================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
------------
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 by Rule 12b-2 of the Exchange Act). Yes [ x ] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date.
As of April 22, 2005, the registrant had 57,239,058 shares of common stock,
$0.01 par value, outstanding.
================================================================================
ST. MARY LAND & EXPLORATION COMPANY
---------------------------------------
INDEX
-----
Part I. FINANCIAL INFORMATION PAGE
----
Item 1. Financial Statements (Unaudited)
Consolidated Balance
Sheets - March 31, 2005 and
December 31, 2004..............................................3
Consolidated Statements of
Operations - Three Months Ended
March 31, 2005 and 2004........................................4
Consolidated Statements of
Stockholders' Equity and
Comprehensive Income - March 31, 2005
and December 31, 2004..........................................5
Consolidated Statements of
Cash Flows - Three Months Ended
March 31, 2005 and 2004........................................6
Notes to Consolidated Financial
Statements - March 31, 2005....................................8
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations.................................................20
Item 3. Quantitative and Qualitative Disclosures
About Market Risk (included within
the content of Item 2)........................................34
Item 4. Controls and Procedures.......................................34
Part II.OTHER INFORMATION
Item 1. Legal Proceedings.............................................34
Item 6. Exhibits......................................................35
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND
SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(In thousands, except share amounts)
March 31, December 31,
------------- -------------
ASSETS 2005 2004
------------- -------------
Current assets:
Cash and cash equivalents $ 17,520 $ 6,418
Short-term investments 1,500 1,412
Accounts receivable 96,669 104,964
Prepaid expenses and other 7,466 5,863
Deferred income taxes 7,615 -
Accrued derivative asset 127 8,270
------------- -------------
Total current assets 130,897 126,927
------------- -------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 1,211,911 1,124,810
Less - accumulated depletion, depreciation and amortization (415,805) (399,013)
Unproved oil and gas properties, net of impairment allowance
of $8,873 in 2005 and $9,867 in 2004 44,961 41,969
Wells in progress 36,348 35,515
Other property and equipment, net of accumulated depreciation
of $6,803 in 2005 and $6,459 in 2004 5,167 5,244
------------- -------------
882,582 808,525
------------- -------------
Noncurrent assets:
Goodwill 9,612 -
Other noncurrent assets 5,544 10,008
------------- -------------
Total noncurrent assets 15,156 10,008
------------- -------------
------------- -------------
Total Assets $ 1,028,635 $ 945,460
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 110,415 $ 110,117
Accrued derivative liability 21,330 2,502
Deferred income taxes 111 2,273
------------- -------------
Total current liabilities 131,856 114,892
------------- -------------
Noncurrent liabilities:
Long-term credit facility 47,000 37,000
Convertible notes 99,814 99,791
Asset retirement obligation 43,462 40,911
Net Profits Plan liability 34,782 30,561
Deferred income taxes 153,724 129,830
Other noncurrent liabilities 17,707 8,020
------------- -------------
Total noncurrent liabilities 396,489 346,113
------------- -------------
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares;
issued: 57,732,758 shares in 2005 and 57,458,246 shares in 2004;
outstanding, net of treasury shares: 57,232,758 shares in 2005
and 56,958,246 shares in 2004 577 574
Additional paid-in capital 135,963 127,374
Treasury stock, at cost: 500,000 shares in 2005 and 2004 (5,295) (5,295)
Deferred stock-based compensation (8,088) (5,039)
Retained earnings 396,808 364,567
Accumulated other comprehensive income (loss) (19,675) 2,274
------------- -------------
Total stockholders' equity 500,290 484,455
------------- -------------
Total Liabilities and Stockholders' Equity $ 1,028,635 $ 945,460
============= =============
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
March 31,
-------------------------------
2005 2004
------------ ------------
Operating revenues:
Oil and gas production revenue $ 138,370 $ 101,206
Oil and gas hedge gain (loss) 1,560 (8,599)
Marketed gas revenue 3,396 3,573
Gain on sale of proved properties - 195
Other revenue 492 107
------------ ------------
Total operating revenues 143,818 96,482
------------ ------------
Operating expenses:
Oil and gas production expense 32,159 23,543
Depletion, depreciation, amortization
and abandonment liability accretion 30,074 20,626
Exploration 7,083 4,631
Abandonment and impairment of unproved properties 1,870 922
General and administrative 5,986 5,577
Change in Net Profits Plan liability 4,221 2,160
Marketed gas operating expense 3,125 3,411
Derivative loss (gain) 1,129 (852)
Other expense 514 585
------------ ------------
Total operating expenses 86,161 60,603
------------ ------------
Income from operations 57,657 35,879
Nonoperating income (expense):
Interest income 82 144
Interest expense (1,944) (1,488)
------------ ------------
Income before income taxes 55,795 34,535
Income tax expense (20,692) (13,086)
------------ ------------
Net Income $ 35,103 $ 21,449
============ ============
Basic weighted-average common shares outstanding 57,231 59,549
============ ============
Diluted weighted-average common shares outstanding 67,047 68,383
============ ============
Basic net income per common share $ 0.61 $ 0.36
============ ============
Diluted net income per common share $ 0.54 $ 0.33
============ ============
The accompanying notes are an integral part
of these consolidated financial statements.
-4-
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 Deferred Other Total
------------------- Paid-in ------------------- Stock-Based Retained Comprehensive Stockholders'
Shares Amount Capital Shares Amount Compensation Earnings Income (Loss) Equity
----------- ------- ---------- --------- -------- ------------ -------- -------------- -------------
Balances, December 31, 2003 58,490,246 $ 584 $146,070 (2,005,400) $(16,057) $ - $274,937 $ (14,881) $ 390,653
Comprehensive income,
net of tax:
Net income - - - - - - 92,479 - 92,479
Change in derivative
instrument fair value - - - - - - - (14,795) (14,795)
Reclassification to earnings - - - - - - - 31,849 31,849
Minimum pension liability
adjustment - - - - - - - 101 101
-------------
Total comprehensive income 109,634
-------------
Cash dividends declared,
$ 0.05 per share - - - - - - (2,849) - (2,849)
Repurchase of common stock
from Flying J - - (19,406) - - - - - (19,406)
Treasury stock purchases - - - (978,600) (16,336) - - - (16,336)
Retirement of treasury stock (2,458,800) (24) (26,725) 2,458,800 26,749 - - - -
Issuance of common stock
under Employee Stock
Purchase Plan 27,748 - 375 - - - - - 375
Sale of common stock,
including income tax
benefit of stock
option exercises 1,399,052 14 17,832 - - - - - 17,846
Deferred compensation related
to issued restricted stock
unit awards, net
of forfeitures - - 8,122 - - (8,122) - - -
Accrued stock-based
compensation - - 1,106 - - - - - 1,106
Amortization of deferred
stock-based compensation - - - - - 3,083 - - 3,083
Directors' stock compensation - - - 25,200 349 - - - 349
----------- ------- ---------- --------- -------- ------------ -------- ------------- -------------
Balances, December 31, 2004 57,458,246 $ 574 $127,374 (500,000) $ (5,295) $ (5,039) $364,567 $ 2,274 $ 484,455
----------- ------- ---------- --------- -------- ------------ -------- ------------- -------------
Comprehensive income,
net of tax:
Net income - - - - - - 35,103 - 35,103
Change in derivative
instrument fair value - - - - - - - (20,967) (20,967)
Reclassification to earn - - - - - - - (982) (982)
-------------
Total comprehensive income 13,154
-------------
Cash dividends declared,
$ 0.05 per share - - - - - - (2,862) - (2,862)
Sale of common stock,
including income tax
benefit of stock
option exercises 274,512 3 4,504 - - - - - 4,507
Deferred compensation related
to issued restricted stock
unit awards, net
of forfeitures - - 4,811 - - (4,811) - - -
Accrued stock-based
compensation - - (726) - - - - - (726)
Amortization of deferred
stock-based compensation - - - - - 1,762 - - 1,762
----------- ------- ---------- --------- -------- ------------ -------- ------------- -------------
Balances, March 31, 2005 57,732,758 $ 577 $135,963 (500,000) $ (5,295) $ (8,088) $396,808 $ (19,675) $ 500,290
=========== ======= ========== ========= ======== ============ ======== ============= =============
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)
(In thousands)
For the Three Months Ended
March 31,
--------------------------
2005 2004
Reconciliation of net income to net cash provided ---------- -----------
by operating activities:
Net income $ 35,103 $ 21,449
Adjustments to reconcile net income to net
cash provided by operating activities:
Gain on sale of proved properties - (195)
Depletion, depreciation, amortization
and abandonment liability accretion 30,074 20,626
Exploratory dry hole expense 200 44
Abandonment and impairment of unproved properties 1,870 922
Unrealized derivative (gain) loss 1,129 (852)
Change in Net Profits Plan liability 4,221 2,160
Deferred and accrued stock-based compensation 1,036 -
Income tax benefit from the exercise of stock options 1,225 -
Deferred income taxes 13,740 8,645
Other 1,046 159
Changes in current assets and liabilities:
Accounts receivable 11,161 (5,292)
Prepaid expenses and other (1,603) 702
Accounts payable and accrued expenses (7,071) (8,450)
---------- -----------
Net cash provided by operating activities 92,131 39,918
---------- -----------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 45 483
Capital expenditures (63,307) (42,482)
Acquisition of oil and gas properties, net of cash received (34,738) (522)
Deposits to short-term investments available-for-sale (1,502) -
Receipts from short-term investments available-for-sale 1,402 1,000
Other 3,822 49
---------- -----------
Net cash used in investing activities (94,278) (41,472)
---------- -----------
Cash flows from financing activities:
Proceeds from credit facility 66,967 76,497
Repayment of credit facility (57,000) (56,500)
Proceeds from sale of common stock for exercise of stock options 3,282 3,942
Repurchase of common stock - (19,406)
---------- -----------
Net cash provided by financing activities 13,249 4,533
---------- -----------
Net change in cash and cash equivalents 11,102 2,979
Cash and cash equivalents at beginning of period 6,418 14,827
---------- -----------
Cash and cash equivalents at end of period $ 17,520 $ 17,806
========== ===========
The accompanying notes are an integral part
of these consolidated financial statements.
