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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 1999.
OR
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.
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)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)
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 if disclosure of delinquent filer pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of 13,348,976 shares of voting stock held
by non-affiliates of the Registrant, based upon the closing sale price of the
common stock on March 2, 2000 of $26.875 per share as reported on the Nasdaq
National Market System, was $358,753,730. Shares of common stock held by each
director and executive officer and by each person who owns 10% or more of the
outstanding common stock or who is otherwise believed by the Company to be in a
control position have been excluded. This determination of affiliate status is
not necessarily a conclusive determination for other purposes.
As of March 2, 2000, the registrant had 13,761,376 shares of common
stock outstanding.
DOCUMENT INCORPORATED BY REFERENCE
The information required by Part III (Items 10, 11, 12 and 13) is
incorporated by reference from Registrant's definitive proxy statement relating
to its 2000 annual meeting of stockholders to be filed no later than April 30,
2000.
<PAGE>
TABLE OF CONTENTS
ITEM PAGE
PART I
ITEM 1. BUSINESS............................................................1
Background......................................................1
Business Strategy...............................................1
Significant Developments Since December 31, 1998................3
ITEM 2. PROPERTIES..........................................................4
Domestic Operations.............................................4
International Operations.......................................10
Acquisitions...................................................10
Reserves.......................................................11
Production.....................................................12
Productive Wells...............................................12
Drilling Activity..............................................13
Domestic Acreage...............................................14
Non-Oil and Gas Activities.....................................14
Competition....................................................15
Markets and Major Customers....................................15
Government Regulations.........................................15
Title to Properties............................................16
Operational Hazards and Insurance..............................17
Employees and Office Space.....................................17
Glossary.......................................................17
ITEM 3. LEGAL PROCEEDINGS..................................................20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................20
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED SECURITY HOLDERS MATTERS...................................21
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA...............................22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS................................24
Overview.......................................................24
Results of Operations..........................................27
Liquidity and Capital Resources................................30
Accounting Matters.............................................35
Effects of Inflation and Changing Prices.......................35
Financial Instrument Market Risk...............................36
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TABLE OF CONTENTS
(Continued)
ITEM PAGE
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Included within the content of ITEM 7.)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........................38
ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE................................38
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................38
ITEM 11. EXECUTIVE COMPENSATION.............................................38
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT.....................................................38
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.....................38
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K................................................39
ii
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PART I
ITEM 1. BUSINESS
Background
St. Mary Land & Exploration Company, together with its subsidiaries
("St. Mary" or the "Company"), is an independent energy company engaged in the
exploration, development, acquisition and production of natural gas and crude
oil. St. Mary was founded in 1908 and was incorporated in Delaware in 1915. St.
Mary's operations are focused in five core operating areas in the United States:
the Mid-Continent region; the ArkLaTex region; onshore Gulf Coast and offshore
Gulf of Mexico; the Williston Basin; and the Permian Basin. As of December 31,
1999, the Company had estimated net proved reserves of approximately 18.9 MMBbls
of oil and 207.6 Bcf of natural gas, or an aggregate of 321 BCFE (84% proved
developed, 65% gas) with a PV-10 value before tax of $351 million.
From January 1, 1995, through December 31, 1999, the Company added
estimated net proved reserves of 398.4 BCFE at an average finding cost of $.81
per MCFE. The Company's average annual production replacement was 294% during
this five-year period.
In 1999 production declined 6% to a total of 31.1 BCFE, or average
daily production of 85.2 MMcf per day, as a result of property sales and the
loss of production from the St. Mary No. 3 in S. Horseshoe Bayou. The Company's
2000 capital budget of approximately $105.0 million includes $60.5 million for
ongoing development and exploration programs in the core operating areas, $32.5
million for niche acquisitions of oil and gas properties and $12.0 million for
higher-risk, large-target exploration prospects.
The Company's principal offices are located at 1776 Lincoln Street,
Suite 1100, Denver, Colorado 80203, and its telephone number is (303) 861-8140.
Business Strategy
St. Mary's objective is to build stockholder value through consistent
economic growth in reserves and production and the resulting increase in net
asset value per share, cash flow per share and earnings per share. A focused and
balanced program of low to medium-risk exploration and development and niche
acquisitions in each of its core operating areas is designed to provide the
foundation for steady growth while the Company's portfolio of higher-risk,
large-target exploration prospects has the potential to significantly increase
the Company's reserves and production. All investment decisions are measured and
ranked by their risk-adjusted impact on per share value. The Company does not
pursue growth solely for the sake of growth.
St. Mary's long-term corporate strategy focuses on growing value per
share, and not necessarily the absolute size of the Company. Management believes
that independents with equity market capitalizations between $300 and $600
million are best positioned to capitalize on opportunities in the domestic E&P
sector and therefore to realize superior returns for their stockholders.
Companies in this size range have critical mass and are able to sustain quality
exploration, development and niche acquisition programs that have a significant
impact on stockholder value.
The Company will pursue opportunities to monetize selected assets at a
premium and to repurchase shares at attractive values in order to enhance the
growth in St. Mary's per share value while maintaining the market capitalization
of the Company within an optimal size range. St. Mary also will continue to
focus its resources within selected basins in the U.S. where the Company's
expertise in geology, geophysics and drilling and completion techniques provides
competitive advantages.
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<PAGE>
Principal elements of the Company's strategy are as follows:
Focused Geographic Operations. The Company focuses its exploration,
development and acquisition activities in five core operating areas where it has
built a balanced portfolio of proved reserves, development drilling
opportunities and higher-risk large-target exploration prospects. The Company
believes that its extensive leasehold position is a strategic asset. Since 1990
St. Mary has expanded its technical and operating staff and increased its
drilling, production and operating capabilities. Senior technical managers, each
possessing over 20 years of experience, head up regional technical offices
located near core properties and are supported by centralized administration in
the Company's Denver office. St. Mary has knowledgeable and experienced
professionals at every level of the organization. St. Mary believes that its
long-standing presence, its established networks of local industry relationships
and its extensive acreage holdings in its core operating areas provide a
significant competitive advantage. Additionally, the Company believes that it
can continue to expand its operations without the need to proportionately
increase the number of employees.
Exploitation and Development of Existing Properties. The Company uses
its comprehensive base of geological, geophysical, engineering and production
experience in each of its core operating areas to source prospects for its
ongoing, low to medium-risk development and exploration programs. St. Mary
conducts detailed geologic studies and uses an array of technologies and tools
including 3-D seismic imaging, hydraulic fracturing and reservoir stimulation
techniques, and specialized logging tools to maximize the potential of its
existing properties. During 1999 the Company participated in 134 gross wells
with an 85% success rate and 33 recompletions with a 91% success rate.
Large-Target Prospects. The Company generally invests approximately 15%
of its annual capital budget in higher-risk, large-target exploration projects.
The Company's strategy is to test four or more of these large exploration
prospects each year which in total have the potential, if successful, to
increase the Company's net reserves by 25% or more. St. Mary seeks to invest in
a diversified mix of large-target exploration projects and generally limits its
capital exposure by participating with other experienced industry partners. St.
Mary plans to test several large-target prospects in the Gulf Region and Texas
during 2000.
Selective Acquisitions. The Company 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 focus on smaller, negotiated transactions where the Company has specialized
geologic knowledge or operating experience has enabled it to acquire
attractively priced and under-exploited properties. In addition, the Company
will pursue corporate acquisitions if they can be made on an accretive basis.
Examples of this type of acquisition include the Nance Petroleum Corporation
("Nance Petroleum" or "Nance") and King Ranch Energy, Inc. ("King Ranch Energy"
or "KRE") acquisitions, both completed in 1999 for stock.
St. Mary's strong balance sheet positions the Company in 2000 to
exploit acquisition opportunities arising throughout the upstream oil and gas
sector. Many companies are expected to divest assets during the year as a result
of continuing consolidation within the industry and the strong oil and gas price
environment that currently exists. St. Mary will continue to emphasize smaller
niche acquisitions utilizing the Company's technical expertise, financial
flexibility and structuring experience. Many attractive acquisition candidates
are sourced in cooperation with St. Mary's regional offices where the local
personnel have a detailed insight into emerging opportunities and geologic
potential. Additionally, the Company is also actively seeking larger
acquisitions of assets or companies that would afford opportunities to expand
the Company's existing core areas, acquire additional geoscientists or gain a
significant acreage and production foothold in a new basin within the United
States.
Control of Operations. The Company believes it is increasingly
important to control geologic and operational decisions as well as the timing of
those decisions. In addition, the Company receives income in the form of monthly
COPAS overhead reimbursement as an operator. St. Mary plans to operate
approximately 70% of its capital budget in 2000.
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Financial Flexibility. A conservative use of financial leverage has
long been a cornerstone of St. Mary's strategy. St. Mary believes that the
preservation of a strong balance sheet is a competitive advantage because it
enables the Company to act quickly and decisively to capture opportunities and
provides the financial resources to weather periods of volatile commodity prices
or escalating costs.
Significant Developments Since December 31, 1998
Acquisitions of Oil and Gas Properties. The Company completed two
significant acquisitions with common stock in 1999. Nance Petroleum Corporation
was acquired in June with the issuance of 259,494 shares of stock and debt
assumption of $3.2 million. This transaction added approximately 13.7 million
BCFE of reserves. The Company closed the acquisition of King Ranch Energy, Inc.
in December 1999, in a merger through the issuance of 2,666,187 shares of common
stock. The Company completed several smaller acquisitions totaling $3.7 million
in Louisiana and the Anadarko Basin and $1.3 million in the Permian and
Williston basins.
Year End Reserves. As of December 31, 1999, net proved reserves
increased 74% to 321 billion cubic feet equivalent. The Company added 103 BCFE
through acquisitions with stock and cash, 56 BCFE from drilling activities and 9
BCFE from net revisions of previous reserves resulting from higher year-end 1999
pricing partially offset by negative performance revisions.
Stock Repurchase Plan. 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 purchases or negotiated sales, up to 1,000,000 of
its own common shares. The Company repurchased a total of 147,800 of its common
shares during 1998, 35,000 in 1999 and 15,000 shares to date in 2000.
Khanty Mansiysk Oil Corporation Shares. The Company sold all of its
original stock in KMOC in August 1999 for $1.9 million realizing a $150,000
gain. The Company elected to convert its receivable into additional shares of
KMOC stock in February 2000, and is actively marketing these shares for sale.
Summo Minerals Corporation. The Company and Summo Minerals Corporation
("Summo") completed a financing agreement with Resource Capital Fund, L.P.
