UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 1999
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Commission File Number 0-20872
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of Registrant as specified in its charter)
Delaware 41-0518430
(State or other Jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1776 Lincoln Street, Suite 1100, Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [ u ] No [ ]
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock as of the latest practicable date.
As of November 11, 1999 the registrant had 11,097,968 shares of Common Stock,
$.01 par value, outstanding.
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY
INDEX
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Part I. FINANCIAL INFORMATION PAGE
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Item 1. Financial Statements (Unaudited)
Consolidated Balance
Sheets - September 30, 1999 and
December 31, 1998 .......................................3
Consolidated Statements of
Operations - Three Months Ended
September 30, 1999 and 1998: Nine Months
Ended September 30, 1999 and 1998 .......................4
Consolidated Statements of
Cash Flows - Nine Months Ended
September 30, 1999 and 1998 .............................5
Notes to Consolidated Financial
Statements - September 30, 1999 .........................7
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations ..........................................10
Part II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K .......................24
Exhibits
--------
27.1 Financial Data Schedule
-2-
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
--------------- --------------
1999 1998
--------------- --------------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 6,594 $ 7,821
Accounts receivable 14,965 17,937
Prepaid expenses and other 775 795
Refundable income taxes 193 391
Deferred income taxes 91 125
--------------- --------------
Total current assets 22,618 27,069
--------------- --------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 259,260 241,021
Unproved oil and gas properties, net of impairment
allowance of $3,095 in 1999 and $5,987 in 1998 28,475 25,588
Other property and equipment 5,119 4,051
--------------- --------------
292,854 270,660
Less accumulated depletion, depreciation, amortization and impairment (133,217) (126,835)
--------------- --------------
159,637 143,825
--------------- --------------
Other assets:
Khanty Mansiysk Oil Corporation receivable and stock 5,110 6,839
Summo Minerals Corporation investment and receivable 1,589 2,869
Restricted cash - 720
Other assets 3,521 3,175
---------------- ---------------
10,220 13,603
---------------- ---------------
$ 192,475 $ 184,497
================ ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 10,733 $ 16,926
Current portion of stock appreciation rights 272 358
---------------- ---------------
Total current liabilities 11,005 17,284
---------------- ---------------
Long-term liabilities:
Long-term debt 25,000 19,398
Deferred income taxes 13,575 11,158
Stock appreciation rights 486 422
Other noncurrent liabilities 932 1,493
---------------- ---------------
39,993 32,471
---------------- ---------------
Commitments and contingencies
---------------- ---------------
Minority interest 464 -
---------------- ---------------
Stockholders' equity:
Common stock, $.01 par value: authorized - 50,000,000 shares: issued and
outstanding - 11,280,768 shares in 1999 and 10,992,447 shares in 1998 113 110
Additional paid-in capital 71,167 67,761
Treasury stock - at cost: 182,800 shares in 1999 and 147,800 shares in 1998 (2,995) (2,470)
Retained earnings 72,511 69,341
Unrealized gain on marketable equity securities-available for sale 217 -
---------------- ---------------
Total stockholders' equity 141,013 134,742
---------------- ---------------
$ 192,475 $ 184,497
================ ===============
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
-3-
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
1999 1998 1999 1998
-------------------------- -------------------------
<S> <C> <C> <C> <C>
Operating revenues:
Oil and gas production $ 19,275 $ 16,645 $ 48,853 $ 55,903
Gain (loss) on sale of proved properties (75) - 39 (14)
Other revenues 703 69 1,026 271
-------- -------- -------- --------
Total operating revenues 19,903 16,714 49,918 56,160
-------- -------- -------- --------
Operating expenses:
Oil and gas production 5,181 4,463 13,135 12,579
Depletion, depreciation and amortization 5,312 5,627 15,995 17,507
Impairment of proved properties 116 6,772 363 8,217
Exploration 1,497 2,924 4,439 9,397
Abandonment and impairment of unproved properties 1,443 2,462 2,243 3,077
General and administrative 1,763 1,245 5,401 5,669
Writedown of Russian convertible receivable - 4,553 - 4,553
Loss in equity investees - 41 58 612
Minority interest and other 548 13 886 105
-------- -------- -------- --------
Total operating expenses 15,860 28,100 42,520 61,716
-------- -------- -------- --------
Income (loss) from operations 4,043 (11,386) 7,398 (5,556)
Nonoperating income and (expense):
Interest income 148 50 786 576
Interest expense (344) (375) (860) (1,129)
-------- -------- -------- --------
Income (loss) before income taxes 3,847 (11,711) 7,324 (6,109)
Income tax expense (benefit) 1,354 (3,984) 2,515 (2,088)
-------- -------- -------- --------
Income (loss) from continuing operations 2,493 (7,727) 4,809 (4,021)
Gain on sale of discontinued operations, net of taxes - - - 34
-------- -------- -------- --------
Net income (loss) $ 2,493 $ (7,727) $ 4,809 $ (3,987)
======== ======== ======== ========
Basic earnings per common share:
Income (loss) from continuing operations $ .22 $ (.71) $ .44 $ (.37)
Gain on sale of discontinued operations - - - -
-------- -------- -------- ---------
Basic net income (loss) per common share $ .22 $ (.71) $ .44 $ (.37)
======== ======== ======== =========
Diluted earnings per common share:
Income (loss) from continuing operations $ .22 $ (.71) $ .44 $ (.37)
Gain on sale of discontinued operations - - - -
-------- -------- -------- ---------
Diluted net income (loss) per common share $ .22 $ (.71) $ .44 $ (.37)
======== ======== ======== =========
Basic weighted average common shares outstanding 11,097 10,937 10,953 10,968
======== ======== ======== =========
Diluted weighted average common shares outstanding 11,228 10,937 10,999 10,968
======== ======== ======== =========
Cash dividend declared per share $ 0.05 $ 0.05 $ 0.15 $ 0.15
======== ======== ======== =========
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
-4-
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
<TABLE>
<CAPTION>
For the Nine Months Ended
September 30,
-------------------------
1999 1998
----------- -----------
<S> <C> <C>
Reconciliation of net income to net cash provided by operating activities:
Net income $ 4,809 $ (3,987)
Adjustments to reconcile net income to net
cash provided by operating activities:
Writedown of Russian convertible receivable - 4,553
(Gain) loss on sale of proved properties (39) 14
Depletion, depreciation and amortization 15,995 17,507
Impairment of proved properties 363 8,217
Exploration 499 4,510
Abandonment and impairment of unproved properties 2,243 3,077
Loss in equity investees 58 612
Deferred income taxes 1,983 (2,094)
Other (604) 256
----------- ----------
25,307 32,665
Changes in current assets and liabilities:
Accounts receivable 3,802 5,882
Prepaid expenses and other 3,141 (1,419)
Accounts payable and accrued expenses (5,926) (663)
Stock appreciation rights (86) 7
----------- ----------
Net cash provided by operating activities 26,238 36,472
----------- ----------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 725 75
Capital expenditures (29,471) (43,294)
Acquisition of oil and gas properties (4,163) (2,132)
Sale of Russian joint venture - 75
Sale of Chelsea Corporation 2,066 -
Investment in and loans to Summo Minerals Corporation (220) (703)
Collections on loan to Summo Minerals Corporation 2,096 -
Receipts from restricted cash 720 -
Investment in Nance Petroleum Corporation 684 -
Other (348) (560)
----------- ----------
Net cash used in investing activities (27,911) (46,539)
----------- ----------
Cash flows from financing activities:
Proceeds from long-term debt 24,550 40,996
Repayment of long-term debt (22,337) (30,987)
Proceeds from sale of common stock 190 173
Repurchase of common stock (525) (2,470)
Dividends paid (1,639) (1,648)
Other 207 -
----------- ----------
Net cash provided by financing activities 446 6,064
----------- ----------
Net decrease in cash and cash equivalents (1,227) (4,003)
Cash and cash equivalents at beginning of period 7,821 7,112
----------- ----------
Cash and cash equivalents at end of period $ 6,594 $ 3,109
=========== ==========
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
-5-
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Continued)
Supplemental schedule of additional cash flow information and noncash
activities:
<TABLE>
<CAPTION>
For the Nine Months Ended
September 30,
-------------------------
1999 1998
----------- -----------
(In thousands)
<S> <C> <C>
Cash paid for interest $ 844 $ 1,077
Cash paid for income taxes 300 490
Cash paid for exploration expenses 4,938 9,231
</TABLE>
In June 1999, the Company acquired Nance Petroleum Corporation and Quanterra
Alpha Limited Partnership for 259,494 shares of the Company's common stock
valued at $3,091,000 together with the assumption of $3,189,000 of Nance
Petroleum Corporation debt. The acquisition was accounted for as a purchase.