-6-
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Continued)
Supplemental schedule of additional cash flow information and noncash investing
and financing activities:
For the Three Months Ended
March 31,
--------------------------
2005 2004
-------- --------
(In thousands)
Cash paid for interest, including amounts capitalized $ 3,549 $ 3,778
Cash paid for income taxes $ 6,017 $ 9,883
In March 2005 the Company issued 194,508 restricted stock units pursuant to the
Company's restricted stock plan. The total value of the grant was $4.9 million.
As of March 31, 2005, the Company has recorded $1.3 million of compensation
expense related to this grant.
In January 2004 the Company issued a total of 8,400 shares of common stock from
treasury to its non-employee directors pursuant to the Company's non-employee
director stock compensation plan. The Company recorded compensation expense of
$64,260 for the first quarter of 2004.
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)
--------------------------
March 31, 2005
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, exploitation,
development, acquisition and production of natural gas and crude oil. The
Company's operations are conducted entirely in the continental United States.
Note 2 - Basis of Presentation and Significant Accounting Policies
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, 2004. In the opinion of
management, all adjustments (consisting of normal recurring accruals) considered
necessary for a fair presentation of the interim financial information have been
included. Operating results for the periods presented are not necessarily
indicative of the results that may be expected for the full year.
Certain amounts in the 2004 unaudited condensed financial statements
have been reclassified to conform to the 2005 unaudited condensed financial
statement presentation. The non-cash portion of Net Profits Interest Bonus Plan
(the "Net Profits Plan") expense and the corresponding liability have been
reclassified as separate line items in the accompanying financial statements for
all periods presented. As a result, prior period general and administrative
expense, exploration expense and other non-current liabilities have been
reclassified to conform to the current presentation. Additionally, wells in
progress have been classified as a separate line item in the consolidated
balance sheets for all periods presented. As a result, prior period unproved oil
and gas properties, net of impairment allowance, have been reclassified to
conform to the current presentation.
Stock Dividend
In March 2005 the Company's Board of Directors approved a two-for-one
stock split in the form of a stock dividend whereby one additional common
share of stock was distributed for each common share outstanding. The stock
dividend was distributed on March 31, 2005, to shareholders of record as of the
close of business on March 21, 2005. All share and per share amounts for all
periods presented herein have been restated to reflect this stock split.
Goodwill
Goodwill is recorded in the Company's consolidated balance sheets as a
result of the acquisition of Agate Petroleum, Inc. in January 2005. Goodwill is
reviewed for impairment annually or more frequently if impairment indicators
arise.
-8-
Other Significant Accounting Policies
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, 2004. 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 - Acquisition of Agate Petroleum, Inc.
On January 5, 2005, the Company acquired Agate Petroleum, Inc.
("Agate") in exchange for $39.9 million in cash. The preliminary purchase price
has been allocated based on the fair values of the acquired assets and
liabilities as estimated at closing. The final purchase price allocation will
not be finalized until all amounts related to receivables and payables are
determined with certainty. The Company expects that this allocation will be
completed prior to the end of 2005 and will not result in any material
adjustments to the preliminary purchase price. The Company acquired $4.6 million
in cash from Agate, and the allocation of the purchase price resulted in the
recording of $41.9 million to proved and unproved oil and gas properties, $1.2
million to net current liabilities, $9.6 million to goodwill, a deferred income
tax liability of $13.6 million and a $1.4 million asset retirement obligation.
The acquisition was accounted for using the purchase method of accounting and
was funded with cash on hand and borrowings under the Company's existing credit
facility. Operating results from the acquired properties have been included in
the consolidated statements of operations only from the date of closing.
The goodwill and deferred income tax liability resulted from acquiring
oil and gas assets in the transaction with a tax basis that is lower than the
allocated fair value book basis because present value considerations cannot be
applied to the amounts recorded for deferred income taxes. The strategic
benefits to the Company that support the recognition of goodwill in this
acquisition include the mix of complementary high-quality assets in two of our
existing core areas, lower-risk exploitation opportunities, and increased cash
flow from operations available for investing activities.
Note 4 - Earnings per Share
Basic net income per common share of stock is calculated by dividing
net income available to common stockholders by the weighted-average common
shares outstanding during each period. Vested restricted stock units are
included in the calculation of the weighted-average common shares outstanding.
On February 9, 2004, the Company repurchased and retired 6,761,636 shares of its
common stock (see Note 11-Repurchase of Common Stock).
Diluted net income per common share of stock is calculated by dividing
adjusted net income by the weighted-average of common shares outstanding,
including the effect of potentially dilutive securities. Adjusted net income is
used for the if-converted method 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 that
are based on income and that would have changed had the Convertible Notes been
converted at the beginning of the period. 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
unvested restricted stock units.
The shares underlying the grants of restricted stock units are excluded
from basic and diluted earnings per share until the measurement date for grants
made under the Restricted Stock Plan. Upon measurement, all unvested shares
attributable to the restricted stock unit grant are included in the diluted
earnings per share calculation. Vested shares are included in both basic and
diluted earnings per share.
The dilutive effect of stock options and unvested restricted stock
units is considered in the detailed calculation below. There were no
anti-dilutive securities related to stock options for the three-month period
ended March 31, 2005 and 1,223,356 anti-dilutive securities related to stock
-9-
options for the three-month period ended March 31, 2004. There were no
anti-dilutive securities related to restricted stock units for any periods
presented.
Shares associated with the conversion feature of the Convertible Notes
are accounted for using the if-converted method as described above and are
considered in the detailed calculation below. A total of 7,692,307 potentially
dilutive shares related to the Convertible Notes were included in the
calculation of diluted net income per common share for the three-month periods
ended March 31, 2005 and 2004. The Convertible Notes were issued in March 2002.
The following table sets forth the calculation of basic and diluted
earnings per share:
For the Three Months Ended
March 31,
---------------------------------
2005 2004
--------------- --------------
(In thousands, except
per share amounts)
Net income $ 35,103 $ 21,449
Adjustments to net income for dilution:
Add: interest expense not incurred if Convertible Notes
converted 1,563 1,580
Less: other adjustments (16) (16)
Less: income tax effect of adjustment items (574) (593)
--------------- --------------
Net income adjusted for the effect of dilution $ 36,076 $ 22,420
=============== ==============
Basic weighted-average common shares outstanding 57,231 59,549
Add: dilutive effects of stock options and unvested
restricted stock units 2,124 1,142
Add: dilutive effect of Convertible Notes using if-
converted method 7,692 7,692
--------------- --------------
Diluted weighted-average common shares outstanding 67,047 68,383
=============== ==============
Basic earnings per common share $ 0.61 $ 0.36
Diluted earnings per common share $ 0.54 $ 0.33
Note 5 - Compensation Plans
Restricted Stock Plan
In May 2004 the Restricted Stock Plan was approved by the Company's
stockholders. This established a long-term incentive program whereby grants of
restricted stock or restricted stock units may be awarded to eligible employees,
consultants, and members of the Board of Directors. Restrictions and vesting
periods for the awards are determined at the discretion of the Board of
Directors and are set forth in the award agreements. The total number of shares
of the Company's common stock reserved for issuance under the Restricted Stock
Plan is 11,200,000. This number is reduced to the extent that stock options are
granted under the Company's stock option plans.
St. Mary issued 194,508 restricted stock units (RSUs) on March 15,
2005, related to 2004 performance. The total expense associated with this
issuance was $4.9 million as measured on the issuance date. The total measured
expense was initially recorded as deferred stock-based compensation and is being
-10-
charged to compensation expense based on the vesting schedule. The RSU grants
vest 25 percent immediately upon issuance and 25 percent on each of the first
three anniversary dates. The vested shares underlying the RSU grants will be
issued on the third anniversary of the issuance, at which time the shares carry
no further restrictions. As of March 31, 2005, there were a total of 647,840
RSUs outstanding, of which 165,057 were vested. Total compensation expense for
the three-month period ended March 31, 2005, related to the RSUs was
$1.0 million. This expense included $380,000 of compensation expense related
to the 2005 plan year for grants expected to be issued in 2006.
Net Profits Plan
Under the Company's Net Profits Plan, oil and gas wells that are
completed or acquired during a year are designated within a specific pool. Key
employees designated as participants by the Company's Compensation Committee of
the Board of Directors and employed by the Company on the last day of that year
vest and become entitled to bonus payments after the Company has received net
cash flows returning 100 percent of all costs and expenses associated with that
pool. Thereafter, 10 percent of future cash flows generated by the pool are
allocated among the participants and distributed at least annually. The portion
of cash flows from the pool to be allocated among the participants increases to
20 percent after the Company has recovered 200 percent of the total costs and
expenses for the pool, including payments made under the Net Profits Plan at the
10 percent level.
