Cash use for the acquisition of oil and gas properties and
the payment of stockholder dividends is discretionary and can be reduced or
eliminated in the event of an unexpected decrease in oil and gas prices. At any
given point in time we may be obligated to pay for commitments to explore for or
develop oil and gas properties or incur trade payables. However, certain future
obligations can be reduced or eliminated when necessary. We are currently only
required to make interest payments on our debt obligations, although we have
voluntarily been reducing our outstanding borrowings under our revolving credit
facility. As of November 5, 2003, the outstanding balance under the revolving
credit facility was $5.0 million, representing an $8.0 million reduction from
the $13.0 million outstanding balance at September 30, 2003. An unexpected
increase in oil and gas prices would provide increased flexibility to modify our
uses of cash flow. This year we have reduced our outstanding debt, paid $81.3
million for property acquisitions and spent $104.6 million on capital
development using cash flows from operations. We have also used $23.2 million of
cash to make income tax payments during 2003.
We continually review our capital expenditure budget to reflect changes in
current and projected cash flow, drilling and acquisition opportunities, debt
requirements and other factors.
Cash Flow. Net cash provided by operating activities increased $44.8
million or 42% to $150.9 million for the nine months ended September 30, 2003
compared with $106.2 million in 2002. Our $50.3 million increase in net income
between the two periods combined with a $32.0 million increase in the effect of
non-cash items were offset by a $37.6 million change in current assets and
liabilities relating to increased accounts receivable and income tax payments in
2003 offset by decreased prepaid expenses, increased accounts payable, and
collections of refundable income taxes in 2002. We anticipate increased
comparative cash flow from operations in 2003 as a result of higher oil and gas
prices in 2003 and increased production attributable to our property
acquisitions and drilling activities in late 2002 and early 2003.
Net cash used in investing activities increased $59.8 million or 64% to
$153.6 million for the nine months ended September 30, 2003, compared with net
cash used of $93.9 million in 2002. This increase results from additional
capital expenditures and acquisition costs. Total capital expenditures,
including acquisitions of oil and gas properties, in the first nine months of
2003 increased $69.8 million or 80% to $156.5 million compared with $86.7
million in the first nine months of 2002. This increase reflects the utilization
of $71.6 million in short term investments, cash equivalents and increased
borrowings under our credit facility to provide a loan to Flying J as part of
our acquisition of properties from Flying J in January 2003. This loan is
secured by the shares of our common stock issued in the transaction.
Net cash used in financing activities was $1.3 million for the nine months
ended September 30, 2003, compared with net cash provided by financing
activities of $32.7 million in 2002. This decrease reflects the 2002 issuance of
our 5.75% convertible notes and the use of proceeds to pay down our credit
facility, partially offset by additional borrowing on our credit facility to
fund our 2003 acquisitions.
St. Mary had $7.1 million in cash and cash equivalents and had negative
working capital of $7.3 million as of September 30, 2003, compared with $11.2
million in cash and cash equivalents and positive working capital of $2.1
million at December 31, 2002. The negative working capital was a function of
accelerated principal repayments of the credit facility, a short term increase
in accounts payables and the payment of estimated income taxes in September. Had
we wanted to incur additional borrowings to increase our current assets, we
could have elected to borrow under our credit facility an amount necessary to
ensure a net working capital position. Providing commodity pricing remains
relatively consistent with current levels through the fourth quarter, we expect
that working capital will be positive at December 31, 2003, and the remaining
$5.0 million outstanding under the credit facility will be completely repaid.
-25-
Senior Convertible Notes. In March 2002 we issued in a private placement a
total of $100.0 million of 5.75% senior convertible notes due 2022 with a 0.5
percent contingent interest provision. Interest payments are due on March 15 and
September 15 of every year. We received net proceeds of $96.8 million after
deducting the initial purchasers' discount and offering expenses payable by us.