The accompanying notes are an integral part
of these consolidated financial statements.
-6-
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
September 30, 1999
Note 1 - Basis of Presentation
The accompanying unaudited condensed consolidated financial statements
have been prepared in accordance with generally accepted accounting principles
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 the Annual Report on Form 10-K/A-3 of St. Mary Land &
Exploration Company and Subsidiaries (the "Company") for the year ended December
31, 1998. In the opinion of Management, all adjustments (consisting of normal
recurring accruals) considered necessary for a fair presentation have been
included. Operating results for the periods presented are not necessarily
indicative of the results that may be expected for the full year.
The accounting policies followed by the Company are set forth in Note 1
to the Company's financial statements in Form 10-K/A-3 for the year ended
December 31, 1998. It is suggested that these financial statements be read in
conjunction with the financial statements and notes included in the Form
10-K/A-3
In September 1999 the Company used full consolidation with minority
interest to reflect the activities of Box Church Gas Gathering, LLC and Roswell,
LLC. Minority interest is the ownership portion of these two entities held by
parties other than the Company.
Note 2 - Investments
In June 1999 the Company participated in a financing package arrangement
with Summo Minerals Corporation ("Summo") and Resource Capital Fund L.P.
("RCF"). The Company received $2,096,000 cash and 17,500,000 Summo warrants in
exchange for reducing Summo's note receivable to $1,400,000 and transferring
4,962,047 Summo common shares to RCF. The loan is secured by Summo's interest in
the Lisbon Valley Project and bears interest at LIBOR plus 2.5%. The warrants
have an exercise price of CDN$0.12 per share, are fully vested and expire on
June 25, 2004. No value has been assigned to the warrants in the financial
statements. The remaining 4,962,046 shares of Summo common stock that the
Company still owns have a recorded cost basis of zero due to the impairment
writedown in the fourth quarter of 1998. Management believes that note
receivable is realizable. The Company continuously analyzes its net investment
in Summo and the effect of persistent depressed copper prices and increased
worldwide copper inventory levels on Summo's stock price.
The transfer of Summo common shares to RCF reduced the Company's
ownership percentage from 37% to 18%. Consequently, the accounting for this
investment was changed from the equity method to the cost method in June 1999.
The Company recorded $58,000 of equity in Summo's losses in 1999 through the
transaction date under the equity method. Under the cost method the Company will
record unrealized gains or losses resulting from the fluctuation in the market
price of Summo's common stock as a component of comprehensive income within the
consolidated statements of stockholders' equity. Unrealized losses can only be
recorded to the extent of the Company's investment, which includes the note
receivable from Summo as well as the Summo common shares and warrants owned. As
a result of changing to the cost method for the investment in Summo, the Company
recorded an unrealized gain of $195,000 in June 1999. The unrealized gain as of
September 30, 1999 was $218,000. This represents the difference in trading value
of the Company's ownership in Summo common stock and the recorded basis of the
common stock.
The June 1999 financing package also resulted in the termination of the
May 1997 agreement which was discussed in the Company's Annual Report on Form
10-K/A-3 for the year ended December 31, 1998.
In June 1999 the Company completed the purchase of Nance Petroleum
Corporation ("Nance") and Quanterra Alpha Limited Partnership for 259,494 shares
of the Company's common stock valued at $3,091,000 together with the assumption
of $3,189,000 of Nance debt. The acquisition included the 26% of Panterra
Petroleum the Company did not previously own as well as certain other
properties. The properties acquired are located in the Williston Basin of
Montana and North Dakota. The acquisition was accounted for as a purchase.
In July 1999 the Company signed an agreement to acquire King Ranch
Energy, Inc. ("KRE") in a merger in which the Company will issue 2,666,252
common shares in exchange for all of the outstanding shares of KRE. The
agreement is subject to approval by shareholders of both the Company and KRE.
In August 1999 the Company sold Chelsea Corporation ("Chelsea"), the
subsidiary that held the Company's common stock investment in Khanty Mansiysk
Oil Corporation ("KMOC"). The Company received proceeds of $2,019,000 net of
transaction costs of $119,000, resulting in a gain of $150,000. The KMOC common
stock was Chelsea's only asset. The Company still holds the convertible
receivable from KMOC that is recorded at its minimum conversion value of
$5,110,000.
Note 3 - Capital Stock
In August 1998 the Company's Board of Directors approved a stock
repurchase program whereby the Company may purchase from time to time, in open
market purchases or negotiated sales, up to one million shares of its common
stock. During the first quarter of 1999 the Company repurchased 35,000 shares of
its common stock under the program at a weighted average price of $15.00 per
share, bringing the total number of shares repurchased under the program to
182,800 at a weighted-average price of $16.38 per share. Management anticipates
that additional purchases of shares by the Company may occur as market
conditions warrant. Such purchases would be funded with internal cash flow and
borrowings under the Company's credit facility.
Note 4 - Income Taxes
Federal income tax expense for 1999 and 1998 differ from the amounts
that would be provided by applying the statutory U.S. Federal income tax rate to
income before income taxes primarily due to Section 29 credits, percentage
depletion, and the effect of state income taxes.
Note 5 - Earnings Per Share
Basic net income per share of common stock is calculated by dividing
net income by the weighted average of common shares outstanding during each
period. Diluted net income per common share of stock is calculated by dividing
net income by the weighted average of outstanding common shares and other
dilutive securities. Dilutive securities of the Company consist entirely of
outstanding options to purchase the Company's common stock. The outstanding
dilutive securities for the three-month period ended September 30, 1999 were
131,317, and the outstanding dilutive securities for the nine-month period ended
September 30, 1999 were 46,817. Because the Company had a loss from continuing
operations for the three-month and nine-month periods ended September 30, 1998,
the outstanding options were antidilutive and were therefore not included in the
earnings per share calculations for these periods. All net income of the Company
is available to common stockholders. Basic and diluted net income per share for
the three months ended September 30, 1999 was $0.22. Basic and diluted net
income per share for the nine months ended September 30, 1999 was $0.44.