Expenses related to current distributions made under the Net Profits
Plan for the three-month period ended March 31, 2005 and 2004 were $2.7 million
and $2.0 million, respectively. These amounts relate to current realized results
from oil and gas operations in the respective periods.
The Company records the estimated future liability for the Net Profits
Plan based on the discounted value of estimated future payments associated with
each individual pool. The following table presents the changes in the estimated
future liability attributable to the Net Profits Plan:
For the Three Months Ended
March 31,
-----------------------------------
2005 2004
--------------- ----------------
(In thousands)
Beginning liability for Net Profits Plan $ 30,561 $ 6,163
Increase in liability 6,886 4,157
Reduction in liability for cash payments
made or accrued and recognized as
compensation expense under the Net
Profits Plan (2,665) (1,997)
--------------- ----------------
Ending liability for Net Profits Plan $ 34,782 $ 8,323
=============== ================
The Company records changes in the present value of estimated future
payments under the Net Profits Plan as a separate item in the consolidated
statements of operations. The change in the estimated liability is recorded as
an increase or decrease to expense in the current period. The amount recorded as
an increase or decrease to expense associated with the change in the estimated
liability is not allocated to general and administrative costs or exploration
costs because it is an estimate at the current time of the adjustment to the
liability that is associated with the future net cash flows from oil and gas
properties in the respective pools rather than current period realized
performance. The table below presents the estimated allocation of the change in
the liability if the Company did allocate the adjustment to these specific line
items:
-11-
For the Three Months Ended March 31,
--------------------------------------
2005 2004
----------------- -----------------
(In thousands)
General and administrative expense $ 2,142 $ 1,087
Exploration expense 2,079 1,073
----------------- -----------------
Total $ 4,221 $ 2,160
================= =================
Stock Option Plans
Statement of Financial Accounting Standards ("SFAS") No. 123,
"Accounting for Stock-Based Compensation," establishes a fair value method of
accounting for stock-based compensation through either recognition or
disclosure. 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 has elected to adopt SFAS No. 123 through compliance with
the disclosure requirements set forth in the Statement. Because the exercise
price of the Company's stock options equals the market price of the underlying
common stock on the date of grant, no compensation expense is recognized under
APB No. 25. The following table illustrates the pro forma effect on net income
and earnings per share if the Company had applied the fair value recognition
provisions of SFAS No. 123 to stock-based employee compensation for the periods
presented.
For The Three Months Ended March 31,
------------------------------------
2005 2004
----------------- ------------------
(In thousands,
except per share amounts)
Net income -
- ------------ $ 35,103 $ 21,449
As reported:
Add: stock-based employee compensation expense
included in reported net income, net of related tax effects 652 -
Less: stock-based employee compensation expense
determined under fair value based method for all awards,
net of related income tax effects (1,227) (883)
----------------- ------------------
Pro forma net income $ 34,528 $ 20,566
================= ==================
Basic earnings per share -
- --------------------------
As reported $ 0.61 $ 0.36
Pro forma $ 0.60 $ 0.35
Diluted earnings per share -
- ----------------------------
As reported $ 0.54 $ 0.33
Pro forma $ 0.53 $ 0.31
For purposes of these 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.
-12-
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 the
three-month period ended March 31, 2004, were estimated using the following
weighted-average assumptions. No options were granted during the three-month
period ended March 31, 2005.
For the Three
Months Ended
March 31, 2004
---------------------
Risk free interest rate
Stock options 3.6%
Employee Stock Purchase Plan **
Dividend yield
Stock options 0.3%
Employee Stock Purchase Plan **
Volatility factor of the expected market price
of the Company's common stock
Stock options 38.7%
Employee Stock Purchase Plan **
Expected life of the options (in years)
Stock options 7.6
Employee Stock Purchase Plan **
- ----------------------------
** No shares were issued under the Employee Stock Purchase Plan in the first
quarter of fiscal years 2005 or 2004.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options that have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. The Company's 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 valuations afforded by the existing models are
different from the value that the options would realize if traded in the market.
In December 2004 the FASB issued SFAS No. 123 (Revised 2004),
"Shared-Based Payment". This statement provides for the accounting for
transactions in which an entity exchanges equity instruments or incurs
liabilities in exchange for goods or services. The effective date of this
statement was delayed until January 1, 2006, by the Securities and Exchange
Commission. Under the modified-prospective method, the Company estimates that it
will record a total of $3.1 million of compensation expense in periods after the
implementation date related to the unvested portion of its stock options issued
prior to the effective date. There will be no cumulative effect of change in
accounting principle as a result of the adoption of SFAS No 123 (revised 2004).
Note 6 - Income Taxes
Income tax expense for the three months ended March 31, 2005 and 2004
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 the composition of state income taxes, percentage depletion, changes
in the composition of income tax rates, the estimated effect of the domestic
-13-
production activities deduction from the recently enacted American Jobs Creation
Act of 2004 and other permanent differences.
For the three-month period ended March 31, 2005, the Company's current
portion of income tax expense was $10.4 million compared to $5.9 million for the
same period in 2004. The Company's effective tax rate for the three-month period
ended March 31, 2005, was 37.1 percent compared to 37.9 percent for the
three-month period ended March 31, 2004. The decrease in tax rate reflects a
change in the composition of the estimated highest marginal state tax rate as a
result of acquisition and drilling activity. It also reflects the Company
estimate of the effect of the domestic production activities deduction and the
possible impact of state permanent differences.
Note 7 - Long-term Debt
Revolving Credit Facility
The Company executed an Amended and Restated Credit Agreement on April
7, 2005, with a five year term. This facility replaced the previous facility.
The new credit facility specifies a maximum loan amount of $500.0 million and
has a maturity date of April 7, 2010. 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.
The initial borrowing base under the new credit facility as authorized by the
bank group was $400.0 million. The borrowing base is subject to regular
semi-annual redeterminations. The borrowing base redetermination process
considers the value of St. Mary's oil and gas properties and other assets, as
determined by the bank syndicate. The Company elected an aggregate commitment
amount of $200.0 million under the new credit facility. 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 1.000% 1.250% 1.500% 1.750%
ABR loans 0.000% 0.250% 0.250% 0.500%
Commitment fee rate 0.250% 0.300% 0.375% 0.375%
At March 31, 2005, the Company's borrowing base utilization percentage
as defined under the credit agreement was 24 percent. The Company had $42
million in Eurodollar loans and $5 million in ABR loans outstanding under its
revolving credit agreement as of March 31, 2005.
5.75% Senior Convertible Notes Due 2022
As of March 31, 2005, the Company also had $100.0 million in
outstanding borrowings under the Convertible Notes. The Convertible Notes
provide for the payment of contingent interest of up to an additional 0.5
percent 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 percent for the three-month periods ended
March 31, 2005 and 2004. Based on the trading price of the Convertible Notes
over the determination periods, the Company will be subject to the contingent
interest payments for the period from March 16, 2005 to September 15, 2005.
-14-
Weighted-average Interest Rate Paid
The weighted-average interest rates paid for the first quarters of 2005
and 2004 were 7.1 percent and 6.0 percent, respectively, including commitment
fees paid on the unused portion of the credit facility aggregate commitment,
amortization of deferred financing costs, amortization of the contingent
interest embedded derivative and the effects of interest rate swaps. The Company
capitalized interest costs of $397,000 and $276,000 for the three-month periods
ended March 31, 2005 and 2004, respectively.
Note 8 - Derivative Financial Instruments
The Company recognized a net gain of $1.6 million from its oil and gas
derivative contracts for the three months ended March 31, 2005, compared to a
net loss of $8.6 million for the same period in 2004.
The following table summarizes all derivative instrument gain (loss)
activity:
For the Three Months Ended
March 31,
-------------------------------
2005 2004
-------------- --------------
(In thousands)
Derivative contract settlements included in
oil and gas hedge gain (loss) $ 1,560 $ (8,599)
Interest rate derivative contract settlements 28 484
Ineffective portion of hedges qualifying for
hedge accounting included in derivative gain (loss) (614) 15
Non-qualified derivative contracts included
in derivative gain (loss) (515) 837
--------------- --------------
Total $ 459 $ (7,263)
=============== ==============
-15-
Oil and Gas Commodity Hedges
The Company has in place derivative contracts for the sale of oil and
natural gas. The Company attempts to qualify these instruments as cash flow
hedges for accounting purposes. The table below describes the volumes and
average contract prices of hedges currently in place. The Company's oil and
natural gas derivatives include swap and collar agreements. Gas contracts are
indexed to a variety of regional indexes, and the oil contracts are NYMEX based.