("RCF") to restructure the Company's loan to Summo and to provide additional
capital. The Company received $2.1 million cash for a portion of its note
receivable and the transfer of 50% or 4,962,047 Summo shares to RCF. In
addition, the Company received 17.5 million Summo warrants exercisable at
CDN$.12. RCF will provide up to $2 million in additional loans to Summo for
operating needs. The Company's current principal balance due from Summo is $1.4
million.
Large Target Success. The Sturlese #1 well was drilled to 16,467 feet
on the Company's Stallion Prospect and found 119 feet of pay in the MA22 and
MA24 sands. This well is currently producing from the MA24 sand with MA 22 pay
behind pipe. The Sturlese #3 reached total depth of 17,000 feet in February
2000, production liner was set, and the well is currently awaiting completion.
Additional drilling to test other fault blocks in the Stallion Prospect is
anticipated in 2000.
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<PAGE>
ITEM 2. PROPERTIES
Domestic Operations
The Company's exploration, development and acquisition activities are
focused in five core operating areas: the Mid-Continent region; onshore Gulf
Coast and offshore Gulf of Mexico; the ArkLaTex region; the Williston Basin in
North Dakota and Montana; and the Permian Basin in west Texas and New Mexico.
Information concerning each of the Company's major areas of operations, based on
the Company's estimated net proved reserves as of December 31, 1999, is set
forth below.
<TABLE>
<CAPTION>
Oil Gas MMCFE PV-10 Value
--- --- ----- -----------
(MBbls) (MMcf) Amount Percent (In thousands) Percent
------- ------ -------------- -------------- -------
<S> <C> <C> <C> <C> <C> <C>
Mid-Continent Region............ 988 82,800 88,726 27.6% $90,395 25.8%
ArkLaTex Region................. 1,635 41,600 51,409 16.0% 46,990 13.4%
Gulf Coast and Gulf of Mexico... 2,122 61,188 73,921 23.0% 95,174 27.1%
Williston Basin................. 9,642 7,633 65,484 20.4% 73,781 21.0%
Permian Basin................... 4,447 10,719 37,401 11.7% 41,466 11.8%
Other (1)....................... 66 3,702 4,099 1.3% 3,210 .9%
------------------------------------------------------------------------
Total........................... 18,900 207,642 321,040 100.0% $351,016 100.0%
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</TABLE>
[FN]
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(1) Includes reserves associated with properties in Colorado, Kansas,
Louisiana, New Mexico, Texas, Utah and Wyoming.
</FN>
Mid-Continent Region. Since 1973 St. Mary has been active in the
Mid-Continent region where operations are managed by its 28-person Tulsa,
Oklahoma office. The Company has ongoing exploration and development programs in
the Anadarko Basin of Oklahoma. The Mid-Continent region accounted for 28% of
the Company's estimated net proved reserves as of December 31, 1999 or 88.7 BCFE
(79% proved developed and 93% gas). The Company participated in 58 gross wells
and recompletions in this region in 1999, including 22 Company-operated wells.
The Company's development and exploration budget in the Mid-Continent
region for 2000 totals $21 million. The Company plans to operate 34 drilling
wells in the Mid-Continent region during 2000 and to utilize two to three
drilling rigs throughout the year. St. Mary also expects to participate in an
additional 10 to 20 wells to be operated by other entities.
Anadarko Basin. The Company's long history of operations and
proprietary geologic knowledge enable the Company to sustain economic
development and exploration programs despite periods of adverse industry
conditions. The Company is applying state of the art technology in hydraulic
fracturing and innovative well completion techniques to accelerate production
and associated cash flow from the region's tight gas reservoirs. St. Mary also
continues to benefit from a continuing consolidation of operators in the basin.
The Company periodically seizes attractive opportunities to acquire properties
from companies that have elected to discontinue operations in the basin.
The Company works aggressively to control its operating costs and to
enhance its full cycle economics. In December 1998 the Company realized net
proceeds of $22 million on the sale of its interests in eight fields in the
Anadarko Basin. This sale was part of the Company's ongoing strategy to enhance
the return on its portfolio of assets through the opportunistic sale of
non-strategic properties during periods in the market when such properties
command premium valuations.
Drilling activities will focus on lower to medium-risk prospects in the
Granite Wash, Osborne and Red Fork formations. In addition, the Company will
devote approximately 42% of its Mid-Continent capital budget to deeper, higher
potential development wells in the lower Morrow formation below 19,000 feet at
the NE Mayfield Field and in various other fields with Morrow and Springer
formations at depths between 10,000 and 16,000 feet.
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<PAGE>
Carrier Prospect. Within its inventory of large-target prospects, the
Company holds an aggregate 11.2% working interest in 25,800 acres in Leon
County, Texas in the Cotton Valley reef play. The Company's Carrier Prospect
acreage is located approximately nine miles east of the trend of the industry's
initial prolific reef discoveries, and targets potentially larger reefs that are
postulated to have developed in the deeper waters of the basin during the
Jurassic period. The Company and its partners completed a 52 square mile 3-D
seismic survey in 1997. St. Mary holds a 22% working interest in the first
prospect that will test a large 3-D anomaly that has been interpreted to be a
platform reef situated in the deeper portion of the East Texas Basin to the east
of the industry's existing pinnacle reef discoveries. St. Mary and its partners
plan to spud the initial test well in late 2000.
Gulf Coast and Gulf of Mexico Region. St. Mary's presence in south
Louisiana dates to the early 1900's when the Company's founders acquired a
franchise property in St. Mary Parish on the shoreline of the Gulf of Mexico.
These 24,900 acres of fee lands constitute one of the Company's most valuable
assets and yielded more than $3 million of gross oil and gas royalty revenue in
1999. The Company's onshore Gulf Coast and Gulf of Mexico presence increased
dramatically in 1999 with the acquisition of King Ranch Energy and is expected
to be a major growth area in 2000 and beyond. This acquisition included 260,000
gross undeveloped acres (81,000 net acres) and 1,538 square miles of 3-D seismic
data. The Gulf Coast and Gulf of Mexico region accounted for 23% of the
Company's estimated net proved reserves as of December 31, 1999, or 73.9 BCFE
(77% proved developed and 83% gas).
The Company's diverse activities in the onshore Gulf Coast and Gulf of
Mexico are managed by its recently expanded 12-person regional office in
Lafayette, Louisiana, and include ongoing development and exploration programs
in Point Coupee, Cameron, Lafourche, Jefferson Davis, Vermilion and Calcasieu
parishes as well as several offshore Gulf of Mexico blocks. Advanced 3-D seismic
imaging and interpretation techniques are revitalizing exploration and
development activities in the Miocene trend along the Gulf Coast. St. Mary is
applying the latest technologies to unravel the region's complex geology and to
extend exploratory drilling into deeper untested formations. The Company's
exploration and development budget in the Gulf Coast and Gulf of Mexico region
for 2000 is $25 million, including approximately $12 million for large target
projects.
The Judge Digby Field is the largest field acquired in the King Ranch
Energy acquisition and is located outside Baton Rouge in Point Coupee Parish.
The Company has a 10% to 20% working interest in six wells currently producing
102 MMCF per day. This ultra deep field produces from multiple Tuscaloosa
reservoirs between 19,000 and 22,000 feet. The Parlange #11 is currently
drilling toward a target depth of 24,450 feet and the operator plans to drill
another well following completion of this well.
The Company plans three offset wells in the Constitution Field in South
Texas where a successful fracture stimulation increased production from 540 MCF
and 85 Bbl per day to 4.2 MMCF and 600 Bbl per day. St. Mary owns a 40% working
interest in this field.
St. Mary and its partners have completed a 30 square mile 3-D survey on
the western and northern flanks of the Edgerly salt dome in Calcasieu Parish,
Louisiana where a 16,000 acre leasehold position was assembled during 1998. The
first well, the Ledoux #1-35 was completed in 1999 for 2.5 MMCF and 248 Bbl per
day, the second well drilled was dry, and the Collingwood #24-1 is currently
completing. The Company has identified a number of other promising anomalies on
the 3-D survey and expects to test several Hackberry prospects at shallow depths
between 10,000 and 13,000 feet in 2000. The Company has an approximate 35%
working interest in the Edgerly prospect.
St. Mary's recent acquisition of King Ranch Energy, its historical
presence in southern Louisiana, its established network of industry
relationships and its extensive technical database on the area have enabled the
Company to assemble an inventory of large-target prospects in the onshore Gulf
Coast and Gulf of Mexico region.
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<PAGE>
In the Gulf of Mexico, St. Mary has three high potential, 3-D, large
target prospects at Vermillion 273, W. El Gordo located on Matagorda 522L, and
Matagorda 701. Vermillion 273, located in 160 feet of water offshore Louisiana,
is a 12,500 foot test for Pliocene lower Lentic objectives. Matagorda 701 is
located 50 miles east of Corpus Christi, Texas in 110 feet of water and will
test a large fault block on the east flank of the Matagorda 700 field. The West
El Gordo prospect is also a lower Miocene Marg A and Siph Davisi prospect on
trend with prolific production at Matagorda 525/526 in shallow Texas state
waters (see "Large-Target Exploration Projects"). Because St. Mary's ownership
interest in certain of these prospects is relatively large, the Company plans to
sell or trade a portion of its interests in order to limit the Company's
exposure on any one well to 30%.
The disappointments at South Horseshoe Bayou and at Atchafalaya Bay
discussed below underscore the risks inherent in the exploration for deep gas
reserves in this region. St. Mary evaluates the results of its exploration
efforts based on full cycle economic returns over a multi-year period and
believes that exploration decisions should not be based solely on any single
year's results.
Fee Lands. The Company owns 24,900 acres of fee lands and associated
mineral rights in St. Mary Parish located approximately 85 miles southwest of
New Orleans. St. Mary also owns a 25% working interest in approximately 300
acres located offshore and immediately south of the Company's fee lands. Since
the initial discovery on the Company's fee lands in 1938, cumulative oil and gas
revenues, primarily landowners' royalties, to the Company from the Bayou Sale,
Horseshoe Bayou and Belle Isle fields on its fee lands have exceeded $225
million. St. Mary currently leases 11,668 acres of its fee lands and has an
additional 13,232 acres that are presently unleased. The Company's principal
lessees are Vastar, Cabot, ExxonMobil and Sam Gary Jr. and Associates, a private
exploration company headquartered in Denver.
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
major discovery on its fee lands at South Horseshoe Bayou in early 1997 and a
subsequent successful confirmation well in early 1998 proved that significant
accumulations of gas are sourced and trapped at depths below 16,000 feet.
South Horseshoe Bayou Project. In October 1995 the Company began
participation as a working interest owner in its fee lands in St. Mary Parish
with a 25% working interest in this project; resulting in a net revenue interest
ranging from 36% to 40% due to its previously existing royalty position. The St.