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
St. Mary Land & Exploration Company ("St. Mary" or the "Company") was
founded in 1908 and incorporated in Delaware in 1915. The Company is engaged in
the exploration, development, acquisition and production of natural gas and
crude oil with operations focused in five core operating areas in the United
States: the Mid-Continent region; the ArkLaTex region; south Louisiana; the
Williston Basin; and the Permian Basin.
The Company's objective is to build value per share by focusing its
resources within selected basins in the United States where management believes
established acreage positions, long-standing industry relationships and
specialized geotechnical and engineering expertise provide a significant
competitive advantage. The Company's ongoing development and exploration
programs are complemented by less predictable opportunities to acquire producing
properties having significant exploitation potential, to monetize assets at a
premium, and to repurchase shares of its common stock at attractive values.
Internal exploration, drilling and production personnel conduct the
Company's activities in the Mid-Continent and ArkLaTex regions and in south
Louisiana. Prior to June 1, 1999, activities in the Williston Basin were
conducted through Panterra Petroleum ("Panterra"), a general partnership managed
by Nance Petroleum Corporation ("Nance"). The Company owned a 74% interest in
Panterra and Nance owned the remaining 26%. On June 1, 1999, the Company closed
on the acquisition of Nance, and all of the Company's activities in the
Williston Basin are now conducted through Nance as a wholly owned subsidiary of
the Company. Activities in the Permian Basin are primarily contracted through an
oil and gas property management company with extensive experience in the basin.
The Company's presence in south Louisiana includes active management of
its fee lands from which significant royalty income is derived. St. Mary has
encouraged development drilling by its lessees, facilitated the origination of
new prospects on acreage not held by production and stimulated exploration
interest in deeper, untested horizons. The Company's discovery on its fee lands
at South Horseshoe Bayou in early 1997 and the successful confirmation well in
early 1998 proved that significant accumulations of gas are sourced and trapped
at depths below 16,000 feet. In August 1998 one of the wells in the South
Horseshoe Bayou project experienced shut-in production due to mechanical
problems. These mechanical problems and premature water encroachment caused the
Company to reduce the project's proved reserves by 38.8 BCFE. Drilling began in
an untested fault block to the north of the existing production at South
Horseshoe Bayou in the third quarter of 1999.
St. Mary seeks to make selective niche acquisitions of oil and gas
properties that complement its existing operations, offer economies of scale and
provide further development and exploration opportunities based on proprietary
geologic concepts. Management believes that the Company's focus on smaller
negotiated transactions where it has specialized geologic knowledge or operating
experience has enabled it to acquire attractively-priced and under-exploited
properties.
The results of operations include several property acquisitions made
during recent years and their subsequent further development by the Company. In
1996, 1997 and 1998 the Company purchased a series of interests totaling $15.8
million that formed a new core area of focus in the Permian Basin of New Mexico
and west Texas. In late 1998 St. Mary, through Panterra, acquired the interests
of Texaco, Inc. in several fields in the Williston Basin for $2.1 million. In
1997 the Company acquired an 85% working interest in certain Louisiana
properties of Henry Production Company for $3.9 million, and the remaining 15%
working interest in these properties was acquired in the first quarter of 1999.
Through the first three quarters of 1999, St. Mary has acquired additional
interests in the West Cameron Block 39 property located offshore Louisiana and
in various other properties in Louisiana and Oklahoma totaling $3.8 million.
In the second quarter of 1999, the Company acquired Nance and Quanterra
Alpha Limited Partnership for 259,494 shares of St. Mary common stock valued at
$3.1 million and the assumption of $3.2 million in debt. The acquisition was
accounted for as a purchase. This acquisition included Nance's 26% interest in
Panterra that the Company did not previously own.
In July 1999, the Company entered into an agreement to acquire King
Ranch Energy, Inc. ("KRE") in a merger that will be accounted for as a purchase.
The Company will issue 2,666,252 shares of its common stock to shareholders of
KRE and KRE will become a wholly owned subsidiary of St. Mary upon consummation
of the agreement. KRE's properties are located primarily in the Gulf of Mexico
and the onshore Gulf Coast. KRE's 1998 production was 48.8 MMCF equivalent per
day. KRE's reported reserves at December 31, 1998, plus an acquisition made
early in 1999, were 64.7 BCF equivalent and 82% natural gas. The Company has
incurred costs of $403,000 related to its acquisition of KRE. The merger
agreement, which has been unanimously approved by the Boards of Directors of
both companies, is subject to obtaining a favorable vote of the shareholders of
St. Mary and KRE.
The Company reviews its producing properties for impairments when
events or changes in circumstance indicate that an impairment in value may have
occurred. The impairment test compares the expected undiscounted future net
revenues on a field-by-field basis with the related net capitalized costs at the
end of each period. When the net capitalized costs exceed the undiscounted
future net revenues, the cost of the property is written down to "fair value",
which is determined using future net revenues discounted at 15% for the
producing property. Future net revenues are estimated using escalated prices and
include the estimated effects of the Company's hedging contracts in place at
December 31, 1998. Probable reserves are risk-adjusted to recognize their lower
likelihood of occurrence. Through June 30, 1999, all proved reserve categories
at their full estimated value and probable reserves risk-adjusted downward to
15% of their estimated value were used in the impairment test and for
engineering in evaluating the Company's property acquisitions. Beginning in the
third quarter 1999 probable reserve volumes are risk-adjusted by 50% before
applying pricing and cost assumptions to determine future net cash flows. This
calculation may not reflect engineering used by the Company in evaluating
property acquisitions.
The Company pursues opportunities to monetize selected assets at a
premium and as part of its continuing strategy to focus and rationalize its
operations. In December 1998 St. Mary sold a package of non-strategic properties
in Oklahoma to ONEOK Resources Company for $22.2 million and sold its remaining
minor interests in Canada for $1.2 million, realizing a combined pre-tax gain of
$7.7 million.
St. Mary has one principal equity investment, Summo Minerals
Corporation ("Summo"). In the second quarter of 1999, the Company's ownership in
Summo was reduced from 37% to 18%, and the Company now uses the cost method to
account for this investment. Prior to this reduction in ownership, the Company
accounted for its investment in Summo under the equity method and included its
share of the income or loss from this entity in its consolidated results of
operations. The Company recorded $58,000 of equity in Summo's losses in 1999
through the date of the ownership reduction.
In June 1998 the Company's stockholders approved an increase in the
number of authorized shares of the Company's common stock from 15,000,000 to
50,000,000 shares.
In August 1998 the Company's Board of Directors authorized a stock
repurchase program whereby St. Mary may purchase from time-to-time, in open
market transactions or negotiated sales, up to 1,000,000 of its own common
shares. The Company has repurchased a total of 182,800 shares of common stock
under this plan through the third quarter of 1999.
In September 1999 the Company used full consolidation with minority
interest to reflect the activities of Box Church Gathering, LLC and Roswell,
LLC. Minority interest is the ownership portion of these two entities held by
parties other than the Company.