Swaps Gas (per MMBtu) Oil (per Bbl)
- ----- ----------------------------------------- -------------------------------------------
Weighted-Average Weighted-Average
Contract Contract Price Contract Price
Period Volumes (Regional Index) Volumes (NYMEX)
--------------- ----------------------- ---------------- -----------------------
2005
- ----
Quarter Ending:
June 30, 2,426,600 $ 6.23 258,214 $ 45.55
September 30, 2,505,000 $ 6.44 299,980 $ 45.55
December 31, 2,490,000 $ 6.77 249,770 $ 45.42
---------------- ---------------
Total 2005 7,421,600 $ 6.48 807,964 $ 45.51
---------------- ---------------
2006
- ----
Quarter Ending:
March 31, 1,620,000 $ 7.13 214,366 $ 44.70
June 30, 1,060,000 $ 5.80 136,976 $ 41.19
September 30, 690,000 $ 5.49 100,372 $ 37.47
December 31, 270,000 $ 5.55 77,686 $ 36.42
--------------- ---------------
Total 2006 3,640,000 $ 6.32 529,400 $ 41.21
--------------- ---------------
2007
- ----
Quarter Ending:
March 31, - $ - 63,410 $ 35.63
June 30, - $ - 61,072 $ 35.35
September 30, - $ - 62,684 $ 35.10
December 31, - $ - 60,620 $ 34.79
--------------- ---------------
Total 2007 - $ - 247,786 $ 35.22
--------------- ---------------
All Contracts 11,061,600 $ 6.43 1,585,150 $ 42.47
=============== ===============
Collars Gas (per MMBtu)
- -------
---------------------------------------------------------------------
Weighted-Average Weighted-Average
Contract Floor Ceiling
Period Price Price Volumes Index
-------------- -------------- --------------------- -----------------
2005
- ----
Quarter Ending:
June 30, $ 5.73 $ 7.20 540,000 IF ANR OK
September 30, $ 5.75 $ 7.30 415,000 IF ANR OK
December 31, $ 6.00 $ 7.63 390,000 IF ANR OK
---------------------
All Contracts $ 5.82 $ 7.36 1,345,000
=====================
-16-
The Company seeks to minimize basis risk and indexes its oil contracts
to NYMEX prices and its gas contracts to various regional index prices
associated with pipelines in proximity to the Company's areas of gas production.
Swap natural gas volumes associated with specific Inside FERC ("IF") regional
indexes are as follows:
Regional Index MMBtu
- -------------- --------------
IF ANR OK 6,531,600
IF Reliant N/S 2,500,000
IF PEPL 2,030,000
--------------
Total 11,061,600
==============
Derivative gains and losses in the consolidated statements of
operations for the three-month periods ended March 31, 2005 and 2004 include a
net loss of $614,000 and a net gain of $15,000, respectively, from
ineffectiveness related to oil and natural gas derivative contracts. On March
31, 2005, the estimated fair value of oil and natural gas derivative contracts
designated and qualifying as cash flow hedges under SFAS No. 133 was a net
liability of $31.6 million. If prices remain unchanged from March 31, 2005
levels, the Company would reclassify this amount to oil and gas hedge loss
included in operating revenue as the hedged production quantities are produced.
As of March 31, 2005, the net amount of unrealized loss net of deferred income
taxes to be reclassified from accumulated other comprehensive income to oil and
natural gas production operating revenues in the next twelve months was $12.9
million. The Company anticipates that all original forecasted transactions will
occur by the end of the originally specified time periods.
Interest Rate Derivative Contracts
In October 2003 the Company entered into fixed-to-floating interest
rate swaps for a total notional amount of $50.0 million through March 20, 2007.
Under the swaps, St. Mary will be paid a fixed interest rate of 5.75 percent 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 payment dates of the
swaps match exactly with the interest payment dates of the Convertible Notes.
The six-month LIBOR rate on March 31, 2005 was 3.4 percent. The fair value of
the swaps was a liability of $1.1 million as of March 31, 2005. During the
three-month periods ended March 31, 2005 and 2004, the Company received payments
of $28,000 and $484,000, respectively, under the swap arrangements. These
payments have reduced the Company's interest expense. The Company recorded a net
derivative loss in the consolidated statements of operations of $676,000 for the
three-month period ended March 31, 2005, and a net derivative gain of $834,000
for the three-month period ended March 31, 2004, from mark-to-market adjustments
for this derivative.
The Company entered into a floating-to-fixed interest rate swap on
April 13, 2005, for a total notional amount of $50.0 million through March 20,
2007, that effectively offset the fixed-to-floating interest rate swaps
described above. Under the swap, St. Mary will be paid a variable interest rate
of 235 basis points above the six-month LIBOR rate as determined on the
semi-annual settlement date and will pay a fixed interest rate of 6.85 percent.
The payment dates of the swap match exactly with the interest payment dates of
the Convertible Notes and fixed-to-floating interest rate swaps. The impact of
this instrument, when combined with the other interest rate swaps, is that the
Company has fixed its net liability related to the interest rate swaps and will
pay a 1.1 percent interest factor on $50.0 million of notional debt through
March 2007.
These swaps do not qualify for fair value hedge treatment under SFAS
No. 133 and related pronouncements.
-17-
Convertible Note Derivative Instrument
The contingent interest provision of the Convertible Notes 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
accounted for 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. Interest expense for each of the three-month periods ended March
31, 2005 and 2004, includes $24,000 of amortization. Derivative gain (loss) in
the consolidated statements of operations for the three-month periods ended
March 31, 2005 and 2004, includes a net gain of $160,000 and $4,000,
respectively, from mark-to-market adjustments for this derivative. The fair
value of this derivative at March 31, 2005 and 2004 was a liability of $660,000
and $771,000, respectively.
Note 9 - Pension Benefits
In December 2003 the FASB issued SFAS No. 132 (revised 2003),
"Employers' Disclosures about Pensions and Other Postretirement Benefits." This
statement replaces FASB Statement No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits", and adds certain annual and interim
period disclosure requirements. The provisions of this statement do not change
the measurement and recognition provisions of FASB No. 87, "Employers'
Accounting for Pensions", No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits", and
No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions." Interim period disclosure requirements have been incorporated
herein.
The Company's employees participate in a non-contributory pension plan
covering substantially all employees who meet age and service requirements (the
"Qualified Pension Plan"). The Company also has a supplemental non-contributory
pension plan covering certain management employees (the "Nonqualified Pension
Plan").
Components of Net Periodic Benefit Cost
The following table presents the components of the net periodic cost
for both the Qualified Pension Plan and the Nonqualified Pension Plan:
For the Three Months Ended
March 31,
----------------------------------
2005 2004
--------------- ---------------
(In thousands)
Components of net periodic benefit cost:
Service cost $ 346 $ 285
Interest cost 134 122
Expected return on plan assets (94) (74)
Amortization of prior service cost - (4)
Amortization of net actuarial loss 60 55
--------------- ---------------
Net periodic benefit cost $ 446 $ 384
=============== ===============
Prior service costs are amortized on a straight-line basis over the
average remaining service period of active participants. Gains and losses in
excess of 10 percent of the greater of the benefit obligation and the
market-related value of assets are amortized over the average remaining service
period of active participants.
-18-
Contributions
St. Mary expects to contribute approximately $1.1 million to the
pension plans in 2005 as was previously disclosed in its financial statements
for the year ended December 31, 2004.
Note 10 - Asset Retirement Obligations
The Company recognizes an estimated liability for future costs
associated with the abandonment of its oil and gas properties. A liability for
the fair value of an asset retirement obligation and 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 increase in carrying value is included in
proved oil and gas properties in the consolidated balance sheets. 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
estimated economic lives of the respective oil and gas properties.
The Company's estimated asset retirement obligation 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 estimated at the time the liability is incurred
or revised. The credit-adjusted risk-free rates used to discount the Company's
abandonment liabilities range from 6.50 percent to 7.25 percent. 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.
A reconciliation of the Company's asset retirement obligation liability
is as follows:
For the Three Months
Ended March 31,
--------------------------------
2005 2004
-------------- --------------
(In thousands)
Beginning asset retirement obligation $ 40,911 $ 25,485
Liabilities incurred 2,169 172
Liabilities settled (323) (86)
Accretion expense 705 465
-------------- --------------
Ending asset retirement obligation $ 43,462 $ 26,036
============== ==============
Note 11 - Repurchase of Common Stock
Repurchase of Common Stock from Flying J
On February 9, 2004, the Company repurchased 6,671,636 restricted
shares of its common stock from Flying J Oil & Gas and Big West Oil &
Gas, Inc. (collectively "Flying J") for a total of $91.0 million. St. Mary
originally issued these shares to Flying J on January 29, 2003, in connection
with St. Mary's acquisition of certain oil and gas properties. In addition to
issuing the shares in the acquisition, St. Mary loaned Flying J $71.6 million.
Flying J used the proceeds of the stock repurchase to repay their outstanding
loan balance of $71.6 million. Accrued interest, which had not been recorded by
the Company for financial reporting purposes due to the non-recourse nature of
the loan was forgiven. The net $19.4 million cash outlay for the repurchase was
funded from the Company's existing cash balances and borrowings under its bank
credit facility.
-19-
Stock Repurchase Program
In August 2004 the Company's Board of Directors approved an increase in
the number of shares that may be repurchased under the original authorization
approved in August of 1998 to 6,000,000 as of the effective date of the
resolution. The shares may be repurchased from time to time in open market
transactions or privately negotiated transactions, subject to market conditions
and other factors, including certain provisions of St. Mary's existing credit
facility agreement and compliance with securities laws. Stock repurchases may be
funded with existing cash balances, internal cash flow and borrowings under the
credit facility. The Company did not repurchase any shares of its common stock
under the program in the first quarter of 2005 and has 5,021,400 remaining
shares that may be repurchased under this authorization.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This discussion contains forward-looking statements. Please refer to
the Cautionary Statement about Forward-Looking Statements at the end of this
item for an explanation of these types of statements.
Overview of the Company
General Overview
We are an independent energy company focused on the exploration,
exploitation, development, acquisition and production of natural gas and crude
oil in the United States. We earn our revenues and generate our cash flows from
operations primarily from the sale at the wellhead of produced natural gas and
crude oil. Our oil and gas reserves and operations are concentrated in the
Anadarko, Arkoma, Permian and various Rocky Mountain basins and in the onshore
Gulf Coast and in the offshore Gulf of Mexico. We maintain a balanced portfolio
of proved reserves, development drilling opportunities and non-conventional gas
prospects.