Mary Land & Exploration No. 1 well, under a turn-key contract, commenced
drilling toward a target depth of 19,000 feet. In February 1996 this well began
encountering severe pressure and mechanical problems that could not be corrected
and in July 1996 the well was plugged without reaching total depth. The drilling
rig was skid and the drilling of a new well commenced on the same site. In
February 1997 the Company announced a significant deep gas discovery at the St.
Mary Land & Exploration No. 2 well. This well was completed in the 17,300 foot
sand, and in January 1998 a confirmation well, the St. Mary Land & Exploration
No. 3, was completed in the same interval. In April 1998 the No. 2 well was
recompleted in the 17,900 foot sand and is currently producing. In August 1998
the No. 3 well was shut-in as the result of mechanical problems while it was
producing approximately 33 MMcf per day. The two wells have produced 6.4 Bcf of
gas and 48 MBbls of oil, net to the Company's interest, through December 31,
1999. Management is currently evaluating whether to sidetrack or abandon the No.
3 well.
The St. Mary Land & Exploration 24-1 well (41% working interest) was
spud in 1999 to test a fault block to the north of the existing production as
part of the Company's continuing management and exploitation of its fee lands.
This well was determined to be dry and was abandoned in February 2000 and all
costs through year-end were charged to exploration expense in the 1999 results
of operations.
Atchafalaya Bay Prospect. In March 1997 the Company and its partner
acquired seven tracts (2,845 gross acres) in a Louisiana state lease sale in
Atchafalaya Bay. A 19,000-foot test of a large 3-D prospect during 1998 was
unsuccessful and the well was completed in a small secondary zone at 12,300
feet. The costs associated with the drilling of this deep exploratory well were
expensed in 1998.
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<PAGE>
Stallion Prospect. The Company's Sturlese No. 1 well (31.25% working
interest) on the Stallion prospect was completed in 1999 with 119 feet of net
pay in the MA 22 and MA 24 sands. This well is currently producing from the MA24
sand with MA 22 pay behind pipe. The Sturlese #3 reached total depth of 17,000'
in February 2000, production liner was set and is currently awaiting completion.
Additional drilling to test other fault blocks is anticipated in 2000 (see
"Large-Target Exploration Projects").
Patterson Prospect. The Company's Patterson prospect is located
approximately 20 miles north of the Company's fee lands in St. Mary Parish
within the lower Miocene producing trend of south Louisiana. St. Mary holds a
25% working interest in leases and options totaling approximately 5,573 acres in
the prospect area which lies within a major east-west producing trend between
the Garden City and Patterson fields. An unsuccessful 19,000-foot test was
drilled in 1995 based on 2-D seismic data and existing well control. In order to
further evaluate this prospect, in 1997 St. Mary and its partners purchased 20
square miles of a regional 3-D seismic survey. PennzEnergy is currently drilling
an analog prospect on trend to Patterson and should reach total depth in the
first quarter 2000. The Company is awaiting the results of this well and hopes
to proceed with the drilling of the 19,500-foot MA sand test by the third
quarter 2000 if this well is successful (see "Large-Target Exploration
Projects").
North Parcperdue Prospect. The Company has a 25% working interest in
the North Parcperdue prospect located in Vermilion Parish. The Bacque No. 1
well, spud in 1999 was unsuccessful in the Marg Tex sands but was completed
uphole in the Marg Vag sands and is awaiting pipeline connection.
ArkLaTex Region. The Company's operations in the ArkLaTex region are
managed by its 16-person office in Shreveport, Louisiana. The ArkLaTex region
accounted for 16% of the Company's estimated net proved reserves as of December
31, 1999, or 51.4 BCFE (89% proved developed and 81% gas). The Company's 2000
capital budget for the ArkLaTex region is $10 million.
In 1992 the Company acquired the ArkLaTex oil and gas properties of T.
L. James & Company, Inc. as well as rights to over 6,000 square miles of
proprietary 2-D seismic data in the region. The Shreveport office's successful
development and exploration programs have derived from a series of niche
acquisitions completed since 1992 totaling $9.3 million. These acquisitions have
provided access to strategic holdings of undeveloped acreage and proprietary
packages of geologic and seismic data, resulting in an active program of
additional development and exploration.
St. Mary's holdings in the ArkLaTex region are comprised of interests
in approximately 514 producing wells, including 96 Company-operated wells, and
interests in leases totaling approximately 67,000 gross acres and mineral
servitudes totaling approximately 15,600 gross acres.
Activities in the ArkLaTex during 1999 focused on the search for new
opportunities and potential analog fields as well as final development of
several important field discoveries made by the Company's geoscientists since
1994. At the Box Church Field in Limestone County, Texas, the Company installed
a field wide system of compression and gas lift to stabilize current production
at 15 MMcf per day. The Company operates the field and holds an average 58%
working interest. Total cumulative gross field reserves are expected to exceed
100 Bcf of gas.
The Company acquired a 50% working interest and operations of the
Rodessa Cotton Valley Field in Caddo Parish, Louisiana in July 1999. The field
consisted of one newly completed gas well. The St. Mary #1 Gipson has since been
drilled and tested at 1300 Mcf per day. Four to six additional locations are
planned to develop the field reserves of 14 BCFE.
The Company participated in two successful wells at the Ada Field in
Bienville Parish, Louisiana with a combined initial production of 8,500 Mcf per
day. The first well at Trinidad Field (25% working interest) in Henderson
County, Texas tested at 1,800 Mcf per day. The Company also participated with a
15% working interest in a discovery well producing 350 Bbl per day at the NE
Collins Cotton Valley Field located in Covington County, Mississippi.
-7-
<PAGE>
The Shreveport office assumed operations of the Clarksville Field (44%
working interest) in Red River County, Texas acquired as part of King Ranch
Energy. The field produces 740 Bbl per day from 35 wells.
In 2000 the Company will continue to focus on the search for new
opportunities and potential analog fields in which to apply its proprietary
geologic models and production techniques. St. Mary believes that it is well
positioned to secure additional acquisitions in the ArkLaTex region during 2000
as consolidation within the industry increases the divestiture activity.
Williston Basin Region. The Company's operations in the Williston Basin
are conducted through Nance Petroleum Corporation, a wholly owned subsidiary
following its acquisition in June 1999. Previously, the Company's Williston
Basin interests were owned through its 74% partnership interest in Panterra
Petroleum, in which Nance Petroleum held a 26% interest. The Company currently
owns interests in 82 fields within the basin's core producing area including
134,000 gross acres, 83 Nance-operated wells and 181 wells operated by other
parties.
The Williston Basin region accounted for 20% of the Company's estimated
net proved reserves as of December 31, 1999, or 65.5 BCFE (95% proved developed
and 88% oil). St. Mary has budgeted approximately $12.0 million for the
Williston Basin development and exploration program.
Nance's operations are directed by senior geoscientists who have
devoted their careers to the development of oil and gas reserves in the
Williston Basin. The Company's long-term strategy is to employ advanced
technologies to improve drilling results and production in order to maximize
full cycle economics. For instance, Nance has successfully used 3-D seismic
imaging to delineate structural and subtle stratigraphic features not previously
discernable using conventional exploration methods. This utilization of advanced
technologies by experienced geoscientists has helped Nance achieve a 94% success
rate in its operated exploration and development program since 1991.
Two new discoveries operated by Nance were completed in 1999 in
McKenzie County, North Dakota on the Mondak prospect where 3-D seismic was
previously shot. The Federal 1-33 discovery was completed and is currently
producing 440 Bbl and 400 MCF per day and the confirmation well, the Federal
16-28 was completed at year-end and is currently producing 635 Bbl and 600 MCF
per day. Another Nance operated well, the Federal 7-12 was drilled in the Glo
field, Cambell County, Wyoming at year-end and is currently testing 200 Bbl per
day.
Nance plans to conduct five additional or extended 3-D surveys in 2000
over existing fields in the search for bypassed pay zones. A drilling rig is
expected to be kept active all year drilling 6-8 wells.
Permian Basin Region. The Permian Basin area covers a significant
portion of eastern New Mexico and western Texas and is one of the major
producing basins in the United States. The basin includes hundreds of oil fields
undergoing secondary and enhanced recovery projects. 3-D seismic imaging of
existing fields and state-of-the-art secondary recovery programs are
substantially increasing oil recoveries in the Permian Basin. The optimization
of production and the careful control of operating costs are especially critical
during periods of low oil prices, such as in 1998. Beginning in 2000 Nance
Petroleum Corporation will manage the Company's interest in the Permian Basin.
The Company believes that COPAS overhead income will more than offset the
general and administrative costs of managing these properties.
St. Mary's holdings in the Permian Basin derive from a series of niche
property acquisitions that date back to 1995. Management believes that its
Permian Basin operations provide St. Mary with a solid base of long lived oil
reserves, promising longer-term exploration and development prospects and the
potential for secondary recovery projects. The Permian Basin region accounted
for 12% of the Company's estimated net proved reserves as of December 31, 1999,
or 37.4 BCFE (84% proved developed and 71% oil).
The Company's reservoir engineers have identified a number of
properties where the project economics of secondary recovery plans are favorable
under current prices. St. Mary's geoscientists have also identified a number of
high quality prospects that are expected to be drilled in 2000.
-8-
<PAGE>
St. Mary initiated a full-scale multi-year waterflood in 1998 at its
Parkway (Delaware) Unit in Eddy County, New Mexico. The initial response to the
first phase of this waterflood has been excellent, increasing field production
by 500 Bbl per day. The Company's operations in the Permian Basin during 2000
will focus on the expansion of the waterflood project at Parkway and additional
secondary recovery work at the E. Shugart field. As a result of higher oil
prices, the Company also expects to see new drilling at the Willow Lake Field
where a new discovery was completed in 1999 and the Young North Field where a
successful recompletion increased production 150 Bbl per day.
St. Mary also holds a 21.2% working interest in an unusual 30,450-acre
top lease in the North Ward Estes Field in Ward County, Texas. The original
lease will expire on August 4, 2000. Until that date, working interest
production from approximately 400 wells on the lease and the development and
exploration rights on the lease are owned by Chevron U.S.A., Inc and Three-B Oil
Company. After that date, production of approximately 1,800 Bbl and 3,500 Mcf
per day from the wells located on the lease and future development and
exploration rights on this 50 square mile property will revert to the ownership
and control of St. Mary and its partners. The top lease will continue in effect
for as long as oil and/or gas is produced in paying quantities.