The notes are general unsecured obligations and rank on a parity in right of
payment with all our existing and future senior indebtedness and other general
unsecured obligations, and are senior in right of payment with all our future
subordinated indebtedness. The notes are convertible into our common stock at a
conversion price of $26.00 per share, subject to adjustment. We can redeem the
notes with cash in whole or in part at a repurchase price of 100% of the
principal amount plus accrued and unpaid interest including contingent interest
beginning on March 20, 2007. The note holders have the option of requiring us to
repurchase the notes for cash at 100% of the principal amount plus accrued and
unpaid interest including contingent interest upon (1) a change in control of
St. Mary or (2) on March 20, 2007, March 15, 2012 and March 15, 2017. If the
note holders request repurchase on March 20, 2007, we may pay the repurchase
price with cash, shares of our common stock valued at a discount to the market
price at the time of repurchase or any combination of cash and our discounted
common stock. We are not restricted from paying dividends, incurring debt, or
issuing or repurchasing our securities under the indenture for the notes. There
are no financial covenants in the indenture. We used a portion of the net
proceeds from the notes to repay our credit facility balance and used the
remaining net proceeds to fund a portion of our 2002 capital expenditures. On
March 25, 2002, we entered into a five-year fixed-rate to floating-rate interest
rate swap on a notional amount of $50.0 million of the notes. The floating rate
was determined as LIBOR plus 0.36%. We elected to terminate this swap on
December 3, 2002, and received proceeds of $4.0 million. On October 3, 2003 we
executed new interest rate swaps on a notional amount of $50.0 million of the
notes which we expect will serve to lower interest expense in the fourth quarter
of 2003.
Credit Facility. On January 29, 2003, we entered into a new $300.0 million
credit facility with Wachovia Bank as Administrative Agent and eight other
participating banks. This new credit facility replaced our previous credit
facility and has a maturity date of January 27, 2006. The calculated borrowing
base was determined by the bank group to be $275.0 million on October 28, 2003.
We have elected a commitment amount of $150.0 million under this facility, which
results in lower commitment fees payable to the bank syndicate. We believe this
commitment level is adequate for our near-term liquidity needs. We are required
to comply with certain financial and non-financial covenants, and we are
currently in compliance with all covenants under the credit facility. Interest
and commitment fees are accrued based on the borrowing base utilization
percentage table below. Eurodollar loans accrue interest at LIBOR plus the
applicable margin from the utilization table, and Alternative Base Rate (ABR)
loans accrue interest at prime plus the applicable margin from the utilization
table. Commitment fees are accrued on the unused portion of the aggregate
commitment amount and are included in interest expense in the consolidated
statements of operations.
Borrowing base
utilization percentage <50% =>50%<75% =>75%<90% >90%
---------------------------------------------------------------------------
Eurodollar Loans 1.25% 1.50% 1.75% 2.00%
ABR Loans 0.00% 0.25% 0.50% 0.75%
Commitment Fee Rate 0.30% 0.38% 0.38% 0.50%
Our loan balance of $13.0 million at September 30, 2003 was comprised of
LIBOR based traunches. Our weighted average interest rates paid for the third
quarter of 2003 and for the nine months ended September 30, 2003 were 7.0% and
6.1%, respectively, including commitment fees paid on the unused portion of the
credit facility borrowing base, amortization of deferred financing costs, and
amortization of the contingent interest embedded derivative with respect to the
convertible notes.
-26-
Schedule of Contractual Obligations. The following table summarizes our
future estimated principal payments for the periods specified (in millions).
Long-Term Operating Total Cash
Contractual Obligations Debt Leases Obligation
- ------------------------- --------------- -------------- ---------------
Less than 1 year $ - $ 2.1 $ 2.1
1-3 years 13.0 2.8 15.8
4-5 years - 2.0 2.0
After 5 years 100.0 3.1 103.1
--------------- -------------- ---------------
Total $ 113.0 $ 10.0 $ 123.0
=============== ============== ===============
In the period from 1-3 years, we have one lease of office space for our
regional offices that will expire. An additional two leases for office space
will expire in year 4. Estimated costs to replace these leases are not included
in the table above. For purposes of the table we assume that the holders of our
5.75% convertible notes will not exercise the conversion or redemption features
until final maturity.