Stock Dividend
In March 2005 the Board of Directors approved a two-for-one stock split
in the form of a stock dividend whereby one additional common share of stock was
distributed for each common share outstanding. The stock dividend was
distributed on March 31, 2005, to shareholders of record as of the close of
business on March 21, 2005. All share and per share amounts for all periods
presented herein have been restated to reflect this stock split.
Oil and Gas Prices
Our results of operations and financial condition are significantly
affected by oil and natural gas commodity prices, which can fluctuate
dramatically. Through the first quarter of 2005 we continued to benefit from
high oil and gas prices that helped contribute to a record financial results for
us in the quarter. Higher natural gas prices are the result of tightening supply
coupled with increasing demand in the United States. Finite storage capacity,
changes in production, import capacity, and weather-related effects on domestic
demand have a significant effect on price volatility. Higher oil prices reflect
decreases in worldwide production capacity, continuing increases in demand from
the global economy, and continued instability in the Middle East.
-20-
First Quarter 2005 Highlights
NYMEX prices for the first quarter of 2005 averaged $6.32 per MMBtu and
$49.85 per barrel, a decrease of 8 percent for gas and an increase of 3 percent
for oil compared to the fourth quarter of 2004. These prices were 11 percent
higher for gas and 42 percent higher for oil than for the comparable period a
year ago. As of March 31, 2005, the NYMEX strip price for the remainder of the
year was $56.65 per barrel for oil and $7.88 per MMBtu for gas compared to
March 31, 2004 NYMEX strip prices of $33.42 per barrel and $5.57 per MMBtu.
On January 5, 2005, we closed the acquisition of Agate Petroleum Inc.
for $39.9 million in cash. Based on the preliminary purchase price allocation,
we acquired $4.6 million in cash from Agate and purchase accounting resulted in
recording approximately $41.9 million to oil and gas properties, $9.6 million to
goodwill, $1.2 million to net current liabilities, $13.6 million of deferred
income tax liability and a $1.4 million asset retirement obligation.
On April 7, 2005, we closed a new five-year, $500 million credit
facility agreement with Wachovia Bank, Wells Fargo Bank and eight other
participating banks. The initial borrowing base for the facility was set as $400
million, and we elected an initial commitment of $200 million. Additional
details regarding this facility are included below.
The quarter ended March 31, 2005, resulted in record high oil and gas
revenues, net income, production, and net cash provided by operating activities.
Net income for the quarter ended March 31, 2005, was $35.1 million or $0.54 per
diluted share compared to the 2004 results of $21.4 million or $0.33 per diluted
share. Net cash provided by operating activities was $92.1 million, up 131
percent from the $39.9 million provided in the first quarter of 2004. Production
increased 12 percent to 20.6 BCFE on a comparative-quarter basis, and our
average realized price increased 35 percent to $6.78 per MCFE. Unit costs
increased for the period as total production costs increased $0.28 to $1.56 per
MCFE, and DD&A increased $0.34 to $1.46 per MCFE.
The following table provides information regarding trends for selected
financial information for the quarter ended March 31, 2005 compared to the
immediate preceding quarter ended December 31, 2004:
Three Months Ended
-------------------------------------
March 31, December 31,
2005 2004 % Change
-------------- ------------------ -------------
(In millions)
Production (MCFE) 20.6 19.9 4%
Oil and gas revenues $ 139.9 $ 139.3 -
Production expenses $ 32.2 $ 26.2 23%
General and administrative expense $ 6.0 $ 5.5 8%
Net income $ 35.1 $ 26.6 32%
Outlook for the Remainder of 2005
Over the remainder of 2005 we will continue to execute our business
plan, which includes:
o Our capital expenditures budget remains constant at $418 million.
Of this amount, $293 million is allocated to drilling. A table of
budgeted amounts by core area is detailed under the caption
Capital Expenditure Budget. We have already spent $41.9 million of
our $125 million acquisitions budget, primarily on the Agate
acquisition, and we continue to aggressively evaluate acquisition
opportunities.
-21-
o Our Hanging Woman Basin coalbed methane project is currently in
full development. As anticipated, we completed 20 wells in the
first quarter of 2005 and are projecting that we will complete a
total of 150 wells for the year. Production for the project is
ahead of projected amounts and was 1,648 MCFE per day on April 25,
2005.
o We plan to participate in 24 well completions in the Williston
Basin Middle Bakken Play. We currently have two operated drilling
rigs and two operated re-entry rigs in the play. We are attempting
to add a third operated drilling rig in this area in 2005.
o We tentatively plan to drill nine horizontal wells in the
Centrahoma field in 2005. The Mowdy #1 well was completed
horizontally in March 2005 in the Cromwell sand with an initial
rate of 3,000 MCFE per day and is currently producing 2,600 MCFE
per day. We have successfully completed vertical producing wells
in 11 sections of the Cromwell formation. We hold 36,000 gross and
20,000 net contiguous acres in this area, and approximately half
of the acreage is held by existing production. We are currently
evaluating future development plans and expect to ultimately drill
approximately four horizontal wells per section in the field. The
Wapanuka limestone, which has produced from vertical wells, may
also respond to this completion technique.
o We continue to anticipate that production for 2005 will exceed
2004 reported amounts as a result of acquisitions and our drilling
programs.
-22-
A quarter-to-quarter overview of selected reserve, production and financial
information, including trends:
Selected Operations Data (In Thousands, Except Price and Per MCFE Amounts):
Three Months Ended March 31,
---------------------------------- % Change
2005 2004 Between Periods
-------------- ---------------- ---------------
Net production volumes
- ----------------------
Natural gas (Mcf) 12,047 11,613 4%
Oil (Bbl) 1,433 1,141 26%
MCFE (6:1) 20,647 18,456 12%
Average daily production
- ------------------------
Natural gas (Mcf per day) 134 128 5%
Oil (Bbls per day) 16 13 27%
MCFE per day (6:1) 229 203 13%
Oil & gas production revenues
- ---------------------------------
Gas production, including hedging $ 74,891 $ 60,439 24%
Oil production, including hedging 65,039 32,168 102%
-------------- ----------------
Total $ 139,930 $ 92,607 51%
============== ================
Oil & gas production expense
- --------------------------------
Lease operating expenses $ 20,236 $ 15,177 33%
Transportation costs 1,880 1,737 8%
Production taxes 10,043 6,629 52%
-------------- ----------------
Total $ 32,159 $ 23,543 37%
============== ================
Average realized sales price(1)
- -------------------------------
Natural gas (Per Mcf) $ 6.22 $ 5.20 20%
Oil (Per Bbl) $ 45.37 $ 28.20 61%
Per MCFE data:
- --------------
Average net realized price(1) $ 6.78 $ 5.02 35%
Lease operating expense (0.98) (0.83) 20%
Transportation costs (0.09) (0.09) 0%
Production taxes (0.49) (0.36) 36%
General and administrative (0.29) (0.30) (1)%
-------------- ----------------
Operating profit $ 4.93 $ 3.44 43%
============== ================
Depletion, depreciation and amortization $ 1.46 $ 1.12 30%
Financial Information (In Thousands, Except Per Share Amounts):
March 31, December 31, % Change
2005 2004 Between Periods
-------------- ------------- ---------------
Working capital (deficit) $ (959) $ 12,035 (108)%
Long-term debt $ 146,814 $ 136,791 7%
Stockholders' equity $ 500,290 $ 484,455 3%
Three Months Ended March 31,
------------------------------- % Change
2005 2004 Between Periods
-------------- ------------- ---------------
Basic net income per common share $ 0.61 $ 0.36 69%
Diluted net income per common share $ 0.54 $ 0.33 64%
Basic weighted-average shares outstanding 57,231 59,549 (4)%
Diluted weighted-average shares outstanding 67,047 68,383 (2)%
Net cash provided by operating activities $ 92,131 $ 39,918 131%
Net cash used in investing activities $ (94,278) $ (41,472) 127%
Net cash provided by financing activities $ 13,249 $ 4,533 192%
- --------------------------------------------
(1) Includes the effects of our hedging
activities
-23-
We present the preceding table as a summary of information relating to
those key indicators of financial condition and operating performance that we
believe to be most important. We present per MCFE information since we use this
information to evaluate our performance relative to our peers and to measure
trends that we believe require analysis. Our period-to-period comparison of
financial results presented later provides additional details for the per MCFE
differences between reported periods.
For the remainder of this year we expect oil and gas production
expenses will increase compared to prior year amounts. Production taxes will be
higher as a percentage of revenue in the remainder of 2005 as a result of the
increase in pricing that we are experiencing. Depreciation, depletion and
amortization will increase due to the higher costs associated with finding and
acquiring crude oil and natural gas. We expect general and administrative
expense per MCFE for all of 2005 will remain fairly consistent relative to the
first three months of 2005.
The remaining information in the table relates to information we have
provided in operations update press releases and is intended to supplement the
discussion above.
Overview of Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to
execute our business plans for the foreseeable future.
Sources of Cash
Our primary sources of liquidity are the cash provided by operating
activities, debt financing and access to the capital markets.