Large-Target Exploration Projects. The Company generally invests
approximately 15% of its annual capital budget in longer-term, higher-risk,
high-potential exploration projects. During the past several years the Company
has assembled an inventory of large potential projects in various stages of
development which have the potential to materially increase the Company's
reserves. The Company's strategy is to maintain a pipeline of seven to ten of
these high-potential prospects and to test four or more targets each year, while
furthering the development of early-stage projects and continuing the evaluation
of potential new exploration prospects.
The Company seeks to develop large-target prospects by using its
comprehensive base of geological, geophysical, engineering and production
experience in each of its focus areas. The large-target projects typically
require relatively long lead times before a well is commenced in order to
develop proprietary geologic concepts, assemble leasehold positions and acquire
and fully evaluate 3-D seismic or other data. The Company seeks to apply the
latest technology, including 3-D seismic imaging, wherever appropriate in its
prospect development and evaluation to mitigate a portion of the inherently
higher risk of these exploration projects. In addition, the Company seeks to
invest in a diversified mix of exploration projects and generally limits its
capital exposure by participating with other experienced industry partners.
The following table summarizes the Company's active large-target
exploration projects (see also "Properties").
<TABLE>
<CAPTION>
St. Mary Expected
Working Test
Project Name Objective Location Interest(1) Date(2)
<S> <C> <C> <C> <C>
Stallion MA Sands Cameron Parish, LA 31.2% Early 2000
Patterson MA-3 , MA-7 St. Mary Parish, LA 25.0% Mid 2000
W. El Gordo MA - Siph D Gulf of Mexico 30.0% Late 2000
Vermillion 273 BOL A Gulf of Mexico 52.5% Late 2000
W. Cameron 39 MA Sands Gulf of Mexico 20.0% Early 2001
Carrier Cotton Valley Reef Leon County, TX 22.0% Early 2001
Matagorda MA - Siph D Gulf of Mexico 80.0% Mid 2001
</TABLE>
[FN]
- ---------
(1) Working interests differ from net revenue interests due to royalty
interest burdens. St Mary plans to sell or trade a portion of its
interest in order to limit the Company's exposure in any one well to
30%.
(2) Expected Test Date refers to the period during which the Company
anticipates the completion of an exploratory well.
</FN>
-9-
<PAGE>
International Operations
In 1997 the Company completed the sale or disposition of the majority
of its international investments. In 1998 the Company sold its remaining
properties in Canada.
Russian Joint Venture. In February 1997, the Company sold its interest
in The Limited Liability Company Chernogorskoye (the "Russian joint venture") to
Khanty Mansiysk Oil Corporation ("KMOC"), formerly known as Ural Petroleum
Corporation, for consideration totaling $17.6 million. The Company received $5.6
million in cash, before transaction costs, $1.9 million of KMOC common stock and
a convertible receivable in a form equivalent to a retained production payment
of approximately $10.1 million plus interest at 10% per annum from the limited
liability company formed to hold the Russian joint venture. The Company sold the
original shares of KMOC stock in August 1999 realizing a gain of $150,000. St.
Mary elected to convert its receivable to additional shares of KMOC stock on
February 10, 2000, and is actively marketing these shares for sale.
Acquisitions
The Company's strategy is to make selective niche acquisitions of oil
and gas properties within its core operating areas in the United States. The
Company seeks to acquire properties that complement its existing operations,
offer economies of scale and provide further development and exploration
opportunities based on proprietary geologic concepts or advanced well completion
techniques. Management believes that the Company's success in acquiring
attractively priced and under-exploited properties has resulted from its focus
on smaller, negotiated transactions where the Company has specialized geologic
knowledge or operating experience. In addition, the Company will pursue
corporate acquisitions when they can be made on an accretive basis.
Although the Company periodically evaluates large acquisition packages
offered in competitive bid or auction formats, the Company has continued to
emphasize property acquisitions having values of less than $10 million. This
size of acquisition package generally attracts less competition and is where the
Company's technical expertise, financial flexibility and structuring experience
afford a competitive advantage.
The Company completed $45 million in oil and gas property acquisitions
in 1999, the largest dollar value in the Company's history. Included were two
larger acquisitions of private companies in exchange for St. Mary common stock.
In June 1999, the Company acquired Nance Petroleum in exchange for 259,494
shares of stock and debt assumption of $3.2 million. This transaction added
approximately 13.7 million BCFE of reserves. The Company closed the acquisition
of King Ranch Energy in December 1999, in a merger in which 2,666,187 shares of
common stock were issued. The Company completed several smaller acquisitions
totaling $3.7 million in Louisiana and the Anadarko Basin and $1.3 million in
the Permian and Williston basins. During the last five years the Company has
closed over $105 million of niche acquisitions where proprietary geologic
knowledge or operating expertise and an attractive stock and performance track
record have afforded the Company a competitive advantage.
In 2000 St. Mary has reserved $32.5 million of its capital program for
property acquisitions. However, the Company has the financial capacity to commit
substantially greater resources to purchases should additional opportunities be
identified.
-10-
<PAGE>
Reserves
At December 31, 1999, Ryder Scott Company, independent petroleum
engineers, evaluated properties representing approximately 82% of the Company's
total PV-10 value and the Company evaluated the remainder. The PV-10 values
shown in the following table are not intended to represent the current market
value of the estimated net proved oil and gas reserves owned by the Company.
Neither prices nor costs have been escalated, but prices include the effects of
hedging contracts.
The following table sets forth summary information with respect to the
estimates of the Company's net proved oil and gas reserves for each of the years
in the three-year period ended December 31, 1999, as prepared by Ryder Scott
Company and St. Mary:
<TABLE>
<CAPTION>
As of December 31,
------------------
1999 1998(1) 1997
---- ------- ----
<S> <C> <C> <C>
Proved Reserves Data:
Oil (MBbls) 18,900 8,614 11,493
Gas (MMcf) 207,642 132,605 196,230
MMCFE 321,042 184,289 265,188
PV-10 value (in thousands) $ 351,000 $ 125,126 $ 262,006
Proved Developed Reserves 84% 86% 87%
Production Replacement 541% (25%) 358%
Life (years) 6.1 6.5 7.3
</TABLE>
[FN]
- ---------
(1) The Company's year-end 1998 reserves reflect property dispositions of
39.6 BCFE, discoveries and extensions of 40.8 BCFE, acquisitions of 5.3
BCFE, negative price-related revisions of 18.2 BCFE and a write-down of
38.8 BCFE of proved reserves at South Horseshoe Bayou.
</FN>
The present value of estimated future net revenues before income taxes
of the Company's reserves was $351 million as of December 31, 1999. This present
value is based on a benchmark of prices in effect at that date of $25.60 per
barrel of oil (NYMEX) and $2.32 per MMBtu of gas (Gulf Coast spot price), both
of which are adjusted for transportation and basis differential. These prices
were 112 percent and 25 percent higher, respectively, than prices in effect at
the end of 1998.
-11-
<PAGE>
Production
The following table summarizes the average volumes of oil and gas
produced from properties in which the Company held an interest during the
periods indicated:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Operating Data:
Net production (1):
Oil (MBbls)................................... 1,383 1,275 1,188
Gas (MMcf).................................... 22,805 25,440 22,900
MMCFE......................................... 31,104 33,090 30,024
Average net daily production (1):
Oil (Bbls).................................... 3,790 3,493 3,254
Gas (Mcf)..................................... 62,478 69,698 62,739
MCFE.......................................... 85,216 90,656 82,263
Average sales price (2):
Oil (per Bbl)................................. $ 16.56 $ 12.98 $ 18.87
Gas (per Mcf)................................. $ 2.17 $ 2.13 $ 2.33
Additional per MCFE data:
Lease operating expense....................... $ .44 $ .39 $ .35
Production taxes.............................. $ .16 $ .12 $ .16
</TABLE>
[FN]
- ---------
(1) Production from South Horseshoe Bayou and sold Oklahoma properties
represented 18.1% and 6.5% respectively, or a total of 24.6% of the
1998 production total.
(2) Includes the effects of the Company's hedging activities (see
"Management's Discussion and Analysis of Financial Condition and
Results of Operations--Overview").
</FN>
The Company uses financial hedging instruments, primarily
fixed-for-floating price swap agreements and no-cost collar agreements with
financial counterparties, to manage its exposure to fluctuations in commodity
prices. The Company also employs the use of exchange-listed financial futures
and options as part of its hedging program for crude oil.
Productive Wells
The following table sets forth information regarding the number of
productive wells in which the Company held a working interest at December 31,
1999. Productive wells are either producing wells or wells capable of commercial
production although currently shut in. One or more completions in the same
borehole are counted as one well. A well is categorized under state reporting
regulations as an oil well or a gas well based upon the ratio of gas to oil
produced when it first commenced production, and such designation may not be
indicative of current production.
<TABLE>
<CAPTION>
Gross Net
----- ---
<S> <C> <C>
Oil 1,178 312
Gas 1,359 250
------- -----
Total 2,537 562
======= =====
</TABLE>
-12-
<PAGE>
Drilling Activity
The following table sets forth the wells drilled and recompleted in
which the Company participated during each of the three years indicated:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1999 1998 1997
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Domestic:
Development:
Oil........................... 26 10.45 6 .28 10 3.06
Gas........................... 105 22.26 109 26.04 92 19.64
Non-productive................ 14 5.75 12 3.98 15 4.35
---------------------------------------------------
Total..................... 145 38.46 127 30.30 117 27.05
---------------------------------------------------
Exploratory:
Oil........................... 1 .20 1 .50 4 1.21
Gas........................... 12 3.84 3 .95 7 2.04
Non-productive................ 9 2.56 6 1.05 5 1.93
---------------------------------------------------
Total..................... 22 6.60 10 2.50 16 5.18
---------------------------------------------------
Farmout or non-consent 6 - 4 - 4 -
---------------------------------------------------
Grand Total(1) ................ 173 45.06 141 32.80 137 32.23
===================================================
</TABLE>
[FN]
- ---------
(1) Does not include 1and 4 gross wells completed on the Company's fee
lands during 1998 and 1997, respectively.
</FN>
All of the Company's drilling activities are conducted on a contract
basis with independent drilling contractors. The Company owns no drilling
equipment.
-13-
<PAGE>
Domestic Acreage
The following table sets forth the gross and net acres of developed and
undeveloped oil and gas leases, fee properties, mineral servitudes and lease
options held by the Company as of December 31, 1999. Undeveloped acreage
includes leasehold interests that may already have been classified as containing
proved undeveloped reserves.