The Company seeks to protect its rate of return on acquisitions of
producing properties by hedging up to the first 24 months of an acquisition's
production at prices approximately equal to those used in the Company's
acquisition evaluation and pricing model. The Company also periodically uses
hedging contracts to hedge or otherwise reduce the impact of oil and gas price
fluctuations on production from each of its core operating areas. The Company's
strategy is to ensure certain minimum levels of operating cash flow and to take
advantage of windows of favorable commodity prices. The Company generally limits
its aggregate hedge position to no more than 50% of its total production. The
Company seeks to minimize basis risk and indexes the majority of its oil hedges
to NYMEX prices and the majority of its gas hedges to various regional index
prices associated with pipelines in proximity to the Company's areas of gas
production. The Company has hedged approximately 24% of its remaining estimated
1999 gas production at an average fixed price of $2.10 per MMBtu, and 32% of its
remaining estimated 1999 oil production at an average fixed price of $17.62 per
Bbl, approximately 16% of its estimated 2000 gas production at an average fixed
price of $2.46 per MMBtu and 19% of its estimated 2000 oil production at an
average fixed price of $18.58 per Bbl and less than 1% of its estimated 2001 gas
and oil production at average fixed prices of $2.46 and $15.76, respectively.
The Company has also purchased options resulting in price collars on
approximately 23% of the Company's remaining estimated 1999 gas production with
price ceilings between $2.90 and $3.00 per MMBtu and price floors between $2.00
and $2.30 per MMBtu and price collars on approximately 21% of its remaining
estimated 1999 oil production with price floors between $15.00 and $16.70 and
price ceilings between $16.85 and $20.90. In 2000 the Company has price collars
on approximately 22% of its estimated gas production with price ceilings between
$2.50 and $2.94 and price floors between $2.00 and $2.30 and approximately 18%
of its estimated oil production with price floors between $15.00 and $18.00 and
price ceilings between $17.75 and $21.00. In 2001 the Company has price collars
on approximately 23% of its estimated gas production with price ceilings between
$2.82 and $2.94 and price floors between $2.30 and $2.35. In 2001 the Company
also has price collars on approximately 9% of its estimated oil production with
a price floor of $16.44 and price ceilings between $20.64 and $20.65.
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, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. All statements, other than statements of
historical facts, included in this Form 10-Q that address activities, events or
developments that the Company expects, believes or anticipates will or may occur
in the future, including such matters as future capital, development and
exploration expenditures (including the amount and nature thereof), drilling of
wells, reserve estimates (including estimates of future net revenues associated
with such reserves and the present value of such future net revenues), future
production of oil and gas, repayment of debt, business strategies, expansion and
growth of the Company's operations, Year 2000 readiness and other such matters
are forward-looking statements. These statements are based on certain
assumptions and analyses made by the Company in light of its experience and its
perception of historical trends, current conditions, expected future
developments and other factors it believes are appropriate in the circumstances.
Such statements are subject to a number of assumptions, risks and uncertainties,
general economic and business conditions, the business opportunities (or lack
thereof) that may be presented to and pursued by the Company, changes in laws or
regulations and other factors, many of which are beyond the control of the
Company. Readers are cautioned that any such statements are not guarantees of
future performance and that actual results or developments may differ materially
from those projected in the forward-looking statements.
Results of Operations
The following table sets forth selected operating data for the periods
indicated:
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
--------------------------- ----------------------------
1999 1998 1999 1998
------------ ------------ ------------- ------------
(In thousands, except BOE data)
<S> <C> <C> <C> <C>
Oil and gas production
Revenues:
Working interests $ 18,504 $ 14,754 $ 46,563 $ 49,626
Louisiana royalties 771 1,891 2,290 6,277
============ ============ ============= ============
Total $ 19,275 $ 16,645 $ 48,853 $ 55,903
============ ============ ============= ============
Net production:
Oil (MBbls) 378 302 974 994
Gas (MMcf) 5,503 6,280 16,247 19,894
============ ============ ============= ============
MBOE 1,295 1,349 3,682 4,310
============ ============ ============= ============
Average sales price (1):
Oil (per Bbl) $ 17.43 $ 11.97 $ 15.07 $ 13.51
Gas (per 2.30 2.07 2.10 2.14
Mcf)
Oil and gas production costs:
Lease operating expense $ 3,668 $ 3,498 $ 9,643 $ 9,458
Production taxes 1,513 965 3,492 3,121
============ ============ ============= ============
Total $ 5,181 $ 4,463 $ 13,135 $ 12,579
============ ============ ============= ============
Additional per BOE data:
Sales price $ 14.88 $ 12.34 $ 13.27 $ 12.97
Lease operating expense 2.83 2.59 2.62 2.19
Production taxes 1.17 .72 .95 .72
------------ ------------ ------------- ------------
Operating margin $ 10.88 $ 9.03 $ 9.70 $ 10.06
Depreciation, depletion and
amortization $ 4.10 $ 4.17 $ 4.34 $ 4.06
Impairment of proved
properties .09 5.02 .10 1.91
General and administrative 1.37 .92 1.47 1.32
</TABLE>
(1) Includes the effects of the Company's hedging activities.
Oil and Gas Production Revenues. Oil and gas production revenues
increased $2.7 million, or 16% to $19.3 million for the third quarter of 1999
from $16.6 million in 1998. Oil production volumes increased 25% and gas
production volumes decreased 12% for the third quarter of 1999 compared with
1998. Average net daily production declined to 14.1 MBOE for the third quarter
of 1999 compared with 14.7 MBOE in 1998. The decline resulted from the
significant loss of production at the South Horseshoe Bayou Field in 1998 and
1999 and the sale of certain Oklahoma properties in December 1998. The average
realized oil price for the third quarter of 1999 increased 46% to $17.43 per
Bbl, while average realized gas prices increased 11% to $2.30 per Mcf, from
their respective 1998 levels.
Oil and gas production revenue decreased $7.0 million or 13% to $48.9
million for the nine months ended September 30, 1999 from $55.9 million in 1998.
Oil production volumes decreased 2% and gas production volumes decreased 18% for
the nine months ended September 30, 1999 compared with 1998. Average net daily
production was 13.5 MBOE for the nine months ended September 30, 1999 compared
with 15.8 MBOE in 1998. The production decrease resulted from the significant
loss of production at the South Horseshoe Bayou Field in 1998 and 1999 and the
sale of certain Oklahoma properties that occurred in late 1998. The average oil
price for the nine months ended September 30, 1999 increased 12% to $15.07 per
Bbl, and gas prices decreased 2% to $2.10 per Mcf, from their respective 1998
levels.
The Company hedged approximately 45% of its oil production for the
third quarter of 1999 or 170 MBbls at an average NYMEX price of $16.15 and
realized a $643,000 decrease in oil revenue or $1.70 per Bbl on these contracts.
The Company did not hedge any of its oil production during the third quarter of
1998. The Company also hedged 53% of its 1999 third quarter gas production or
3.2 million MMBtu at an average indexed price of $2.18 and realized a $1.2
million decrease in gas revenues or $.22 per Mcf from these hedge contracts
compared with a $674,000 increase in gas revenues or $.10 per Mcf in 1998.