Common Stock. On January 29, 2003, we issued a total of 3,380,818
restricted shares of our common stock to Flying J Oil & Gas Inc. and Big
West Oil & Gas Inc. for the acquisition of oil and gas properties, and we
made a non-recourse loan to Flying J in the amount of $71.6 million at LIBOR
plus 2% for up to a 39-month period. We also entered into a put and call option
agreement with Flying J whereby during the 39-month loan period Flying J can
elect to put these shares to St. Mary for $71.6 million plus accrued interest on
the loan during the first thirty months of the loan period, and we can elect to
call the shares for $97.4 million, with the proceeds from the exercise of either
the put option or the call option to be applied to repayment of the loan. The
net option with respect to Flying J's net contractual rights to obtain
additional value from any appreciation of the shares over the put amount up to
the call amount has been valued at $1.0 million for accounting purposes. Final
valuation determinations were made in the third quarter of 2003. For accounting
purposes the above arrangements have been treated as an acquisition of
properties in exchange for $71.6 million of cash plus the net option to Flying J
valued at $1.0 million, resulting in a total valuation of $72.6 million.
Operating results from the acquired properties have been included in the
consolidated statements of operations only from the date of closing. The
restricted shares issued are subject to contractual restrictions on transfer for
a period of two years, and Flying J cannot increase their ownership percentage
in St. Mary for a period of 30 months. For accounting purposes the net option is
reflected in the equity section of our consolidated balance sheets as additional
paid-in capital. The stock and the loan are reflected in the temporary equity
section of our consolidated balance sheets. See Note 9 of the Notes to
Consolidated Financial Statements under Part I, Item 1 of this report.
Capital and Exploration Expenditures Incurred. Expenditures for exploration
and development of oil and gas properties and acquisitions are the primary use
of our capital resources. The following table sets forth certain information
regarding the costs incurred by us in our oil and gas activities during the
periods indicated. These expenditures include the value of the stock and other
consideration issued in the Flying J transaction.
-27-
Nine Months Ended September
September 30,
-------------------------------
2003 2002
--------------- ---------------
(In thousands)
Development $ 78,155 $ 52,584
Exploration 26,416 12,704
Acquisitions:
Proved 75,844 7,886
Unproved 5,476 10,582
--------------- ---------------
Total $ 185,891 $ 83,756
=============== ===============
We continuously evaluate opportunities in the marketplace for oil and gas
properties and, accordingly, may be a buyer or a seller of properties at various
times. We will continue to emphasize acquisitions in our core areas utilizing
St. Mary's technical expertise, financial flexibility and structuring
experience. In addition, we are also actively seeking larger acquisitions of
assets or companies that would afford opportunities to expand our existing core
areas, to acquire additional geoscientists or to gain a significant acreage and
production foothold in a new basin.
St. Mary's total costs incurred in the first nine months of 2003 increased
$102.1 million or 122% compared to the first nine months of 2002. We spent
$110.0 million in the first nine months of 2003 for unproved property
acquisitions and domestic exploration and development compared to $75.9 million
for the comparable period in 2002.
We continue to evaluate the results of our two coalbed methane pilot
programs located in the Hanging Woman Basin. On April 30, 2003, the Bureau of
Land Management issued its record of decision approving the two environmental
impact statements that considered coalbed methane development in northeast
Wyoming and southeast Montana, and the BLM is now issuing drilling permits on
federal acreage in Wyoming. We hope the two environmental impact statements will
also open the door for new coalbed methane development on federal acreage in
this area of Montana. Immediately after the decision was issued several
environmental groups filed multiple challenges. These challenges and a
previously reported environmental public interest group lawsuit by the Northern
Plains Resource Council, Inc. affect 89,700 gross acres related to this project.
See Legal Proceedings under Part II, Item 1 of this report.