Our current credit facility. On April 7, 2005, we entered into a new
five-year, $500 million credit facility agreement with Wachovia Bank, Wells
Fargo Bank and eight other participating banks. This new credit facility
replaced our previous $300.0 million credit facility discussed in Part II, Item
7 of our Form 10-K for the year ended December 31, 2004. The initial borrowing
base for the new facility is set at $400 million. We elected an initial
commitment amount of $200 million, which results in lower commitment fees
payable to the bank syndicate. We believe this commitment level is adequate for
our near-term liquidity requirements. The credit agreement has a maturity date
of April 7, 2010. We must comply with certain financial and non-financial
covenants, and we are currently in compliance with all of these covenants.
Interest and commitment fees are accrued based on the borrowing base utilization
percentage. Eurodollar loans accrue interest at LIBOR plus the applicable margin
from the utilization table, and Alternate Base Rate loans accrue interest at
prime plus the applicable margin from the utilization table. This table is
located in Note 7 of Part I, Item 1 of this report. Borrowings under the new
facility are secured by the majority of our oil and gas properties and a pledge
of the common stock of our material subsidiary companies.
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. Our loan balance of $47.0 million on March 31, 2005,
was comprised of $42.0 million of Eurodollar based borrowing and $5.0 million of
ABR borrowing. As of April 29, 2005, our total outstanding borrowings under the
new credit facility had been reduced to $32.0 million of Eurodollar based
borrowing and no ABR borrowing.
We increased our net borrowings by $10.0 million to $146.8 million in
the first quarter of 2005 primarily to fund our purchase of Agate Petroleum. Our
weighted-average interest rate paid in the first quarter of 2005 was 7.1 percent
and included commitment fees paid on the unused portion of the credit facility
borrowing base, amortization of deferred financing costs, amortization of the
contingent interest embedded derivative associated with the convertible notes,
and the effects of interest rate swaps.
-24-
Interest rate market 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. We entered into a floating-to-fixed
interest rate swap on April 13, 2005, for a total notional amount of $50.0
million through March 20, 2007 in order to effectively offset our
fixed-to-floating interest rate swaps. Under the floating-to-fixed interest rate
swap, we will be paid a variable interest rate of 235 basis points above the
six-month LIBOR rate as determined on the semi-annual settlement date and will
pay a fixed interest rate of 6.85 percent. The impact of this instrument, when
combined with the other interest rate swaps, is that we have fixed our net
liability related to the interest rate swaps, and we will pay a 1.1 percent
interest factor on $50.0 million of notional debt through March 2007. The
payment dates of the swap match exactly with the interest payment dates of the
convertible notes and the fixed-to-floating interest rate swaps. We anticipate
that increasing interest rates will result in higher interest expense for us in
2005 compared to last year.
The sensitivity analysis discussed below presents the hypothetical
change in fair value of those financial instruments we held at March 31, 2005,
that are sensitive to changes in interest rates. For fixed-rate debt, interest
rate changes affect the fair market value but do not impact results of
operations or cash flows. Conversely, interest rate changes for floating-rate
debt 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. Giving
consideration to the interest rate swaps in effect on March 31, 2005, we had
floating-rate debt of $97.0 million and had $50.0 million of fixed-rate debt as
of that date. Assuming constant debt levels, the cash flow impact for the
remainder of the year resulting from a one-percentage point change in interest
rates would be approximately $728,000 before taxes. The results of operations
impact might be less than this amount as a direct effect of the capitalization
of interest to wells drilled during the year. In prior years when our debt
amount was at a reduced level we capitalized a larger percentage of our interest
expense. Since we cannot predict the exact amount that would be capitalized, we
cannot predict the exact effect that a one-percentage point shift would have on
the results of operations. As a result of the new interest rate swap in April
2005 and a reduction in amounts outstanding under our credit facility, we had
floating-rate debt of $32.0 million and fixed-rate debt of $100.00 million as of
April 29, 2005.
Uses of Cash
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. In the first quarter of 2005 we spent $98.0 million on
capital development using cash flows from operations and debt financing. Our net
payables decreased by $7.1 million and we made a $6.0 million cash payment for
income taxes.
We have 5,021,400 shares that may be repurchased under our stock
repurchase program. The shares may be repurchased from time to time in open
market transactions or privately negotiated transactions, subject to market
conditions and other factors, including certain provisions of our existing bank
credit facility agreement and compliance with securities laws.
In connection with our two-for-one stock split in March 2005, we
announced that the semi-annual dividend rate would remain at $0.05 per share.
This effectively doubles our cash dividend payments from 2004.
The following table presents amounts and percentage changes between the
quarters ended March 31, 2005 and 2004, from our operating, investing and
financing activities. The analysis following the table should be read in
conjunction with our consolidated statements of cash flows in Part I, Item 1 of
this report.
-25-
Amount of Change Percent of Change
2005/2004 Between Periods
---------------- -----------------
Net cash provided by operating activities 52,213 131%
Net cash used in investing activities (52,806) 127%
Net cash provided by financing activities 8,716 192%
Analysis of cash flow changes between the quarters ended March 31, 2005 and
March 31, 2004
Operating activities. Sources of cash flow from oil and gas sales, net
of the effects of hedging, increased $51.7 million between the period ended
March 31, 2005 and the period ended March 31, 2004. This was the result of a 35
percent increase in our realized prices and a 12 percent increase in production
between the two periods. Cash expenditures for oil and gas production expenses,
exploration expenses and administrative expenses increased by $4.9 million
during the same timeframe, and in the first quarter of 2004 we made a $5.8
million advance payment for income taxes.
Investing activities. The increase in net cash used resulted from
$20.8 million of increased drilling expenditures in the first quarter of 2005
compared to the first quarter of 2004 and from our $39.9 million acquisition of
Agate in 2005, less $4.6 million of cash we received at closing. Total 2005
capital expenditures, including acquisitions of oil and gas properties,
increased $55.0 million or 128 percent to $98.0 million compared to $43.0
million in 2004.
Financing activities. The $8.7 million increase in cash provided
between periods presented above reflects the net $19.4 million we paid to
repurchase our shares from Flying J on February 9, 2004, and a $10.0 million
increase in borrowing against our credit facility in 2005 to fund our drilling
and acquisition programs. On February 9, 2004, we repurchased 6,761,636 shares
of our common stock from Flying J for a total of $91.0 million. We originally
issued these shares to Flying J on January 29, 2003, in connection with our
acquisition of oil and gas properties. At that time we also loaned Flying J
$71.6 million. Flying J used the proceeds from the share repurchase to repay the
outstanding loan balance. The net $19.4 million difference was funded from our
available cash and from borrowings under our credit facility.
St. Mary had $17.5 million in cash and cash equivalents and had
negative working capital of $1.0 million as of March 31, 2005, compared to $6.4
million in cash and cash equivalents and working capital of $12.0 million as of
December 31, 2004.
Capital Expenditure Budget
Expenditures for exploration and development of oil and gas properties
and acquisitions are the primary use of our capital resources. We still
anticipate spending approximately $418 million for capital and exploration
expenditures in 2005 with $125 million allocated for acquisitions of producing
properties. Anticipated ongoing exploration and development expenditures and
budgeted gross wells for each of our core areas are as follows. The timing of
drilling and completion of wells is variable and will differ from these
estimates.
Exploration and
Development
Expenditures Well Count
--------------- ----------
(In millions)
Rocky Mountain region $ 95 118
Mid-Continent region 87 90
Gulf Coast region 41 27
ArkLaTex region 34 81
Coalbed Methane 26 183
Permian Basin region 10 35
--------------- ----------
$ 293 534
=============== ==========
-26-
We regularly review our capital expenditure budget to reflect changes
in current and projected cash flow, acquisition opportunities, debt requirements
and other factors. The above allocations are subject to change based on various
factors and results.
The following table sets forth certain information regarding the costs
incurred by us in our oil and gas property acquisition, exploration and
development activities, whether capitalized or expensed.
Three Months Ended
March 31,
-----------------------------
2005 2004
------------ -----------
(In thousands)
Development costs $ 53,246 $ 34,446
Exploration costs 12,107 6,616
Acquisitions:
Proved 39,324 694
Unproved 2,246 -
Leasing activity 4,446 2,792
------------ -----------
Total including asset retirement obligation
$ 111,369 $ 44,548
============ ===========
Our costs incurred for capital and exploration activities for the three
months ended March 31, 2005, increased $66.8 million or 150 percent compared to
the same period of 2004. This increase reflects our 2005 acquisition of Agate
and the planned increase in our drilling activity budget. We have $83.1 million
of our original allocated budget available for acquisitions in 2005.
We continue to develop the coalbed methane reserves in our Hanging
Woman Basin project. We completed 20 wells during the first quarter, and
permitting is on schedule to complete approximately 150 wells for the year. We
have 154,000 net lease acres in the basin and are concentrating our initial
development on 80,000 net acres located in Wyoming. Outstanding legal challenges
filed by environmental public interest groups affect 47,000 net acres in Montana
relating to this project. See Legal Proceedings under Part II, Item 1 of this
report.
We believe that internally generated cash flow together with our credit
facility will be sufficient to fund our expected operational, drilling and
acquisition expenditures for the foreseeable future. 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,
whether we can make an economic acquisition, and our ability to assimilate
acquisitions we make. Also, the impact of oil and gas prices on investment
opportunities, the availability of capital and borrowing facilities and the
success of our development and exploratory activities could lead to increased
funding requirements for further development.