Oil and Gas Production Costs. Oil and gas production costs consist of
lease operating expense and production taxes. Total production costs increased
$718,000 or 16% to $5.2 million for the third quarter of 1999 from $4.5 million
in 1998. Total oil and gas production costs per BOE increased 21% to $4.00 for
the third quarter of 1999 from $3.31 in 1998 due to increased workover costs,
reduction in production volumes at South Horseshoe Bayou, increased production
taxes from higher cost oil production and the December 1998 sale of producing
properties in Oklahoma with lower production costs per BOE.
Total production costs increased $556,000 or 4% to $13.1 million for
the nine months ended September 30, 1999 from $12.6 million in 1998. Total oil
and gas production costs per BOE increased 22% to $3.57 in the first nine months
of 1999 from $2.91 in 1998 due to increased workover costs, reduction in
production volumes at South Horseshoe Bayou and the December 1998 sale of
producing properties in Oklahoma with lower production costs per BOE.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion and amortization expense ("DD&A") decreased $315,000 or 6% to $5.3
million for the third quarter of 1999 from $5.6 million in 1998. DD&A expense
per BOE decreased 2% to $4.10 in the third quarter of 1999 from $4.17 in 1998.
This decrease is due to the reduction in volumes produced at South Horseshoe
Bayou and the December 1998 sale of producing properties in Oklahoma with lower
DD&A expense per BOE. The Company recorded a $116,000 impairment of proved oil
and gas properties in New Mexico and Oklahoma for the third quarter of 1999
compared with $6.8 million in 1998. This decrease was due to marginal wells
drilled in Oklahoma and Louisiana in 1998, the adverse effects of low oil prices
in the Williston Basin in 1998 and the Company's unsuccessful 1998 deep test at
its Atchafalaya Bay prospect.
DD&A decreased $1.5 million or 9% to $16.0 million for the nine months
ended September 30, 1999 from $17.5 million in 1998. DD&A expense per BOE
increased 7% to $4.34 in the nine months ended September 30, 1999 from $4.06 in
1998. This increase is due to the reduction in volumes produced at South
Horseshoe Bayou, decreased royalty production from the Fee Lands, the effect of
continued low prices on the Company's oil and gas reserves in the first quarter
of 1999, and the December 1998 sale of producing properties in Oklahoma with
lower DD&A expense per BOE. The Company recorded $363,000 of impairments of
proved oil and gas properties for the nine months ended September 30, 1999
mostly due to an unsuccessful recompletion attempt in the Greensburg prospect in
Louisiana compared with $8.2 million in 1998. This decrease was also due to
marginal wells drilled in Oklahoma and Louisiana in 1998, the adverse effects of
low oil prices in the Williston Basin in 1998 and the Company's unsuccessful
1998 deep test at its Atchafalaya Bay prospect.
Abandonment and impairment of unproved properties decreased $1.1
million or 41% to $1.4 million for the third quarter of 1999 from $2.5 million
in 1998 due to a decrease in abandonment of expired leases in 1999.
Abandonment and impairment of unproved properties decreased $834,000 or
27% to $2.2 million for the nine months ended September 30, 1999 from $3.1
million in 1998 due to a decrease in abandonment of expired leases in 1999.
Exploration. Exploration expense decreased $1.4 million or 49% to $1.5
million for the third quarter of 1999 from $2.9 million in 1998. The decrease
results from improved exploratory drilling results in 1999.
Exploration expense decreased $5.0 million or 53% to $4.4 million for
the nine months ended September 30, 1999 from $9.4 million in 1998. The decrease
results from nonrecurring delay rental payments for the Atchafalaya project in
1998 and improved exploratory drilling results in 1999.
General and Administrative. General and administrative expenses
increased $518,000 or 42% to $1.8 million in the third quarter of 1999 from $1.2
million in 1998. This increase was due to an increase in compensation expense
and a reduction in overhead reimbursements from outside interest owners in
properties operated by the Company.
General and administrative expenses decreased $268,000 or 5% to $5.4
million for the nine months ended September 30, 1999 from $5.7 million in 1998.
Compensation expense decreased $924,000 due to a decrease in bonus expense in
1999. This decrease in compensation expense was partially offset by a $581,000
reduction in overhead reimbursements from outside interest owners in properties
operated by the Company.
Minority Interest and Other Operating Expenses. Other operating
expenses consist of minority interest and legal expenses in connection with
ongoing oil and gas activities. This expense increased $535,000 to $548,000 for
the third quarter of 1999 from $13,000 in 1998. This increase was due to
increased activity in the pending litigation that seeks to recover damages from
the drilling contractor in connection with the St. Mary Land & Exploration No. 1
well at South Horseshoe Bayou and a $259,000 adjustment for minority interest.
Other operating expenses increased $781,000 to $886,000 for the nine
months ended September 30, 1999 from $105,000 in 1998. This increase was due to
increased activity in the pending litigation that seeks to recover damages from
the drilling contractor in connection with the St. Mary Land & Exploration No. 1
well at South Horseshoe Bayou and a $259,000 adjustment for minority interest.
Equity in Loss of Summo Minerals Corporation. The Company accounted for
its investment in Summo under the equity method and included its share of
Summo's losses in its results of operations until the Company's ownership was
reduced to 18% in June 1999. Consequently, the Company now accounts for its
investment in Summo under the cost method. The Company did not record equity in
the net loss of Summo for the third quarter of 1999 compared with a loss of
$41,000 in 1998. This decrease was due to the change to the cost method.
The Company recorded equity in the net loss of Summo of $58,000 for the
nine months ended September 30, 1999 compared with $612,000 in 1998. This
decrease was due to Summo's write-off of its investment in its Cashin and
Champion properties in the second quarter of 1998 and the change to the
investment method.
Non-Operating Income and Expense. Net non-operating expense decreased
$129,000 to $196,000 in the third quarter of 1999 from $325,000 in 1998 due to
decreased long-term debt during 1999 compared to 1998 and recognition of
interest income from loans made to Summo.
Net non-operating expense decreased $479,000 to $74,000 for the nine
months ended September 30, 1999 from $553,000 in 1998 due to decreased long-term
debt during 1999 compared to 1998 and recognition of interest income from loans
made to Summo.
Income Taxes. Income tax expense totaled $1.4 million in the third
quarter of 1999 compared with an income tax benefit of $4.0 million in 1998,
resulting in effective tax rates of 35.2% and 34%, respectively. The increased
expense reflects higher net income from operations before income taxes for 1999
resulting from increased oil and gas prices. The increased rate reflects a lower
impact on higher net income from Section 29 credits and percentage depletion in
1999.
Income tax expense was $2.5 million for the nine months ended September
30, 1999 compared with an income tax benefit of $2.1 million in 1998, resulting
in effective tax rates of 34.3% and 34.2%, respectively. The increased expense
reflects higher net income from operations before income taxes for 1999
resulting from higher oil and gas prices. The rates reflect the offsetting
impact of Section 29 credits and percentage depletion in 1999 for the net income
and the 1998 net loss amounts reported.