Capital Expenditure Budget. We anticipate spending approximately $235
million for capital and exploration expenditures in 2003 with $92 million
allocated for acquisitions, which includes the $72.6 million acquisition of
properties from Flying J in January 2003. Budgeted ongoing exploration and
development expenditures in 2003 for each of our core areas is as follows (in
millions).
o Mid-Continent region $ 62
o Rockies region 27
o ArkLaTex region 26
o Gulf Coast and Gulf of Mexico region 16
o Permian Basin 8
o Other 4
-------
Total $ 143
=======
-28-
We believe the amount not funded from our internally generated cash flow in
2003 can be funded from our existing cash and our credit facility. The amount
and allocation of future capital and exploration expenditures will depend upon a
number of factors including the number and size of available acquisition
opportunities and our ability to assimilate these acquisitions. Also, the impact
of oil and gas prices on investment opportunities, the availability of capital
and borrowing capability, and the success of our development and exploratory
activity could lead to funding requirements for further development. If
additional development or attractive acquisition opportunities arise, we may
consider other forms of financing, including the public offering or private
placement of equity or debt securities.
Sale of Investment. Subsequent to September 30, 2003, we received $1.5
million from the sale of our investment in Constellation Copper Corporation.
Derivatives. We seek to protect our rate of return on acquisitions of
producing properties by hedging cash flow when the economic criteria from our
evaluation and pricing model indicate it would be appropriate. Management's
strategy is generally to hedge cash flows from acquisitions for up to 24 months
in order to meet minimum rate-of-return criteria. Management reviews these
hedging parameters on a quarterly basis. We may periodically hedge additional
production when we view the price environment to be favorable for hedging. We
generally limit our aggregate hedge position to no more than 50% of total
production but will hedge larger percentages of total production in certain
circumstances. We seek to minimize basis risk and index the majority of oil
hedges to NYMEX prices and the majority of gas hedges to various regional index
prices associated with pipelines in proximity to our areas of gas production.
Our policy requires that we diversify our hedge positions with various
counterparties and requires that such counterparties have clear indications of
financial strength. Including hedges entered into since September 30, 2003 we
have the following swaps and collars in place:
Swaps
-----
Average Quantity Average Fixed
Product Volumes/month Type Contract Price Duration
---------------------------------------------------------------------------------------
Natural Gas 1,845,000 MMBtu $4.49 10/03 - 12/03
Natural Gas 869,000 MMBtu $4.08 01/04 - 12/04
Oil 191,800 Bbls $25.20 10/03 - 12/03
Oil 144,500 Bbls $23.71 01/04 - 12/04
Collars
-------
Average Floor Ceiling
Product Volumes/month Price Price Duration
---------------------------------------------------------------------------------------
Natural Gas 152,000 MMbtu $2.50 $5.93 10/03 - 12/03
Other Derivatives. Our 5.75% convertible notes contain a provision for the
payment of contingent interest if certain conditions are met. Under SFAS No. 133
this provision is considered an embedded equity-related derivative that is not
clearly and closely related to the fair value of an equity interest and
therefore must be separated and accounted for as a derivative instrument. The
value of the derivative at issuance in March 2002 was $474,000. This amount was
recorded as a decrease to the 5.75% convertible notes payable in the
consolidated balance sheets. Of this amount, $71,000 has been amortized through
interest expense in 2003. Derivative income in the consolidated statements of
operations includes $247,000 of net income from mark-to-market adjustments for
this derivative at September 30, 2003, compared to a net loss of $239,000
included in derivative loss at September 30, 2002.
-29-
Critical Accounting Policies and Estimates
We refer you to the corresponding section of our Annual Report on Form 10-K
for the year ended December 31, 2002.
Accounting Matters
New Accounting Standards
In May 2003 the Financial Accounting Standards Board issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This Statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity and requires that such financial instruments be
classified as a liability (or as an asset in certain circumstances). SFAS No.
150 is effective for all freestanding instruments entered into or modified after
May 31, 2003. Otherwise, it became effective for us as of July 1, 2003. We
currently have no financial instruments that fall within the scope of this
statement.
In December 2002 the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure: an amendment of FASB Statement No.