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage (1) Acreage (2) Total
----------- ----------- -----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Arkansas..................................... 4,059 800 167 54 4,226 854
Louisiana................................... 107,862 35,589 69,596 19,259 177,458 54,848
Montana..................................... 16,922 8,527 50,688 35,086 67,610 43,613
New Mexico.................................. 7,880 2,028 3,400 1,605 11,280 3,633
North Dakota................................ 36,887 11,354 109,834 44,411 146,721 55,765
Oklahoma.................................... 115,798 25,549 40,411 10,556 156,209 36,105
Texas....................................... 167,142 64,548 261,903 78,340 429,045 142,888
Other (3) .................................. 14,334 5,473 27,276 9,828 41,610 15,301
------------------------------------------------------------------
Subtotal........................... 470,884 153,868 563,275 199,139 1,034,159 353,007
------------------------------------------------------------------
Louisiana Fee Properties..................... 10,334 10,334 14,580 14,580 24,914 24,914
Louisiana Mineral Servitudes................. 10,125 5,509 5,511 5,191 15,636 10,700
------------------------------------------------------------------
Subtotal................................ 20,459 15,843 20,091 19,771 40,550 35,614
------------------------------------------------------------------
GRAND TOTAL ............................ 491,343 169,711 583,366 218,910 1,074,709 388,621
==================================================================
</TABLE>
[FN]
- ---------
(1) Developed acreage is acreage assigned to producing wells for the
spacing unit of the producing formation. Developed acreage in certain
of the Company's properties that include multiple formations with
different well spacing requirements may be considered undeveloped for
certain formations, but have only been included as developed acreage in
the presentation above.
(2) Undeveloped acreage is lease acreage on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether such acreage
contains estimated net proved reserves.
(3) Includes interests in Alabama, Colorado, Kansas, Mississippi, Utah and
Wyoming. St. Mary also holds an override interest in an additional
44,388 gross acres in Utah.
</FN>
Non-Oil and Gas Activities
Summo Minerals. At December 31, 1998, the Company, through a
subsidiary, owned 9.9 million shares or 37% of Summo Minerals Corporation
("Summo") and had advanced $2.9 million to Summo under an interim financing
arrangement. Summo is a North American mining company focusing on finding late
exploration stage, low to medium-sized copper deposits in the United States.
Summo's common shares are listed on the Toronto Stock Exchange under the symbol
"SMA." In June 1999, the Company participated in a financing package arrangement
with 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. As a result of this transfer of shares to RCF the Company's ownership
percentage was reduced from 37% to 18%. 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. The remaining 4,962,046 shares of Summo common stock that the
Company still owns have a recorded value of $255,000 that includes the
unrealized gain on marketable equity securities. Management believes that the
remaining investment in Summo is realizable. The Company continually analyzes
the realizability of its investment in Summo in view of the effects of
persistent depressed copper prices and increased worldwide copper inventory
levels. In January 2000 Summo issued 1,016,594 shares of its common stock to the
Company as payment of interest on the Company's note receivable from Summo. On
issuance of these shares, the Company's ownership in Summo increased to 19%.
-14-
<PAGE>
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. As a result of the new financing
arrangement, the Company is not obligated to fund any future loans to Summo.
Competition
Competition in the oil and gas business is intense, particularly with
respect to the acquisition of producing properties, proved undeveloped acreage
and leases. Major and independent oil and gas companies actively bid for
desirable oil and gas properties and for the equipment and labor required for
their operation and development. The Company believes that the locations of its
leasehold acreage, its exploration, drilling and production capabilities and the
experience of its management and that of its industry partners generally enable
the Company to compete effectively. Many of the Company's competitors, however,
have financial resources and exploration, development and acquisition budgets
that are substantially greater than those of the Company, and these may
adversely affect the Company's ability to compete, particularly in regions
outside of the Company's principal producing areas. Because of this competition,
there can be no assurance that the Company will be successful in finding and
acquiring producing properties and development and exploration prospects at its
planned capital funding levels.
Markets and Major Customers
During 1999 one customer individually accounted for 13.3% of the
Company's total oil and gas production revenue. During 1998 no individual
customer accounted for 10% or more of the Company's total oil and gas production
revenue. During 1997 two customers individually accounted for 10.6% and 10.2% of
the Company's total oil and gas production revenue.
Government Regulations
The Company's business is subject to various federal, state and local
laws and governmental regulations that may be changed from time to time in
response to economic or political conditions. Matters subject to regulation
include discharge permits for drilling operations, drilling bonds, reports
concerning operations, the spacing of wells, unitization and pooling of
properties, taxation and environmental protection. From time to time, regulatory
agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and gas wells below actual production
capacity in order to conserve supplies of oil and gas.
The Company's operations could result in liability for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. The Company
could be liable for environmental damages caused by previous property owners. As
a result, substantial liabilities to third parties or governmental entities may
be incurred, and the payment of such liabilities could have a material adverse
effect on the Company's financial condition and results of operations. The
Company maintains insurance coverage for its operations, including limited
coverage for sudden environmental damages, but does not believe that insurance
coverage for environmental damages that occur over time is available at a
reasonable cost. Moreover, the Company does not believe that insurance coverage
for the full potential liability that could be caused by sudden environmental
damages is available at a reasonable cost. Accordingly, the Company may be
subject to liability or may lose substantial portions of its properties in the
event of certain environmental damages. The Company could incur substantial
costs to comply with environmental laws and regulations.
-15-
<PAGE>
Certain operations the Company conducts are on Federal oil and gas
leases that the Minerals Management Service (the 'MMS') administers. The MMS
issues such leases through competitive bidding. These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the Outer Continental Shelf Lands Act (which are subject to
change by the MMS). For offshore operations, lessees must obtain MMS approval
for exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. Lessees must also comply with detailed
MMS regulations governing, among other things, engineering and construction
specifications for offshore production facilities, safety procedures, flaring of
production, plugging and abandonment of Outer Continental Shelf OCS wells,
calculation of royalty payments and the valuation of production for this
purpose, and removal of facilities. To cover the various obligations of lessees
on the OCS, the MMS generally requires that lessees post substantial bonds or
other acceptable assurances that such obligations will be met. The cost of such
bonds or other surety can be substantial, and there is no assurance that the
Company can continue to obtain bonds or other surety in all cases. Under certain
circumstances the MMS may require any Company operations on Federal leases to be
suspended or terminated.
The MMS has under consideration proposals to change the method of
calculating royalties and the valuation of crude oil produced from federal
leases. These changes, if adopted, would modify the valuation procedures for
crude oil to reduce use of oil posted prices and assign a value to crude oil
intended to better reflect market value. The Company cannot predict what action
the MMS will take on this matter, or can it predict at this stage how the
Company might be affected if the MMS adopts such changes.
The Oil Pollution Act of 1990 imposes a variety of regulations on
"responsible parties" related to the prevention of oil spills. The
implementation of new, or the modification of existing, environmental laws or
regulations, including regulations promulgated pursuant to the Oil Pollution Act
of 1990, could have a material adverse impact on the Company.
The recent trend toward stricter standards in environmental legislation
and regulation is likely to continue. Initiatives to further regulate the
disposal of oil and gas wastes at the federal, state and local level could have
a material impact on the Company.
Title to Properties
Substantially all of the Company's working interests are held pursuant
to leases from third parties. A title opinion is usually obtained prior to the
commencement of drilling operations on properties. The Company has obtained
title opinions or conducted a thorough title review on substantially all of its
producing properties and believes that it has satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty interests,
liens for current taxes and other burdens which the Company believes do not
materially interfere with the use of or affect the value of such properties. The
Company performs only a minimal title investigation before acquiring undeveloped
properties.
-16-
<PAGE>
Operational Hazards and Insurance
The oil and gas business involves a variety of operating risks,
including fire, explosions, blow-outs, pipe failure, casing collapse, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures and discharges of toxic gases. The occurrence of any such event could
result in substantial losses to the Company due to injury and loss of life;
severe damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage; clean-up responsibilities; regulatory
investigation and penalties and suspension of operations. The Company and the
operators of properties in which it has an interest maintain insurance against
some, but not all, potential risks. However, there can be no assurance that such
insurance will be adequate to cover any losses or exposure for liability. The
occurrence of a significant unfavorable event not fully covered by insurance
could have a material adverse affect on the Company's financial condition and
results of operations. Furthermore, the Company cannot predict whether insurance
will continue to be available at a reasonable cost or at all.
Employees and Office Space
As of December 31, 1999, the Company had 142 full-time employees. None
of the Company's employees is subject to a collective bargaining agreement. The
Company considers its relations with its employees to be good. The Company
leases approximately 35,900 square feet of office space in Denver, Colorado, for
its executive and administrative offices, of which 7,200 square feet is
subleased. The Company also leases approximately 15,000 square feet of office
space in Tulsa, Oklahoma, approximately 7,300 square feet of office space in
Shreveport, Louisiana, approximately 7,500 square feet in Lafayette, Louisiana
and approximately 10,900 square feet in Billings, Montana. The Company believes
that its current facilities are adequate.
Glossary
The terms defined in this section are used throughout this Form 10-K.
2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
two-dimensional cross-section of the subsurface.
3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used herein in reference to natural gas.
BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Behind pipe reserves. Estimated net proved reserves in a formation in which
production casing has already been set in the wellbore but has not been
perforated and production tested.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
of six Mcf of gas (including gas liquids) to one Bbl of oil.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
-17-
<PAGE>
Estimated net proved reserves. The estimated quantities of oil, gas and gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Exploratory well. A well drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir, or to extend a known reservoir.
Fee land. The most extensive interest which can be owned in land, including
surface and mineral (including oil and gas) rights.
Finding cost. Expressed in dollars per BOE. Finding costs are calculated by
dividing the amount of total capital expenditures for oil and gas activities by
the amount of estimated net proved reserves added during the same period
(including the effect on proved reserves of reserve revisions).
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
of fluid and proppant (usually sand) into the formation under high pressure.
This creates artificial fractures in the reservoir rock which increases
permeability and porosity.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
Mcf. One thousand cubic feet.
MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMcf. One million cubic feet.
MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
required to raise the temperature of a one-pound mass of water one degree
Fahrenheit.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net asset value per share. The result of the fair market value of total assets
less total liabilities, divided by the total number of outstanding shares of
common stock.
PV-10 value. The present value of estimated future gross revenue to be generated
from the production of estimated net proved reserves, net of estimated
production and future development costs, using prices and costs in effect as of
the date indicated (unless such prices or costs are subject to change pursuant
to contractual provisions), without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
-18-
<PAGE>
Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Proved undeveloped reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Reserve life. Expressed in years, represents the estimated net proved reserves
at a specified date divided by forecasted production for the following 12-month
period.
Royalty. The interest paid to the owner of mineral rights expressed as a
percentage of gross income from oil and gas produced and sold unencumbered by
expenses.