Net Income. Net income for the third quarter of 1999 increased $10.2
million or 132% to $2.5 million compared with a net loss of $7.7 million in
1998. A 16% increase in oil and gas revenues caused by increases in oil and gas
prices combined with a $1.4 million decrease in exploration expense, a $6.6
million decrease in proved property impairments and the $4.6 million 1998
write-down of the Russian convertible receivable were offset by a $5.3 million
increase in income tax expense.
Net income for the nine months ended September 30, 1999 increased $8.8
million or 221% to $4.8 million compared with a net loss of $4.0 million in
1998. A 13% decrease in oil and gas revenues caused by a reduction in produced
volumes and the $4.6 million 1998 writedown of the Russian convertible
receivable were partially offset by a $10.2 million decrease in DD&A and
impairment of proved and unproved properties and a $5.0 million decrease in
exploration expense.
Liquidity and Capital Resources
The Company's primary sources of liquidity are the cash provided by
operating activities, debt financing, sales of non-strategic properties and
access to the capital markets. The Company's cash needs are for the acquisition,
exploration and development of oil and gas properties and for the payment of
debt obligations, trade payables and stockholder dividends. The Company
generally finances its exploration and development programs from internally
generated cash flow, bank debt and cash and cash equivalents on hand. The
Company continually reviews its capital expenditure budget based on changes in
cash flow and other factors.
Cash Flow. The Company's net cash provided by operating activities
decreased $10.3 million or 28% to $26.2 million for the nine months ended
September 30, 1999 compared with $36.5 million in 1998. Revenues decreased by
$7.0 million due to decreased production at South Horseshoe Bayou and decreased
production in Oklahoma from the sale of producing properties. Additionally,
adjustments for non-cash expenses decreased due to lower DD&A of $1.5 million,
impairment of proved properties of $7.9 million, a decrease in accounts
receivable of $2.0 million along with an increase in deferred income taxes of
$4.1 million.
Exploratory dry hole costs are included in cash flows from investing
activities even though these costs are expensed as incurred. If exploratory dry
hole costs had been included in operating cash flows, the net cash provided by
operating activities would have been $25.7 million and $32.0 million in 1999 and
1998, respectively.
Net cash used in investing activities decreased $18.6 million or 40% to
$27.9 million for the nine months ended September 30, 1999 compared with $46.5
million in 1998. The decrease is due to a $13.6 million decrease in capital
expenditures, a $1.3 million increase resulting from acquisitions, a $2.0
million increase from the sale of Chelsea Corporation and a $2.6 million
decrease resulting from the reduction of the Company's investment in Summo in
the first half of 1999. Total capital expenditures, including acquisitions of
oil and gas properties, in the first nine months of 1999 decreased $11.8 million
or 26% to $33.6 million compared with $45.4 million in the same period of 1998.
If exploratory dry hole costs had been included in operating cash flows
rather than in investing cash flows, net cash used in investing activities would
have been $27.4 million and $42.0 million in 1999 and 1998, respectively.
A portion of the proceeds from sales of oil and gas properties in 1998
was applied to acquisitions of oil and gas properties in 1999 under tax-free
exchanges. In a tax-free exchange of properties the tax basis of the sold
property carries over to the acquired property for tax purposes. Gains or losses
for tax purposes are recognized by amortization of the lower tax basis of the
property throughout its remaining life or when the acquired property is sold or
abandoned.
Net cash provided by financing activities decreased $5.6 million or 93%
to $446,000 for the nine months ended September 30, 1999 compared with $6.1
million in 1998. The decrease was due to a reduction of long-term debt in 1999
compared with an increase in long-term debt in 1998.
The Company had $6.6 million in cash and cash equivalents and had
working capital of $11.6 million as of September 30, 1999 compared with $7.8
million in cash and cash equivalents and working capital of $9.8 million as of
December 31, 1998. The reduction in cash and cash equivalents is the result of
capital expenditures.
Credit Facility. On June 30, 1998, the Company entered into a long-term
revolving credit agreement with a maximum loan amount of $200.0 million. The
lender may periodically re-determine the aggregate borrowing base depending upon
the value of the Company's oil and gas properties and other assets. In May 1999
the borrowing base was reduced $25.0 million by the lender to $80.0 million as a
result of reduced reserve pricing and the write-down of South Horseshoe Bayou
reserves. The accepted borrowing base was $40.0 million at September 30, 1999.
The credit agreement has a maturity date of December 31, 2005, and includes a
revolving period that matures on December 31, 2000. The Company can elect to
allocate up to 50% of available borrowings to a short-term tranche due in 364
days. The Company must comply with certain covenants including maintenance of
stockholders' equity at a specified level and limitations on additional
indebtedness. As of September 30, 1999, and December 31, 1998, $25.0 million and
$10.5 million, respectively, was outstanding under this credit agreement. These
outstanding balances accrue interest at rates determined by the Company's debt
to total capitalization ratio. During the revolving period of the loan, loan
balances accrue interest at the Company's option of either (a) the higher of the
Federal Funds Rate plus 1/2% or the prime rate, or (b) LIBOR plus 1/2% when the
Company's debt to total capitalization is less than 30%, up to a maximum of
either (a) the higher of the Federal Funds Rate plus 5/8% or the prime rate plus
1/8%, or (b) LIBOR plus 1-1/4% when the Company's debt to total capitalization
is equal to or greater than 50%.
Panterra, in which the Company had a 74% general partnership interest,
maintained a separate credit facility with a $21.0 million borrowing base as of
December 31, 1998. Outstanding borrowings under this separate credit facility
were $12.0 million as of December 31, 1998. St. Mary's portion of the December
31, 1998 outstanding balance was $8.9 million. The Company used its primary
credit facility to retire the balance due on the Nance credit facility.
Common Stock. In June 1998 the Company's stockholders approved an
increase in the number of authorized shares of the Company's common stock from
15,000,000 to 50,000,000 shares.
In August 1998 the Company's Board of Directors authorized a stock
repurchase program whereby St. Mary may purchase from time-to-time, in open
market transactions or negotiated sales, up to 1,000,000 of its common shares.
During 1998 the Company repurchased a total of 147,800 shares of its common
stock under the program for $2.5 million at a weighted-average price of $16.71
per share. The Company repurchased 35,000 additional shares for $15.00 per share
during the first nine months of 1999. Management anticipates that additional
purchases of shares by the Company may occur as market conditions warrant. Such
purchases will be funded with internal cash flow and borrowings under the
Company's credit facility.
In June 1999 the Company completed the purchase of Nance and Quanterra
Alpha Limited Partnership for 259,494 shares of the Company's common stock
valued at $3.1 million and the assumption of $3.2 million of Nance debt.
Capital and Exploration Expenditures. The Company's expenditures for
exploration and development of oil and gas properties and acquisitions are the
primary use of its capital resources.
Outlook. The Company believes that its existing capital resources, cash
flows from operations and available borrowings are sufficient to meet its
anticipated capital and operating requirements for 1999.
The Company generally allocates approximately 85% of its capital budget
to low to moderate-risk exploration, development and niche acquisition programs
in its core operating areas. The remaining portion of the Company's capital
budget is directed to higher-risk, large exploration ideas that have the
potential to increase the Company's reserves by 25% or more in any single year.