123." This statement provided for transition methods for adopting the fair value
accounting model of accounting for the issuance of stock options. The statement
provides for three alternative adoption methods: (1) The retroactive method -
where all prior periods are restated to reflect the expensing of all options
granted on a retroactive basis, (2) The modified-prospective method-where a
company begins expensing all prior and current option grants in the current
year, and (3) The prospective method-where a company begins expensing all
current period option grants in the current year. We are continuing to evaluate
these adoption alternatives and current FASB discussions as well as considering
the issuance of restricted stock for its equity component of employee
compensation.
Effective January 1, 2003, we adopted the provisions of SFAS No. 143,
"Accounting for Asset Retirement Obligations." Upon adoption of SFAS No. 143, we
recorded a discounted liability of $21.4 million, reversed the existing offshore
abandonment liability of $9.1 million, increased net property and equipment by
$21.1 million and recognized a one-time cumulative effect gain of $5.4 million
(net of deferred tax benefit of $3.4 million). We will deplete the amount added
to property and equipment and recognize accretion expense in connection with the
discounted liability over the remaining economic lives of the respective oil and
gas properties. Prior to the adoption of SFAS No. 143, we assumed that salvage
value approximated abandonment costs and therefore salvage value was not
reflected in the DD&A calculation. As a result of adopting SFAS No. 143 and
the discounting of the asset retirement obligation, the salvage value must now
be reflected in the DD&A rate. Accordingly, $13.7 million was reversed from
accumulated DD&A and is included as a part of the increase in net property
and equipment in the cumulative effect adjustment. This adjustment to
accumulated DD&A relates to prior depletion of salvage value that would have
been excluded from the DD&A calculation if the abandonment liability had
been separately recognized. As of September 30, 2003, our capitalized proved oil
and gas properties included $44.0 million of estimated salvage value which is
not included in our DD&A calculation.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 addresses
accounting and reporting for business combinations and is effective for all
business combinations initiated after June 30, 2001. SFAS No. 142 addresses the
accounting and reporting for goodwill subsequent to acquisition and other
intangible assets. The new standard eliminates the requirement to amortize
acquired goodwill; instead, such goodwill is required to be reviewed at least
annually for impairment. The new standard also requires that, at a minimum, all
-30-
intangible assets be aggregated and presented as a separate line item in the
balance sheet. The adoption of SFAS No. 141 and SFAS No. 142 had no impact on
our financial position or results of operations.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
requires companies to classify the costs of mineral rights held under lease or
other contractual arrangements associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically, we have
included the costs of such mineral rights associated with extracting oil and gas
as a component of oil and gas properties. If it is ultimately determined that
SFAS No. 142 requires oil and gas companies to classify costs of mineral rights
held under lease or other contractual arrangements associated with extracting
oil and gas as a separate intangible assets line item on the balance sheet, we
will reclassify these amounts out of oil and gas properties and into a separate
intangible assets line item. Our cash flows and results of operations would not
be affected since such intangible assets would continue to be depleted and
assessed for impairment. Further, we do not believe the classification of the
costs of mineral rights associated with extracting oil and gas as intangible
assets would have any impact on compliance with covenants under its debt
agreements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We hold derivative contracts and financial instruments that have cash flow
and net income exposure to changes in commodity prices or interest rates.
Financial and commodity based derivative contracts are used to limit the risks
inherent in some crude oil and natural gas price changes that have an effect on
us.
Our board of directors has adopted a policy regarding the use of derivative
instruments. This policy requires every derivative used by St. Mary to relate to
underlying offsetting positions, anticipated transactions or firm commitments.
It prohibits the use of speculative, highly complex or leveraged derivatives.
Under the policy, the Chief Executive Officer and Vice President - Finance must
review and approve all risk management programs that use derivatives. The board
of directors periodically reviews these programs.