Financing alternatives
The debt and equity financing capital markets remain attractive to
energy companies that operate in the exploration and production segment. This is
a result of strong commodity prices and the general strength reflected in the
balance sheets of the companies in this segment. As our cash balance and
availability under our existing credit facility are significant, we are not
currently considering accessing the capital markets in 2005. However, if
additional development or attractive acquisition opportunities arise that exceed
-27-
our currently available resources, we may consider other forms of financing,
including the public offering or private placement of equity or debt securities.
Sensitivity Analysis
We are exposed to market risk, including the effects of changes in oil
and gas commodity prices, and interest rates as discussed below and under the
caption "Interest rate market risk." Since we produce and sell natural gas and
crude oil, our financial results can be affected when prices for these
commodities fluctuate. In order to reduce the impact of fluctuations in
commodity prices, we enter into hedging transactions as discussed below. Changes
in interest rates can affect the amount of interest we earn on our cash, cash
equivalents and short-term investments and the interest rate we pay on
borrowings under our revolving credit facility. Changes in interest rates do not
affect the interest we pay on our fixed rate convertible notes, but do affect
the fair value of that debt.
Note 8 of Part I, Item 1 of this report contains important information
about our oil and gas derivative contracts, including the volumes and average
contract prices of hedges we currently have in place and have entered into
through April 29, 2005, and our interest rate derivative contracts. We
anticipate that all hedge and derivative contract transactions will occur as
expected.
There has been no material change to the natural gas and crude oil
price sensitivity analysis previously disclosed. Please see the corresponding
section under Part II, Item 7 of our Annual Report on Form 10-K for the year
ended December 31, 2004.
Summary of oil and gas production hedges in place
Our net realized oil and gas prices are impacted by hedges we have
placed on future forecasted transactions. We have historically entered into
hedges of existing production around the time we make acquisitions of producing
oil and gas properties. Our intent is to lock in a significant portion of an
equivalent amount of existing production to the prices we used to evaluate the
risked economics of our acquisition. We also hedge a small percentage of our
forecasted production on a discretionary basis.
For swap contracts in place on March 31, 2005, a hypothetical increase
of 10 percent in future gas strip prices representing a $0.74 weighted-average
increase per MMBtu applied to a notional amount of 11.1 million MMBtu covered by
natural gas swaps would cause a decrease in the value of derivative instruments
of $8.2 million. A hypothetical increase of 10 percent in the future NYMEX strip
oil prices representing a $5.49 increase per Bbl applied to a notional amount of
1.6 MMBbl covered by crude oil swaps would cause an $8.7 million decrease in the
value of the derivative instruments.
For collar contracts in place on March 31, 2005, a hypothetical
increase of 10 percent in future gas strip prices representing a $0.74
weighted-average increase per MMBTU applied to a notional amount of 1.3 million
MMBtu covered by natural gas collars would cause a $663,000 decrease in the
value of the derivative instruments.
The effect of price increases would impact our hedge gain or loss
amounts. However, these are cash flow hedges with high correlation, and the
price we receive on the underlying oil and gas production would be higher by
approximately the same amount. The effect on our results of operations would be
minimal.
Summary of interest rate hedges in place
We entered into fixed-rate to floating-rate interest rate swaps on
$50.0 million of convertible notes on October 3, 2003. Because of continuing
increases in interest rates, we entered into a floating-to-fixed interest rate
swap on April 13, 2005, through March 20, 2007, in on this same notional amount
of $50.0 million order to effectively offset our fixed-to-floating interest rate
swaps. Under the floating-to-fixed interest rate swap, St. Mary will be paid a
variable interest rate of 235 basis points above the six-month LIBOR rate as
determined on the semi-annual settlement date and will pay a fixed interest rate
of 6.85 percent. The payment dates of the swap match exactly with the interest
payment dates of our convertible notes and the fixed-to-floating interest rate
swaps. The impact of this instrument, when combined with the other interest rate
swaps, is that we have fixed our net liability related to the interest rate
swaps, and will pay a 1.1 percent interest factor on $50.0 million of notional
debt through March 2007.
-28-
These interest rate derivative instruments do not qualify for fair
value hedge treatment under Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" and are
consequently marked-to-market. Excluding accrued payments due to our
counterparts as of at March 31, 2005, the interest rate swaps had a fair value
liability of $1.1 million. Derivative loss (gain) in the consolidated statements
of operations for the quarter ended March 31, 2005, includes $676,000 of loss
related to the change in fair value. Derivative loss (gain) in the consolidated
statements of operations for the quarter ended March 31,2004, includes $834,000
of income related to the change in fair value. We anticipate that interest
expense in 2005 will be higher than in 2004.
Schedule of contractual obligations
The following table summarizes our future estimated principal payments
and minimum lease payments for the periods specified (in millions):
Less than More than
Contractual Obligations Total 1 year 1-3 years 3-5 years 5 years
- ---------------------------------- --------- ---------- --------- --------- ---------
Long-Term Debt $ 147.0 $ - $ 100.0 $ 47.0 $ -
Operating Leases 9.2 2.0 2.8 2.1 2.3
Other Long-Term Liabilities 19.1 1.8 14.7 1.3 1.3
--------- ---------- --------- --------- ---------
Total $ 175.3 $ 3.8 $ 117.5 $ 50.4 $ 3.6
========= ========== ========= ========= =========
This table includes our 2005 estimated pension liability payment of
approximately $1.1 million, but excludes the remaining unfunded portion of $1.8
million, as we cannot determine with accuracy the timing of future payments. The
table does not include estimated payments associated with our net profits plan.
We record a liability for the estimated future payments. However, predicting the
precise timing that the liability will be paid is contingent upon estimates of
appropriate discount factors adjusting for risk and time-value and upon a number
of factors that we cannot control. We have excluded asset retirement obligations
because we are not able to precisely predict the timing for these amounts. The
net profits plan, pension liabilities and asset retirement obligations are
discussed in Note 7, Note 8 and Note 9, respectively, of Part IV Item 15 of our
Form 10-K for the year ended December 31, 2004, and also in Note 5, Note 9 and
Note 10, respectively, of Part I Item 1 of this report.
Three leases for office space will expire in year two and a fourth
office space lease will expire in year three. 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 convertible notes will not exercise the conversion
feature. If the holders do exercise their conversion feature, we will not have
to repay the $100.0 million. However, our common shares outstanding would
increase by 7,692,307 shares.
We have announced that we have effectively doubled our dividend from
prior years and we believe that we will continue to pay the semi-annual
dividend of $0.05 per share. We anticipate having sufficient cash to make
payments for income taxes, dependent on net income and capital spending.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing other than operating
leases, nor do we have any unconsolidated subsidiaries.
Critical Accounting Policies and Estimates
We refer you to the corresponding section in Part II, Item 7 of our
Annual Report on Form 10-K for the year ended December 31, 2004.
-29-
Additional Comparative Data in Tabular Format:
Change Between the
Three Months Ended
-----------------------
Oil and Gas Production Revenues March 31, 2005 and 2004
- ------------------------------- -----------------------
Increase in oil and gas production revenues, net of hedging $ 47,323
(In thousands)
Components of Revenue Increases:
Natural Gas
Realized price change per Mcf $ 1.02
Realized price percentage change 20%
Production change (MMcf) 434
Production percentage change 4%
Oil
Realized price change per Bbl $ 17.17
Realized price percentage change 61%
Production change (MBbl) 293
Production percentage change 26%
Our product mix as a percentage of total oil and gas revenue and production:
Three Months Ended March 31,
--------------------------------
Revenue 2005 2004
- ------- -------- --------
Natural Gas 54% 65%
Oil 46% 35%
Production
- ----------
Natural Gas 58% 63%
Oil 42% 37%
Information regarding the effects of oil and gas hedging activity:
Three Months Ended March 31,
--------------------------------
Natural Gas Hedging 2005 2004
- ------------------- ------------ ---------
Percentage of gas production hedged 21% 32%
Natural gas MMBtu hedged $ 2.8 million $ 4.1 million
Increase (decrease) in gas revenue $ 3.8 million $ (3.1 million)
Average realized gas price per Mcf before hedging $ 5.90 $ 5.48
Average realized gas price per Mcf after hedging $ 6.22 $ 5.20
Oil Hedging
- -----------
Percentage of oil production hedged 18% 41%
Oil volumes hedged (MBbl) 252 462
Decrease in oil revenue $ (2.2 million) $ (5.5 million)
Average realized oil price per Bbl before hedging $ 46.93 $ 32.98
Average realized oil price per Bbl after hedging $ 45.37 $ 28.20
-30-
Information regarding the components of exploration expense:
Three Months Ended March 31,
------------------------------
Summary of Exploration Expense (In millions) 2005 2004
- -------------------------------------------- ---------- ---------
Geological and geophysical expenses $ 2.0 $ 0.7
Exploratory dry holes 0.2 0.2
Overhead and other expenses 4.9 3.7
---------- ---------
$ 7.1 $ 4.6
========== =========
Comparison of Financial Results and Trends between the Quarters ended
March 31, 2005 and 2004
Oil and Gas Production Revenue. Average net daily production increased
13 percent to a record 229.4 MMCFE for the quarter ended March 31, 2005,
compared with 202.8 MMCFE for the quarter ended March 31, 2004. The following
table presents specific components that contributed to the increase in revenue
for the first quarter of 2005 when compared to the first quarter of 2004:
Average Net Daily Oil and Gas Production
Production Revenue Added Costs Added
Added (MMCFE) (Millions) (Millions)
----------------- ------------- -----------
Paggi-Broussard 1 (SM 40%) 11.0 $ 6.8 $ 0.5
Williston Basin Middle Bakken Play 9.7 7.6 0.9
Other wells completed in 2004 and 2005 35.7 20.4 2.1
Goldmark acquisition 4.2 2.2 1.0
Border acquisition 4.6 2.3 0.8
Agate acquisition 5.3 2.3 0.9
Other acquisitions 1.2 0.7 0.2
----------------- ------------- -----------
Total 71.7 $ 42.3 $ 6.4
================= ============= ===========
The increases in this table also reflect the difference in oil and gas
prices received between the comparable periods. Additional production costs
reflect increases resulting from inflation and competition for resources. These
increases are offset by natural declines in production from older properties to
result in the net increase in production between the quarters presented.