The Company anticipates incurring approximately $95.0 million for
capital and exploration expenditures in 1999 with $33.0 million allocated for
ongoing exploration and development in its core operating areas, $10.0 million
for large-target, higher-risk exploration and development projects, and $52.0
million for acquisitions of producing properties. These anticipated expenditures
include the acquisition of Nance through the issuance of St. Mary common stock
and the assumption of Nance debt. These numbers also assume that the KRE
acquisition closes during 1999 through the issuance of St. Mary common stock.
Anticipated ongoing exploration and development expenditures for each
of the Company's core areas include $16.0 million in the Mid-Continent region,
$6.5 million in the ArkLaTex region, $4.5 million in the Williston Basin and
$6.0 million allocated within the Permian Basin and south Louisiana regions.
The results of operations also include the results of the Company's
large-target exploration ideas. During the first half of 1999 two confirmed
wells were drilled at the West Cameron Block 39 project. The Company has several
prospects in its pipeline of large-target exploration ideas. Drilling was
completed at the Stallion project in July 1999. The well began producing into
permanent facilities in October 1999 at a rate of 9.8 MMcf per day. The Company
has spud two additional significant tests in the third quarter of 1999 at its
South Horseshoe Bayou and North Parcperdue projects in south Louisiana.
The amount and allocation of future capital and exploration
expenditures will depend upon a number of factors including the number of
available acquisition opportunities, the Company's ability to assimilate such
acquisitions, the impact of oil and gas prices on investment opportunities, the
availability of capital and borrowing capability and the success of its
development and exploratory activity which could lead to funding requirements
for further development.
The Company continuously evaluates opportunities in the marketplace for
oil and gas properties and, accordingly, may be a buyer or a seller of
properties at various times. St. Mary will continue to emphasize smaller niche
acquisitions utilizing the Company's technical expertise, financial flexibility
and structuring experience. In addition, the Company is also actively seeking
larger acquisitions of assets or companies that would afford opportunities to
expand the Company's existing core areas, to acquire additional geoscientists or
to gain a significant acreage and production foothold in a new basin within the
United States. The acquisition of KRE, which is anticipated to close in the
fourth quarter of 1999, is an example of this strategy.
The persistence of depressed commodity prices and increased worldwide
inventory levels of copper have caused Summo's stock price to decline.
Management believed that this stock price decline was not temporary and that its
value was impaired. Consequently, the Company wrote down its net investment in
Summo to net realizable value in the fourth quarter of 1998. Management believes
the recorded net investment is recoverable. The Company, through a subsidiary,
now owns 4.96 million shares or 17.7% of Summo.
In June 1999, the Company participated in a financing package
arrangement with Summo Minerals Corporation ("Summo") and Resource Capital Fund
L.P. ("RCF"). This package resulted in the Company receiving $2.1 million in
exchange for reducing Summo's note receivable to $1.4 million and transferring
4.96 million Summo shares to RCF. Also as part of the arrangement, the Company
was granted 17.5 million warrants to purchase Summo common stock with an
exercise price of CDN$0.12 per share that are fully vested and expire on June
25, 2004. No value has been assigned to the warrants in the financial
statements. The proceeds received from RCF were applied to the outstanding
principle balance of the Summo note receivable and to accrued interest resulting
in a remaining net book value of $1,589,000, which management believes is
realizable. The loan is secured by Summo's interest in the Lisbon Valley Project
and bears interest at LIBOR plus 2.5%. The Company continuously analyzes its net
investment in Summo and the effect of persistent depressed copper prices and
increased worldwide copper inventory levels on Summo's stock price.
Future development and financial success of the Lisbon Valley Project
are largely dependent on the market price of copper, which is determined in
world markets and is subject to significant fluctuations.
Impact of the Year 2000 Issue. The following Year 2000 statements
constitute a Year 2000 Readiness Disclosure within the meaning of the Year 2000
Information and Readiness Disclosure Act of 1998.
The Year 2000 Issue is the result of computer programs and embedded
computer chips being written or manufactured using two digits rather than four,
or other methods, to define the applicable year. Computer programs and embedded
chips that are date-sensitive may recognize a date using "00" as the year 1900
rather than the year 2000. This could result in a system failure or
miscalculations causing disruptions of operations, including, among other
things, a temporary inability to process transactions, operate equipment or
engage in normal business activities. Failure to correct a material Year 2000
compliance problem could result in an interruption in, or inability to conduct
normal business activities or operations. Such failures could materially and
adversely affect the Company's results of operations, cash flow and financial
condition.
The Company's approach to determining and mitigating the impact on the
Company of Year 2000 compliance issues is comprised of five phases:
i) Review and assessment of all internal information technology (IT) systems
and significant non-IT systems for Year 2000 compliance;
ii) Identify and prioritize systems with Year 2000 compliance issues; iii)
Repair or replace and test non-Year 2000 compliant systems;
iv) Survey and assess the Year 2000 readiness of the Company's significant
vendors, suppliers, purchasers and transporters of oil and natural gas;
and,
v) Design and implement contingency plans for those systems, if any, that
cannot be made Year 2000 compliant before December 31, 1999.
The Company completed phases i) and ii) of its plan by August 1998, and
has identified the systems requiring repair or replacement in order to be Year
2000 compliant. This review and assessment was completed using outside
consultants as well as Company personnel. The Company determined that of its
major systems, the software it uses for reservoir engineering, its telephone
system, a significant number of the personal computers used by Company personnel
and the computer system used by Panterra had to be updated or replaced.
Phase iii) of the Company's plan of repair and replacement of non-Year
2000 compliant systems is 100% complete. The telephone system and personal
computers have been replaced with Year 2000 compliant hardware and software as
part of the Company's ongoing upgrade program. The Company implemented a Year
2000 compliant release of the reservoir engineering system in the third quarter
of 1999. In the fourth quarter of 1998 Panterra licensed a Year 2000 compliant
system and converted to the new system in January 1999. Nance is now using that
system. The systems that have been either upgraded or replaced have been tested
to confirm their Year 2000 compliance. Testing of the Company's primary
accounting, lease records and production accounting system was performed during
the second quarter of 1999 as planned and confirmed the system to be Year 2000
compliant. The Company presently believes that other less significant IT and
non-IT systems can be upgraded to mitigate any Year 2000 issues with
modifications to existing software or conversions to new systems. Modifications
or conversions to new systems for the less significant systems, if not completed
timely, would have neither a material impact on the operations of the Company
nor on its results of operations.
Under phase iv) of the plan, the Company initiated formal
communications with its significant vendors, suppliers and purchasers and
transporters of oil and natural gas to determine the extent to which the Company
is vulnerable to those third parties' failures to remediate their own Year 2000
issues. The Company received responses from over 50% of these vendors and they
represent the Company's critical business partners and suppliers. Responses
received to date confirm that respondents will be Year 2000 compliant on a
timely basis. Management considers this phase complete. However, there can be no
assurance that the systems of these third parties will be converted timely, or
that a failure to remediate Year 2000 compliance issues by another company would
not have a material adverse effect on the Company.
Phase v) of the Company's Year 2000 plan, the design and implementation
of contingency plans for those systems, if any, that cannot be made Year 2000
compliant before December 31, 1999, is complete.