Royalty interest. An interest in an oil and gas property entitling the owner to
shares of oil and gas production free of costs of exploration, development and
production. Royalty interests are approximate and are subject to adjustment.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether such acreage contains estimated net proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to share in
the production.
-19-
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
To the knowledge of management, no claims are pending or threatened
against the Company or any of its subsidiaries which individually or
collectively could have a material adverse effect upon the Company's financial
condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On December 16, 1999, St. Mary held a special meeting of the
stockholders to vote on a proposal to issue 2,666,252 shares of St. Mary common
stock under the merger agreement by which St. Mary was to acquire King Ranch
Energy, Inc. The proposal was approved by a majority of the stockholders as
indicated by the following tabulation of votes:
<TABLE>
<CAPTION>
<S> <C>
For: 9,121,635
Against: 12,914
Abstain: 6,527
Broker non-votes: 0
</TABLE>
-20-
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
SECURITY HOLDERS MATTERS
Market Information. The Company's common stock is traded on the Nasdaq
National Market System under the symbol MARY. The range of high and low bid
prices for the quarterly periods in 1999 and 1998, as reported by the Nasdaq
National Market System, is set forth below:
<TABLE>
<CAPTION>
Quarter Ended High Low
------------- ---- ---
<S> <C> <C>
March 31, 1999 $20.750 $14.875
June 30, 1999 21.375 15.250
September 30, 1999 29.813 15.250
December 31, 1999 28.063 20.250
March 31, 1998 $39.375 $26.250
June 30, 1998 39.625 21.625
September 30, 1998 25.000 15.000
December 31, 1998 23.875 15.500
</TABLE>
On March 2, 2000, the closing sale price for the Company's common stock
was $26.88 per share.
Holders. As of February 29, 2000, the number of record holders of the
Company's common stock was 278. Management believes, after inquiry, that the
number of beneficial owners of the Company's common stock is in excess of 1,600.
Dividends. The Company has paid cash dividends to stockholders every
year since 1940. Annual dividends of $0.16 per share were paid quarterly in each
of the years 1987 through 1996. The Company increased its quarterly dividend 25%
to $.05 per share effective with the quarterly dividend paid in February 1997.
Dividends paid totaled $2,193,000 in 1999 and $2,190,000 in 1998.
-21-
<PAGE>
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected consolidated financial data for
the Company as of the dates and for the periods indicated. The financial data
for each of the five years ended December 31, 1999, were derived from the
Consolidated Financial Statements of the Company. The following data should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations," which includes a discussion of factors
materially affecting the comparability of the information presented, and in
conjunction with the Company's financial statements included elsewhere in this
report.
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Operating revenues:
Oil production $ 22,906 $ 16,545 $ 22,415 $ 22,100 $ 17,090
Gas production 49,588 54,103 53,349 34,674 19,479
Gain on sale of Russian joint venture - - 9,671 - -
Gain(loss) on sale of proved properties (55) 7,685 4,220 2,254 1,292
Other revenues 1,582 411 1,391 523 789
--------------------------------------------------------------
Total operating revenues 74,021 78,744 91,046 59,551 38,650
--------------------------------------------------------------
Operating expenses:
Oil and gas production 18,681 17,005 15,258 12,897 10,646
Depletion, depreciation & amortization 22,574 24,912 18,366 12,732 10,227
Impairment of proved properties 3,982 17,483 5,202 408 2,676
Exploration 11,593 11,705 6,847 8,185 5,073
Abandonment and impairment of
unproved properties 6,616 4,457 2,077 1,469 2,359
General and administrative 9,172 7,097 7,645 7,603 5,328
Writedown of Russian convertible
receivable - 4,553 - - -
Writedown of investment
in Summo Minerals - 3,949 - - -
(Income) loss in equity investees 58 661 325 (1,272) 579
Other 1,744 141 281 78 152
--------------------------------------------------------------
Total operating expenses 74,420 91,963 56,001 42,100 37,040
--------------------------------------------------------------
Income (loss) from operations (399) (13,219) 35,045 17,451 1,610
Non-operating (expense) income 75 (1,027) (99) (1,951) (896)
Income tax (expense) benefit 406 5,415 (12,325) (5,333) 723
--------------------------------------------------------------
Income (loss) from continuing operations 82 (8,831) 22,621 10,167 1,437
Gain on sale of discontinued operations,
net of income taxes - 34 488 159 306
--------------------------------------------------------------
Net income (loss) $ 82 $ (8,797) $ 23,109 $ 10,326 $ 1,743
==============================================================
</TABLE>
-22-
<PAGE>
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Income Statement Data (continued):
Basic net income (loss) per common share:
Income (loss) from continuing operations $ 0.01 $ (0.81) $ 2.13 $ 1.16 $ 0.17
Gain on sale of discontinued operations - - 0.05 0.02 0.03
-------------------------------------------------------------
Basic net income (loss) per share $ 0.01 $ (0.81) $ 2.18 $ 1.18 $ 0.20
=============================================================
Diluted net income (loss) per common share:
Income (loss) from continuing operations $ 0.01 $ (0.81) $ 2.10 $ 1.15 $ 0.17
Gain on sale of discontinued operations - - 0.05 0.02 0.03
-------------------------------------------------------------
Diluted net income (loss) per share $ 0.01 $ (0.81) $ 2.15 $ 1.17 $ 0.20
=============================================================
Cash dividends per share $ 0.20 $ 0.20 $ 0.20 $ 0.16 $ 0.16
Basic weighted average common shares
outstanding 11,099 10,937 10,620 8,759 8,760
Diluted weighted average common shares
outstanding 11,164 10,937 10,753 8,826 8,801
Balance Sheet Data (end of period):
Working capital $ 13,439 $ 9,785 $ 9,618 $ 13,926 $ 3,102
Net property and equipment 180,665 143,825 157,481 101,510 71,645
Total assets 230,438 184,497 212,135 144,271 96,126
Long-term obligations 13,000 19,398 22,607 43,589 19,602
Total stockholders' equity 188,772 134,742 147,932 75,160 66,282
Other Data:
EBITDA (1) $ 22,175 $ 11,693 $ 53,411 $ 30,183 $ 11,837
Net cash provided by operating activities 40,755 45,386 43,111 24,205 17,713
Capital and exploration expenditures, cash
and noncash 91,184 57,855 89,213 52,601 32,307
</TABLE>
[FN]
- ---------
(1) EBITDA is defined as earnings before interest income and expense,
income taxes, depreciation, depletion, amortization, and gain on sale
of discontinued operations. EBITDA is a financial measure commonly used
for the Company's industry and should not be considered in isolation or
as a substitute for net income, cash flow provided by operating
activities or other income or cash flow data prepared in accordance
with generally accepted accounting principles or as a measure of a
company's profitability or liquidity. Because EBITDA excludes some, but
not all, items that affect net income and may vary among companies, the
EBITDA presented above may not be comparable to similarly titled
measures of other companies.
</FN>
-23-
<PAGE>
ITEM 7. 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; onshore Gulf Coast and
offshore Gulf of Mexico; 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, ArkLaTex, Gulf Coast and offshore
Gulf of Mexico regions and in the Williston and Permian Basins. 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. In 1999 the
Company's activities in the Permian Basin were primarily contracted through an
oil and gas property management company with extensive experience in the basin.
After December 31, 1999, Nance personnel assumed this responsibility.
The Company's presence in south Louisiana includes active management of
its fee lands from which royalty income is derived. Royalty revenues from the
fee lands were $3.1, $6.9, and $8.8 million for the years 1999, 1998, and 1997,
respectively. 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. The Company's 1999 test well drilled at South Horseshoe Bayou was
unsuccessful and resulted in a dry hole in February 2000. All of the Company's
costs relating to this prospect at December 31, 1999 have been expensed except
for costs associated with the #2 well which is currently producing. An
evaluation is currently underway to determine if a sidetrack will be attempted
on the #3 well in 2000.
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. In addition, the Company will pursue corporate acquisitions if they
can be made on an accretive basis.
-24-
<PAGE>
The results of operations include several property acquisitions made
during recent years and their subsequent further development by the Company.
From 1996 to 1999 the Company has made a series of acquisitions totaling $15.9
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; the remaining 15%
working interest in these properties was acquired in early 1999. In 1999 St.
Mary acquired additional interests in the West Cameron Block 39 property located
in the Gulf of Mexico and in various other properties in Louisiana and Oklahoma
totaling $3.7 million.
On June 1, 1999, the Company acquired Nance and Quanterra Alpha Limited
Partnership for 259,494 shares of St. Mary common stock valued at $3.1 million,
the assumption of $3.2 million in debt and transaction costs of $56,000. This
acquisition was accounted for as a purchase and included Nance's 26% interest in
Panterra that the Company did not previously own. Through the remainder of 1999,
Nance acquired various Williston Basin properties for $948,000.
On December 17, 1999, in a transaction accounted for as a purchase, the
Company acquired King Ranch Energy, Inc ("KRE") for 2,666,187 shares of common
stock valued at $52.8 million and transaction costs of $2.3 million. After the
acquisition, KRE's name was changed to St. Mary Energy Company ("SMEC"). The
acquired properties are located primarily in the Gulf of Mexico and the onshore
Gulf Coast.
The Company reviews its producing properties for impairments when
events or changes in circumstances 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, 1999. This calculation may not reflect engineering data 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 late 1998 St. Mary sold a package of non-strategic properties in
Oklahoma to ONEOK Resources Company ("ONEOK") 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 June 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 January 2000 Summo issued 1,016,594 shares of its common
stock to the Company as payment of interest on the Company's note receivable
from Summo. On issuance of these shares, the Company's ownership in Summo
increased to 19%.
-25-
<PAGE>
In August 1999 the Company sold its stock in Khanty Mansiysk Oil
Corporation ("KMOC") for $1.9 million and realized a $150,000 gain. The Company
continues to market its receivable from KMOC and in February 2000 elected to
convert the receivable into KMOC 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. This change positioned the Company to use its stock for
future acquisitions.
Box Church Gas gathering, LLC and Roswell, LLC are small majority owned
support entities that service the ArkLaTex region and the Permian Basin,
respectively. The activities of these entities are fully consolidated, and the
minority interest is recorded. Minority interest is the ownership portion of
these two entities held by parties other than the Company.
At the end of 1998 crude oil producers were confronted with
historically low prices and a possibly weak outlook for 1999 based upon future
prices at the time. Natural gas producers were experiencing relative price
stability. During 1999 crude oil availability changed and prices began to
increase. As future prices increased, oil producers who were concerned about
their experiences in 1998 began hedging their remaining 1999 production. Oil
prices continued to increase, and at the end of 1999 some regions of the United
States were experiencing two-fold price increases over the end of 1998. Oil
producers who hedged significant quantities of oil using early 1999 future
pricing recognized hedging losses during 1999. Gas prices as experienced by the
Company continue to remain relatively stable.