Commodity Price Risk. We use various hedging arrangements to manage our
exposure to price risk from natural gas and crude oil production. These hedging
arrangements have the effect of locking in for specified periods, at
predetermined prices or ranges of prices, the prices we will receive for the
volumes to which the hedge relates. Consequently, while these hedging
arrangements are structured to reduce our exposure to decreases in prices
associated with the hedged commodity, they also limit the benefit we might
otherwise receive from any price increases associated with the hedged commodity.
The derivative gain or loss effectively offsets the loss or gain on the
underlying commodity exposures that have been hedged. The fair value of the
swaps are estimated based on quoted market prices of comparable contracts and
approximate the net gains or losses that would have been realized if the
contracts had been closed out at quarter-end. The fair value of the futures are
based on quoted market prices obtained from the New York Mercantile Exchange and
have been adjusted for our hedging of the basis differential accorded to the
pipelines relative to our areas of 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 16.4 million
MMBtu would cause a potential $1.3 million change in net income before income
taxes over the remaining life of the contracts in place on September 30, 2003
and a potential $354,000 change for the last three months of 2003. A
hypothetical $1.00 per Bbl change in our quarter-end market prices for crude oil
swaps and future contracts on a notional amount of 2.3 million Bbls would cause
a potential $2.0 million change in net income before income taxes over the
remaining life of the contracts in place on September 30, 2003 and a potential
$370,000 change for the last three months of 2003. These hypothetical changes
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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, 2003, which are sensitive to changes in interest rates.
For fixed-rate debt, interest rate changes affect the fair market value but do
not impact results of operations or cash flows. Conversely for floating rate
debt, interest rate changes generally do not affect the fair market value but do
impact future results of operations and cash flows assuming other factors are
held constant. The carrying amount of our floating rate debt approximates its
fair value. At September 30, 2003, we had floating rate debt of $13.0 million
under our revolving credit facility and $100.0 million of fixed rate debt under
the 5.75% Senior Convertible Notes, which provide for the payment of contingent
interest of up to an additional 0.5% during six-month interest periods under
certain circumstances. Assuming constant debt levels with respect to the debt
instruments in effect as of September 30, 2003, 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 $32,500
before taxes.
On October 3, 2003, St. Mary entered into fixed to floating interest rate
swaps on a notional amount of $50 million, which represents 50% of the
outstanding principal amount of our 5.75% Senior Convertible Notes. Under the
swaps, St. Mary will receive payments at a fixed interest rate of 5.75% in
exchange for making payments at a variable interest rate of 235 basis points
plus the 6-month LIBOR rate. The 6-month LIBOR rate on October 3, 2003 was
1.16%. The swaps expire during March 2007, on the first date that St. Mary is
entitled to redeem the notes at its option.
ITEM 4. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are
designed for the purposes of ensuring that information required to be disclosed
in our SEC reports is recorded, processed, summarized and reported within the
time periods specified in the SEC's rules and forms, and that such information
is accumulated and communicated to our management, including the Chief Executive
Officer and the Vice-President - Finance, as appropriate to allow timely
decisions regarding required disclosure.
We carried out an evaluation, under the supervision and with the
participation of our management, including the Chief Executive Officer and the
Vice-President - Finance, of the effectiveness of the design and operation of
our disclosure controls and procedures as of the end of the period covered by
this Quarterly Report on Form 10-Q. Based upon that evaluation, the Chief
Executive Officer and the Vice-President - Finance concluded that our disclosure
controls and procedures are effective for the purposes discussed above as of the
end of the period covered by this Quarterly Report on Form 10-Q. There was no
significant change in our internal control over financial reporting that
occurred during our most recent fiscal quarter that has materially affected, or
is reasonably likely to materially affect, our internal control over financial
reporting.
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
-----------------
The previously reported legal proceeding involving Nance Petroleum
Corporation and the Northern Plains Resource Council, Inc. ("NPRC") in the U.S.
District Court for the District of Montana had no significant developments
during the quarterly period ended September 30, 2003. Both the Plaintiff, NPRC,
and the Defendants have filed motions for summary judgment. The Magistrate
assigned to this case has recommended that the Plaintiff's motion be denied and
the Defendants' motion be granted. If the presiding judge accepts these
recommendations, the case will be dismissed with a judgment rendered in favor of
the majority of the Defendants including Nance Petroleum Corporation. For a
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description of this proceeding, please see the "Legal Proceedings" section of
St. Mary's Annual Report on Form 10-K for the year ended December 31, 2002.