Through September 30, 1999, the Company has spent approximately
$450,000 on its Year 2000 efforts. This includes the costs of consultants as
well as the cost of repair or replacement of non-compliant hardware and software
systems. No additional costs to complete the Company's plan are anticipated. The
Company has not specifically tracked its internal costs of addressing the Year
2000 issue. However, management does not believe these costs to be material.
The Company has not completed a comprehensive analysis of the
operational problems and costs that would be reasonably likely to result from
the Company or its significant third parties' failure to timely complete efforts
to remediate Year 2000 issues. Potential "worst case" impacts could include the
inability of the Company to deliver its production to, or receive payment from,
third parties purchasing or transporting the Company's production; the inability
of third party vendors to provide needed materials or services to the Company
for ongoing or future exploration, development or producing operations; and the
inability of the Company to execute financial transactions with its banks or
third parties whose systems fail or malfunction.
The Company currently has no reason to believe that any of these
contingencies will occur or that its principal vendors, customers and business
partners will not be Year 2000 compliant. However, there can be no assurance
that the Company will be able to identify and correct all Year 2000 problems or
implement a satisfactory contingency plan. Therefore, there can be no assurance
that the Year 2000 issue will not materially impact the Company's results of
operations or adversely affect its relationships with vendors, customers and
other business partners.
Accounting Matters
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," effective for all fiscal
quarters of fiscal years beginning after June 15, 1999. The Statement requires
companies to report all derivatives at fair value as either assets or
liabilities and bases the accounting treatment of the derivatives on the reasons
an entity holds the instrument. The Company is currently reviewing the effects
this Statement will have on the financial statements in relation to the
Company's hedging activities.
In June 1999 the FASB issued SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities--Deferral of the Effective Date of FASB
Statement No. 133--An Amendment of FASB Statement No. 133." SFAS No. 137 delayed
the effective date of the requirements of SFAS No. 133 to all fiscal quarters of
fiscal years beginning after June 15, 2000.
Effects of Inflation and Changing Prices
Within the United States inflation has had a minimal effect on the
Company. The Company cannot predict the future extent of any such effect.
The Company's results of operations and cash flows are affected by
material changes in oil and gas prices. Oil and gas prices are strongly impacted
by North American influences on gas and global influences on oil in relation to
supply and demand for petroleum products. Oil and gas prices are further
impacted by the quality of the oil and gas to be sold and the location of the
Company's producing properties in relation to markets for the products. Oil and
gas price increases or decreases have a corresponding effect on the Company's
revenues from oil and gas sales. Oil and gas prices also affect the prices
charged for drilling and related services. If oil and gas prices increase, there
could be a corresponding increase in the cost to the Company for drilling and
related services, although offset by an increase in revenues. Also, as oil and
gas prices increase, the cost of acquisitions of producing properties increases,
which could limit the number and accessibility of quality properties on the
market.
Material changes in oil and gas prices affect the current and future
value of the Company's estimated proved reserves and the borrowing capability of
the Company, which is largely based on the value of such proved reserves. Oil
and gas price changes have a corresponding effect on the value of the Company's
estimated proved reserves and the available borrowings under the Company's
credit facility.
The last half of 1998 and most of the first quarter of 1999 were
characterized by historically low oil prices and weakening gas markets. Capital
left the oil and gas industry and caused a significant decrease in the number of
working drilling rigs. Consequently, in early 1999 there was an abundance of
available drilling rigs, personnel, supplies and services with a corresponding
reduction of costs. Oil and gas prices have increased from December 31, 1998
levels during the second and third quarters of 1999. If prices continue to
increase, there could be a return to shortages and a corresponding increase in
the costs to the Company of exploration, drilling and production of oil and gas.
Financial Instrument Market Risk
The Company holds derivative contracts and financial instruments that
have cash flow and net income exposure to changes in commodity prices or
interest rates. Financial and commodity-based derivative contracts are used to
limit the risks inherent in some crude oil and natural gas price changes that
have an effect on the Company. In prior years the Company has occasionally
hedged interest rates, and may do so in the future should circumstances warrant.
The Company's Board of Directors has adopted a policy regarding the use
of derivative instruments. This policy requires every derivative used by the
Company to relate to underlying offsetting positions, anticipated transactions
or firm commitments. It prohibits the use of speculative, highly complex or
leveraged derivatives. Under the policy, the Chief Executive Officer and Vice
President of Finance must review and approve all risk management programs that
use derivatives. The Company's Board of Directors periodically reviews these
programs.
Commodity Price Risk. The Company uses various hedging arrangements to
manage the Company's exposure to declines in prices from its natural gas and
crude oil production. These hedging arrangements have the effect of locking in
for specified periods, at predetermined prices or ranges of prices, the prices
the Company will receive for the volumes to which the hedge relates.
Consequently, while these hedging arrangements are structured to reduce the
Company's exposure to decreases in prices associated with the hedged commodity,
they also limit the benefit the Company might otherwise receive from price
increases associated with the hedged commodity. A hypothetical 10% change in the
quarter-end market prices of commodity-based swaps and futures contracts on a
notional amount of 29 million MMBtu would have caused a potential $298,000
change in net income before income taxes for the Company for gas contracts in
place on September 30, 1999. A 10% change in the quarter-end market prices of
commodity-based swaps and future contracts on a notional amount of 1,260 MBbls
would have caused a potential $779,000 change in net income before income taxes
for the Company for oil contracts in place on September 30, 1999. These
hypothetical changes were discounted to present value using a 7.5% discount rate
since the latest expected maturity date of some of the swaps and futures
contracts is greater than one year from the reporting date. The derivative gain
or loss effectively offsets the loss or gain on the underlying commodity
exposures that have been hedged. The fair values of the swaps are estimated
based on quoted market prices of comparable contracts and approximate the net
gains or losses that would have been realized if the contracts had been closed
out at quarter end. The fair values of the futures are based on quoted market
prices obtained from the New York Mercantile Exchange.
Interest Rate Risk. Market risk is estimated as the potential change in
fair value resulting from an immediate hypothetical one percentage point
parallel shift in the yield curve. A sensitivity analysis presents the
hypothetical change in fair value of those financial instruments held by the
Company at September 30, 1999, which are sensitive to changes in interest rates.
For fixed-rate debt, interest rate changes affect the fair market value but do
not impact results of operations or cash flows. Conversely for floating rate
debt, interest rate changes generally do not affect the fair market value but do
impact future results of operations and cash flows, assuming other factors are
held constant. The carrying amount of the Company's floating rate debt
approximates its fair value. At September 30, 1999, the Company had floating
rate debt of $25.0 million and had no fixed rate debt. Assuming constant debt
levels, the results of operations and cash flows impact for the remainder of the
year resulting from a one percentage point change in interest rates would be
approximately $63,000 before taxes.
<PAGE>
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit Description
27.1 Financial Data Schedule
(b) One report on Form 8-K dated July 27, 1999 regarding
the merger agreement between the Company and King
Ranch Energy was filed during the third quarter of
1999.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
November 15, 1999 By /s/ MARK A. HELLERSTEIN
Mark A. Hellerstein
President and Chief Executive Officer
November 15, 1999 By /s/ RICHARD C. NORRIS
Richard C. Norris
Vice President - Finance, Secretary
and Treasurer
November 15, 1999 By /s/ GARRY A. WILKENING
Garry A. Wilkening
Vice President - Administration and
Controller
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