This Annual Report on Form 10-K 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-K 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 oil and gas production estimates,
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, including such factors as
uncertainties in cash flow, expected merger benefits, the volatility and level
of oil and natural gas prices, production rates and reserve replacement, reserve
estimates, drilling and operating risks, competition, litigation, environmental
matters, the potential impact of government regulations, and other such matters,
many of which are beyond the control of the Company. Readers are cautioned that
our 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.
-26-
<PAGE>
Results of Operations
The following table sets forth selected operating data for the periods
indicated:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1999 1998 1997
---- ---- ----
(In thousands, except per MCFE data)
<S> <C> <C> <C>
Oil and gas production revenues:
Working interests................................. $69,408 $63,771 $66,957
Louisiana royalties............................... 3,086 6,877 8,807
---------------------------------
Total.......................................... $72,494 $70,648 $75,764
=================================
Net production:
Oil (MBbls)....................................... 1,383 1,275 1,188
Gas (MMcf)........................................ 22,805 25,440 22,900
---------------------------------
MMCFE............................................. 31,103 33,090 30,028
---------------------------------
Average sales price (1):
Oil (per Bbl)..................................... $ 16.56 $ 12.98 $ 18.87
Gas (per Mcf)..................................... $ 2.17 $ 2.13 $ 2.33
Oil and gas production costs:
Lease operating expenses.......................... $13,641 $12,929 $10,463
Production taxes.................................. 5,040 4,076 4,795
---------------------------------
Total.......................................... $18,681 $17,005 $15,258
=================================
Additional per MCFE data:
Sales price....................................... $ 2.33 $ 2.13 $ 2.52
Lease operating expenses.......................... (.44) (.39) (.35)
Production taxes.................................. (.16) (.12) (.16)
---------------------------------
Operating margin............................... $ 1.73 $ 1.62 $ 2.01
=================================
Depletion, depreciation and amortization.......... $ .73 $ .75 $ .61
Impairment of proved properties................... $ .13 $ .53 $ .17
General and administrative........................ $ .29 $ .22 $ .26
</TABLE>
[FN]
- ---------
(1) Includes the effects of the Company's hedging activities.
</FN>
Oil and Gas Production Revenues. Oil and gas production revenues
increased $1.9 million, or 3% to $72.5 million in 1999 compared to $70.6 million
in 1998. Oil production volumes increased 8% and gas production volumes
decreased 10% in 1999 compared to 1998. Average net daily production declined to
85.2 MMCFE in 1999 compared to 90.6 MMCFE in 1998. The increase in oil
production occurred as a result of the Nance acquisition, production increases
at the Parkway Delaware Unit waterflood and the drilling of successful wells in
Montana. Gas production decreased as a result of the loss of production at the
South Horseshoe Bayou Field and the sale of certain Oklahoma properties in
December 1998. This decrease reduced the average daily production.
The average realized oil price for 1999 increased 28% to $16.56 per
Bbl, while average realized gas prices increased 2% to $2.17 per Mcf, from their
respective 1998 levels. The Company hedged approximately 41.4% of its oil
production for 1999 or 572 MBbls at an average NYMEX price of $17.19. The
Company experienced a $2.0 million decrease in oil revenue or $1.45 per Bbl for
1999 on these contracts compared to a $435,000 increase or $.34 per Bbl in 1998.
The Company also hedged 56.2% of its 1999 gas production or 14,085,000 MMBtu at
an average index price of $2.19. The Company experienced a $558,000 decrease in
gas revenues or $.02 per Mcf for 1999 from these hedge contracts compared to a
$1.4 million increase in gas revenues or $.06 per Mcf in 1998.
-27-
<PAGE>
Oil and gas production revenues decreased $5.1 million, or 7% to $70.6
million in 1998 compared to $75.8 million in 1997. Oil production volumes
increased 7% and gas production volumes increased 11% in 1998 compared to 1997.
Average net daily production reached 90.6 MMCFE in 1998 compared to 82.2 MMCFE
in 1997. This production increase resulted from new properties acquired and
drilled during 1998 and late 1997. Major acquisitions affecting the production
increase included the Southwest Mayfield properties in Oklahoma purchased from
Conoco and the Louisiana properties purchased from Henry Production Company in
1997, the acquisition of certain producing properties in Texas from Stroud
Exploration in 1998, and the additional interests purchased in the Siete
properties during 1997 and 1998. Successful drilling results in the South
Horseshoe Bayou and Haynesville fields in Louisiana, the Box Church Field in
Texas and the Company's Oklahoma drilling program also contributed to the 1998
production increase. These production increases were only slightly offset by the
sale of certain Oklahoma properties to ONEOK Resources Company in late 1998.
Oil and Gas Production Costs. Oil and gas production costs consist of
lease operating expense ("LOE") and production taxes. Total production costs
increased $1.7 million, or 10% in 1999 to $18.7 million compared with $17.0
million in 1998, while total oil and gas production costs per MCFE increased 17%
to $.60 in 1999 compared with $.51 in 1998. A $396,000 increase in LOE workover
costs and a $968,000 increase in LOE relating to the Nance and KRE acquisitions
were offset by a $591,000 decrease in LOE at South Horseshoe Bayou and the
December 1998 sale of producing properties in Oklahoma. A $705,000 increase in
production taxes was the result of higher prices for oil production. The
increase in the per MCFE amount is also due to a 10% decrease in gas production
volumes caused by a reduction in volumes at South Horseshoe Bayou and the
December 1998 sale of producing properties in Oklahoma which had lower
production costs per MCFE.
Total production costs increased $1.7 million, or 11% in 1998 to $17.0
million compared with $15.3 million in 1997. Total oil and gas production costs
per MCFE increased 1% to $.51 in 1998 compared to $.51 per MCFE in 1997. A $2.4
million increase in LOE related to a corresponding increase in production for
1998 which was described above and a $1.0 million increase in non-recurring LOE
resulting from increased workover activity. A $700,000 decrease in production
taxes was the result of the decrease in oil and gas revenues in 1998 on which a
portion of production taxes were based.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion and amortization expense ("DD&A") decreased $2.3 million or 9% to
$22.6 million in 1999 compared with $24.9 million in 1998. This decrease was due
to the December 1998 sale of producing properties in Oklahoma. DD&A expense per
MCFE decreased 4% to $.73 in 1999 compared to $.75 in 1998 due to low prices
that affected the Company's oil and gas reserves and net book value at December
31, 1998 and the subsequent recovery of prices which increased the Company's oil
and gas reserves during 1999. This effect was offset during 1999 by a 10%
reduction in gas production caused by decreased production at South Horseshoe
Bayou, the December 1998 sale of producing properties in Oklahoma with lower
DD&A expense per MCFE and decreased royalty production from the fee lands.
Impairment of proved oil and gas properties decreased $13.5 million to $4.0
million in 1999 compared with $17.5 million in 1998. The decrease was caused by
marginal wells drilled in Oklahoma and Louisiana in 1998, the adverse effects of
low oil prices in 1998 and the Company's unsuccessful 1998 deep test at its
Atchafalaya Bay prospect. Of the impairments caused by reserve reductions in
under-performing properties in 1999, $2.6 million related to the Larose
prospect, $246,000 related to the Greensburg prospect and $264,000 related to
several other prospects in Louisiana. A total of $734,000 of impairment related
to nine prospects in Oklahoma.
-28-
<PAGE>
DD&A increased $6.5 million or 36% to $24.9 million in 1998 compared
with $18.4 million in 1997. This increase resulted from increased production
volumes of new properties acquired and drilled in 1998 and late 1997, including
the Southwest Mayfield properties acquired from Conoco in the fourth quarter of
1997. Decreases in reserve volumes caused by the adverse impact of low oil
prices in the Williston Basin and mechanical problems at South Horseshoe Bayou
also contributed to the DD&A increase. DD&A expense per MCFE increased 23% to
$.75 in 1998 compared to $.61 in 1997 due to higher drilling and acquisition
costs per MCFE and the factors mentioned above. Impairment of proved oil and gas
properties increased $12.3 million to $17.5 million in 1998 compared with $5.2
million in 1997. Those charges resulting from a decline in the Company's oil and
gas reserve value due to lower prices in predominantly oil producing fields were
$1.4 million in west Texas and $600,000 in the Williston Basin of North Dakota
and Montana. Other charges were due to reserve volume reductions in
under-performing properties. Of these, $8.9 million and $1.2 million related to
the Atchafalaya and Bayou D'Arbonne prospects, respectively, in Louisiana, $1.2
million related to the Young North prospect in New Mexico, $700,000 related to
the Kirvin/Mann North prospect in Texas and $1.0 million related to several
prospects in Oklahoma. The drilling of two marginal wells in Oklahoma also
resulted in impairments of $600,000 in 1998.
Abandonment and impairment of unproved properties increased $2.1
million or 48% to $6.6 million in 1999 compared to $4.5 million in 1998 due to
the Company's impairment of its remaining costs at South Horseshoe Bayou.
Abandonment and impairment of unproved properties increased $2.4 million or 115%
to $4.5 million in 1998 compared to $2.4 million in 1997 due to additional
impairments taken during 1998.
Exploration. Exploration expense decreased $112,000 or 1% to $11.6
million for 1999 compared with $11.7 million in 1998. Decreases of $565,000 in
geological and geophysical expenses and $600,000 in delay rentals were offset by
increases of $689,000 of dry hole expense and $253,000 of exploration overhead.
Exploration expense increased $4.9 million or 71% to $11.7 million for 1998
compared with $6.8 million in 1997 due to the drilling of ten exploratory dry
holes during 1998 in the Mid-Continent and Gulf Coast regions, compared to
better exploratory drilling results in 1997. The payment of $795,000 in delay
rentals for the Company's Atchafalaya Bay prospect area during 1998 also
contributed to the increase in exploration expense.
General and Administrative. General and administrative expenses
increased $2.1 million or 29% to $9.2 million in 1999 compared to $7.1 million
in 1998 due to a $1.9 million increase in compensation and benefit related
expenses including a $477,000 increase related to the Company's Stock
Appreciation Rights ("SAR") plan. SAR plan expense will decrease in 2000 as the
Company terminated awards under this plan effective November 1996. General and
administrative expenses decreased $548,000 in 1998 compared to $7.6 million in
1997 due to a $358,000 reduction of expenses related to the Company's SAR plan
and a $259,000 reduction in charitable contributions which are based on pre-tax
income.