Oil and Gas Production Expense. Total production costs increased $8.6
million, or 37 percent, to $32.2 million for the first quarter of 2005, from
$23.5 million in the comparable period of 2004. As noted in the table above,
completed wells and acquisitions in 2004 and 2005 have added $6.4 million of
incremental production costs in 2005. Additionally, we experienced an increase
in value-based production taxes consistent with an increase in revenue from
crude oil and natural gas due to higher prices.
Total oil and gas production costs per MCFE increased $0.28 to $1.56
for 2005, compared with $1.28 for 2004. This increase is comprised of the
following:
o An $0.11 increase in production taxes due to higher revenue from
crude oil in our Rocky Mountain and Permian regions;
o A $0.02 increase in production taxes due to higher revenue from
natural gas in our Mid-Continent region;
-31-
o A $0.06 increase in LOE reflecting a general 7 percent increase
which we had forecast in our budget process that was caused by
competition for resources;
o A $0.02 increase in LOE in our Gulf Coast region reflecting the
effect of resolving certain LOE billing amounts in the first
quarter that is not expected to have an impact in future periods.
o A $0.02 increase due to the start-up activity in our Hanging Woman
Basin; and
o A $0.04 overall increase in LOE relating to workover charges.
General and Administrative. General and administrative expenses
increased $409,000 or seven percent to $6.0 million for the quarter ended March
31, 2005, compared with $5.6 million for the comparable period of 2004. G&A
on a per MCFE basis remained relatively flat between periods as the increase in
G&A expense was offset by a corresponding increase in production.
An increase in our employee count from January 1, 2004, to March 31,
2005, has resulted in an increase in base employee compensation of $305,000
between the first quarter of 2005 and the first quarter of 2004. Accounting fees
increased $158,000 between the same periods. A $1.5 million increase in expense
associated with our net profits plan and our restricted stock plan was offset by
COPAS overhead reimbursements and allocation of G&A to exploration expense.
COPAS overhead reimbursement from operations increased $456,000 due to an
increase in operated well count resulting from our drilling and acquisition
programs. The amount of G&A we allocated to exploration expense increased
$1.2 million due to incentive plan payment increases and increases in our
technical exploration staff.
Change in net profits plan liability. For the quarter ended March 31,
2005, this expense increased to $4.2 million from $2.2 million for 2004. This
increase is due to the performance of individual pools and the effect of a
higher price environment. Adjustments to the liability are subject to estimation
and may change dramatically from year-to-year based on assumptions used for
production rates, reserve quantities, commodity pricing, discount rates, tax
rates, and production costs. Currently, our assessment of these factors results
in our concluding that this expense will be lower for all of 2005 than in 2004.
Interest Expense. Interest expense increased by $456,000 to $1.9
million for 2005 compared to $1.5 million for 2004. The increase reflects
increasing interest rates and an increase in average borrowings under our credit
facility in first quarter of 2005 relative to the same period in the prior year.
Income Taxes. Income tax expense totaled $20.7 million for the first
quarter of 2005 and $13.1 million for the first quarter of 2004, resulting in
effective tax rates of 37.1 percent and 37.9 percent, respectively. The
effective rate change from 2004 reflects changes in the composition of the
highest marginal state tax rates as a result of acquisition and drilling
activity, and other permanent differences including the estimated effect of the
domestic production activities deduction from the recently enacted American Jobs
Creation Act of 2004.
The current portion of the income tax expense in 2005 is $10.4 million
compared to $5.9 million in 2004. These amounts are 50 percent and 45 percent of
the total tax for the respective periods. We increased our 2005 budget for
drilling expenditures over 2004 amounts but have not adjusted this amount during
the first quarter of 2005. Our projections are for larger increases in revenue
due to anticipated production and pricing. We now believe that current taxable
income and the resulting current portion of income tax as a percentage of total
income tax will be higher in 2005 than it was in 2004.
Accounting Matters
We refer you to Note 2 and Note 5 of Part I, Item 1 of this report for
additional information.
-32-
Environmental
St. Mary's compliance with applicable environmental regulations has not
resulted in any significant capital expenditures or materially adverse effects
on our liquidity or results of operations. We believe that we are in substantial
compliance with environmental regulations, and we do not currently expect that
any material expenditures will be required in the foreseeable future. However,
we are unable to predict the impact that future compliance with regulations may
have on future capital expenditures, liquidity and results of operations.
Cautionary Statement 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's
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 under 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, the imprecise nature of oil
and gas 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 2004 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.
-33-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions
"Interest Rate Market Risk" and "Sensitivity Analysis" in Item 2 above and is
incorporated herein by reference.
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
From time to time, we may be involved in litigation relating to claims
arising out of our operations in the normal course of business. As of the date
of this report, no legal proceedings are pending against us that we believe
individually or collectively could have a material adverse effect upon our
financial condition or results of operations.
As previously reported, Nance Petroleum Corporation, a wholly owned
subsidiary, is named along with several other leaseholders and interested
parties as an additional co-defendant in a lawsuit that was originally filed in
the U.S. District Court for the District of Montana on June 12, 2001. The
plaintiff, the Northern Plains Resource Council, Inc.("NPRC"), an environmental
public interest group, sued the U.S. Bureau of Land Management ("BLM"), the U.S.
Secretary of the Interior, the Montana BLM State Director and Fidelity
Exploration & Production Company. The lawsuit seeks the cancellation of all
federal leases related to coalbed methane development in Montana issued by the
BLM since January 1, 1997. This cancellation is sought primarily on the grounds
of an alleged failure of the BLM to comply with federal environmental laws. NPRC
alleges that the environmental impacts of coalbed methane development were not
properly analyzed before the challenged leases were issued. The Montana portion
of our Hanging Woman Basin coalbed methane project contains approximately 74,000
total net acres. The lawsuit potentially affects approximately 47,000 net acres
that are subject to federal leases. Based on information presently available, we
believe that the BLM complied with the applicable environmental laws, and the
District Court agreed by granting the defendants' motion for summary judgment in
December 2003. The court held that the issuance process regarding the federal
leases in question complied with the applicable environmental laws. The
plaintiff appealed this decision, and the Ninth Circuit Court of Appeals
affirmed the decision of the trial court on August 26, 2004. Plaintiff filed a
petition for rehearing that was denied by the reviewing panel by its Order dated
February 10, 2005. The only appeal left for the Plaintiffs is to petition for
certiorari to the U.S Supreme Court. Notwithstanding our success in the lower
court and the appellate court, there is no assurance as to the ultimate outcome
-34-
of the lawsuit, and therefore, there is no assurance that it will not adversely
affect our coalbed methane project. Even if the federal leases in Montana become
unavailable, we are proceeding with this project on non-federal leases in
Wyoming, and we anticipate acquiring additional non-federal leases in Montana
and Wyoming.
ITEM 6. Exhibits
The following exhibits are furnished as part of this report:
Exhibit Description
------- -----------
10.1* Amended and Restated Credit Agreement dated April 7, 2005
among St. Mary Land & Exploration Company, Wachovia Bank,
National Association as Administrative Agent, and the Lenders
party thereto
10.2* Amended and Restated Guaranty Agreement by St. Mary Energy
Company in favor of Wachovia Bank, National Association, as
Administrative Agent, dated April 7, 2005
10.3* Amended and Restated Guaranty Agreement by Nance Petroleum
Corporation in favor of Wachovia Bank, National Association,
as Administrative Agent, dated April 7, 2005
10.4* Amended and Restated Guaranty Agreement by NPC Inc. in favor
of Wachovia Bank, National Association, as Administrative
Agent, dated April 7, 2005
10.5* Amended and Restated Pledge and Security Agreement between
St. Mary Land & Exploration Company and Wachovia Bank,
National Association, as Administrative Agent, dated
April 7, 2005
10.6* Amended and Restated Pledge and Security Agreement between
Nance Petroleum Corporation and Wachovia Bank, National
Association, as Administrative Agent, dated April 7, 2005
10.7* Supplement and Amendment to Deed of Trust, Mortgage, Line of
Credit Mortgage, Assignment, Security Agreement, Fixture
Filing and Financing Statement for the benefit of Wachovia
Bank, National Association, as Administrative Agent,
dated effective as of April 7, 2005
10.8* Deed of Trust to Wachovia Bank, National Association, as
Administrative Agent, dated effective as of April 7, 2005
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.
-35-
SIGNATURES
- ----------
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
May 4, 2005 By: /s/ MARK A. HELLERSTEIN
-----------------------
Mark A. Hellerstein
President and Chief Executive Officer
May 4, 2005 By: /s/ DAVID W. HONEYFIELD
-----------------------
David W. Honeyfield
Vice President - Finance, Secretary
and Treasurer
May 4, 2005 By: /s/ GARRY A. WILKENING
----------------------
Garry A. Wilkening
Vice President - Administration and
Controller
-36-