As previously reported in St. Mary's Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 2003, the Company received a copy of an
Administrative Order (the "Order") by the U.S. Environmental Protection Agency
(Docket No. CWA-06-2003-1995) on August 4, 2003, related to certain oil and gas
properties in the Gulf of Mexico that are or were owned, operated or leased by
St. Mary Energy Company. Interests in these properties were acquired by the
Company through its acquisition of St. Mary Energy Company, formerly named King
Ranch Energy, Inc., on December 17, 1999. The Order alleges violations of the
Clean Water Act through certain violations of EPA reporting rules with respect
to such properties under applicable EPA permits during reporting monitoring
periods from July 1, 1998 to December 31, 1999. Based on our internal review,
the Company believes that any reporting discrepancies were inadvertent and did
not involve any improper discharge of pollutants into the environment, and the
Company has fully cooperated with the EPA to appropriately correct and remedy
any reporting discrepancies. The reports in question have been corrected as
necessary and were refilled during the course of the Show Cause Hearing held on
September 30, 2003, at the Region VI office of EPA. We believe all issues raised
in the Order were fully addressed. No final decision has been rendered by the
Hearing Officer regarding matters raised by the Order. The Company cannot
predict whether any monetary or other penalties will be imposed. However, the
Company does not currently expect that such penalties, if any, will have a
material effect on the Company's financial condition, results of operations or
cash flows.
ITEM 5. Other Information
In July 2003 St. Mary's audit committee authorized in advance up to $20,000
of certain non-audit services to be performed by Deloitte & Touche LLP, the
Company's independant auditor. These services are limited to consultation
regarding a state private revenue letter ruling.
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ITEM 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits
The following exhibits are furnished as part of this report:
Exhibit Description
------- -----------
31.1* Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes - Oxley Act of 2002
31.2* Certification of Vice President - Finance pursuant to
Section 302 of the Sarbanes - Oxley Act of 2002
32.1* Certification pursuant to U.S.C. Section 1350 as
adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002
--------------------------
* Filed with this Form 10-Q.
(b) Reports on Form 8-K
St. Mary Land & Exploration Company filed the following
current reports on Form 8-K during the quarter ended September 30,
2003:
o On July 16, 2003, we filed a current report on Form 8-K
reporting under Item 9 pursuant to Item 12 that we had
issued a press release announcing an update of our
operations for the second quarter of 2003.
o On August 1, 2003, we filed a current report on Form 8-K
reporting under Item 5 that we had issued a press release on
July 25, 2003 announcing the retirement of Ronald D. Boone
as an officer and employee and a press release on July 28,
2003 providing a status update on the testing of various
zones in our Duchesne Deep Prospect.
o On August 7, 2003, we filed a current report on Form 8-K
reporting under Item 12 that we had issued a press release
announcing our second quarter 2003 financial results and an
updated forecast for our third quarter and full year of 2003.
o On September 4, 2003, we filed a current report on Form 8-K
reporting under Item 5 that we issued a press release
announcing that drilling of our exploratory well in our
Duchesne Deep Prospect was unsuccessful.
o On September 16, 2003, we filed a current report on Form 8-K
reporting under Item 5 that we issued a press release
announcing the accrual of contingent interest on our 5.75%
senior convertible notes.
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SIGNATURES
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
November 5, 2003 By: /s/ MARK A. HELLERSTEIN
-------------------------------------
Mark A. Hellerstein
President and Chief Executive Officer
November 5, 2003 By: /s/ DAVID W. HONEYFIELD
-------------------------------------
David W. Honeyfield
Vice President - Finance, Secretary
and Treasurer
November 5, 2003 By: /s/ GARRY A. WILKENING
-------------------------------------
Garry A. Wilkening
Vice President - Administration and
Controller