Minority Interest and Other Operating Expenses. This expense increased
$1.6 million to $1.7 million from $141,000 in 1998 due to increased activity in
St. Mary's 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 $118,000 adjustment for minority interest. Other
operating expenses decreased $140,000 or 50% in 1998 compared with 1997 due to
decreased activity in the pending South Horseshoe Bayou litigation.
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% from 37% in June 1999. Consequently, the Company now accounts for
its investment in Summo under the cost method. Equity in the net loss of Summo
was $58,000 in 1999, $661,000 in 1998, and $526,000 in 1997. The losses in 1998
and 1997 are due to general and administrative expenses associated with the
expansion of Summo's Denver office and with the appeals process for permitting
of the Lisbon Valley Copper Project. The Company's ownership in Summo was 37% in
1998 and 1997.
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<PAGE>
Non-Operating Income and Expense. Net non-operating expense decreased
$1.1 million to $75,000 of net income in 1999 compared to $1.0 million of net
expense in 1998 due to decreased interest expense attributable to reduced
long-term debt during 1999, and recognition of interest income from loans made
to Summo. Debt was decreased in 1999 with proceeds from the sale of the Oklahoma
properties in late 1998. Net non-operating expense increased $928,000 to $1.0
million in 1998 due to interest expense for increased borrowings in 1998 to fund
capital expenditures, and due to lower borrowings in 1997 resulting from cash
received from the sale of common stock.
Income Taxes. Income taxes provided a net benefit of $406,000 for 1999
resulting in an effective tax rate of 125%. The effective rate reflects the
effect of the book net operating loss before tax and the compounded effect of
alternative fuel credits allowed under Internal Revenue Code Section 29 incurred
in years when the Company reports a pre-tax book loss. Income tax benefit was
$5.4 million for 1998 and income tax expense was $12.3 million in 1997,
resulting in effective tax rates of 38% and 35%, respectively. The expense
amount in 1997 reflects higher net income from continuing operations before
income taxes compared to the subsequent year, offset partially by the
utilization of Section 29 tax credits.
Net Income(Loss). Net income for 1999 was $82,000 compared to a net
loss of $8.8 million for 1998. A 2% increase in gas prices, a 28% increase in
oil prices and an 8% increase in oil production volumes were partially offset by
a 10% decrease in gas production volumes for the year and resulted in a $1.9
million or 3% increase in oil and gas production revenues. The combination of
impairments of proved properties and DD&A decreased $15.8 million from 1998
amounts and were partially offset by a $1.7 million increase in oil and gas
production costs, a $2.2 million increase in unproved property impairments, and
a $2.1 million increase in general and administrative expenses. A $1.2 million
increase in other revenues and a $1.1 million decrease in non-operating income
and expenses were partially offset by a $1.6 million increase in minority
interest and other expense. Income tax benefit decreased by $5.0 million in
1999. Activity in 1998 not affecting net income in 1999 included $7.7 million in
gains on sales of proved properties, a $4.6 million writedown of the receivable
from KMOC and $4.6 million in losses related to the Company's investment
activity in Summo Minerals.
Net loss for 1998 was $8.8 million compared to net income of $23.1
million for 1997. A 9% reduction in gas prices and a 31% reduction in oil prices
were only partially offset by an 11% increase in gas production volumes and a 7%
increase in oil production volumes for the year. This resulted in a $5.1 million
or 7% reduction in oil and gas production revenues. Gains on sales of proved
properties of $7.7 million were offset by impairments of proved and unproved
properties and increased DD&A expense resulting from lower reserve values;
writedowns of the Russian convertible receivable and the Company's investment in
Summo Minerals; and increased exploration expense brought about by unsuccessful
exploration projects.
The Company also realized gains net of income taxes from the sale of
discontinued real estate of $34,000 in 1998, and $488,000 in 1997.
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. In 1997
the Company financed a large portion of its exploration and development programs
with the proceeds from its secondary public offering of common stock. The
Company continually reviews its capital expenditure budget based on changes in
cash flow and other factors.
-30-
<PAGE>
Cash Flow. The Company's net cash provided by operating activities
decreased $4.6 million or 10% to $40.8 million in 1999 compared to $45.4 million
in 1998. The decrease was caused by a $4.6 million decrease in accounts payable
related to oil and gas production costs and general and administrative expense.
The $1.9 million increase in oil and gas revenues was offset by a corresponding
increase in accrued oil and gas receivables. A $1.6 million increase in minority
interest and other operating expense was offset by a $764,000 increase in other
revenues and a $1.1 million decrease in cash paid for interest expense. Net cash
provided by operating activities increased 5% to $45.4 million in 1998 compared
to $43.1 million in 1997. A $9.8 million decrease in accounts receivable
resulting from lower oil and gas prices and reduced drilling activity and a $2.4
million increase in unproved property impairments were offset by a $5.1 million
decrease in oil and gas revenue, a $4.3 million increase in prepaid expenses and
a $400,000 increase in cash paid for interest expense.
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 $35.8 million, $40.5 million, and $41.5
million, in 1999, 1998, and 1997, respectively.
The Company made cash payments of approximately $333,000 in 1999,
$363,000 in 1998 and $1.6 million in 1997 in satisfaction of liabilities
previously accrued under the SAR plan.
Net cash used in investing activities decreased $14.8 million or 40% in
1999 to $22.2 million compared to $37.0 million in 1998. The decrease is due to
reduction in capital expenditures, $2.1 million received from the sale of the
subsidiary that held the KMOC stock, $2.6 million from the Company's investment
in Summo and $12.7 million in cash received as a result of the Company's
purchase of Nance and KRE offset by a $20.9 million decrease in proceeds
received from property sales. Nance and KRE were acquired with St. Mary common
stock. Consequently, the value of the common stock issued is not reflected in
net cash used in investing activities. Total 1999 capital expenditures for cash,
including acquisitions of oil and gas properties, decreased $18.3 million or 31%
to $40.3 million in 1999 compared to $58.6 million in 1998 due to a decrease in
drilling activity in 1999.
Net cash used in investing activities decreased $30.5 million or 45% in
1998 to $37.0 million compared to $67.5 million in 1997. The decrease is due to
a $10.1 million increase in proceeds from sales of oil and gas properties in
1998, including the sale of the Russian joint venture in 1997, and a decrease of
$23.1 million in cash paid for acquisitions of oil and gas properties in 1998.
Total 1998 capital expenditures, including acquisitions of oil and gas
properties, decreased $22.9 million or 28% to $58.6 million in 1998 compared to
$81.5 million in 1997 due to a $23.1 million decrease in acquisitions in 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 $17.2 million, $32.1 million, and $65.8 million in 1999, 1998, and
1997, respectively.
The Company was able to deposit the majority of the proceeds from the
sales of oil and gas properties in 1997 into qualified tax escrow accounts and
apply these funds to acquisitions of oil and gas properties in 1997, allowing
tax-free exchanges of these properties for income tax purposes. Portions of the
proceeds from sales of oil and gas properties in 1998 were also 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 used in financing activities increased $4.4 million to $12.1
million in 1999 compared to $7.7 million in 1998. The increase is due to a $6.6
million decrease in long-term debt partially offset by a $1.9 million decrease
in stock repurchase payments.
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<PAGE>
Net cash provided by (used in) financing activities decreased $35.8
million to net cash used of $7.7 million in 1998 compared to net cash provided
of $28.1 million in 1997. The decrease in cash provided was due to the $51.2
million received in 1997 from the secondary public offering of common stock
compared to $173,000 from employee stock purchases in 1998. This change was
partially offset by a $3.2 million decrease in long-term debt in 1998 compared
to a $21.0 million decrease in 1997. The Company also spent $2.5 million in 1998
to repurchase shares of its own common stock.
The Company had $14.2 million in cash and cash equivalents and had
working capital of $13.4 million as of December 31, 1999 compared to $7.8
million in cash and cash equivalents and working capital of $9.8 million as of
December 31, 1998. The net change in working capital results from a $6.4 million
increase in cash and cash equivalents and a $6.0 million increase in accounts
receivable, prepaid expenses and refundable income taxes that was offset by an
$8.8 million increase in accounts payable and accrued liabilities.
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 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 December 31, 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 December 31, 1999 and 1998, $13.0 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%. At December 31, 1999 the Company's debt to
capitalization ratio as defined under the credit agreement was 6.4%.
Panterra, in which the Company owned 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
facility were $12.0 million as of December 31, 1998. St. Mary's portion of the
December 31, 1998 balance was $8.9 million. The Company used its primary credit
facility to retire the balance due on the Panterra credit facility in August
1999, and the $21 million borrowing base was transferred to the Company's
primary 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. This change allows the Company to make
acquisitions without the use of its cash or credit facility.
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 and 1999 the Company repurchased a total of 182,800 shares of its
common stock under the program for $3.0 million at a weighted-average price of
$16.38 per share. In early 2000 the Company repurchased an additional 15,000
shares for $22.99 per share. 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.
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<PAGE>
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. The following table sets forth certain
information regarding the costs incurred by the Company in its oil and gas
activities during the periods indicated.
<TABLE>
<CAPTION>
Capital and Exploration Expenditures
------------------------------------
For the Years Ended
December 31,
------------
1999 1998 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Development $ 22,166 $ 32,191 $ 39,030
Exploration:
Domestic 20,809 17,767 15,311
International - - 16
Acquisitions:
Proved 33,080 4,204 27,291
Unproved 15,129 3,693 7,565
----------------------------------
Total $ 91,184 $ 57,855 $ 89,213
==================================
</TABLE>
The Company's total costs incurred in 1999 increased $33.3 million or
58% compared to 1998. Proved property acquisitions increased $40.8 million in
1999. In June 1999 the Company acquired Nance and Quanterra Alpha Limited
Partnership in a stock transaction; the property acquisition amount included
above was $6.1 million. Subsequent to this transaction, Nance as a wholly owned
subsidiary of the Company purchased $1.2 million of properties in several small
acquisitions in the Williston Basin. In December 1999 the Company acquired KRE
in a stock transaction; the property acquisition amount included above was $33.6
million. Follow-on acquisitions relating to interests purchased in the Permian
Basin amounted to $327,000 in 1999. Certain properties were acquired in
Louisiana and the Gulf of Mexico for $2.8 million. Several smaller acquisitions
in other core areas were also completed during 1999 totaling $1.0 million. The
Company spent $46.2 million in 1999 for unproved property acquisitions and
domestic exploration and development compared to $53.7 million in 1998.
The Company's total costs incurred in 1998 decreased $31.4 million or
35% compared to 1997. Proved property acquisitions decreased $23.1 million in
1998. In December 1998 Panterra acquired certain properties in the Williston
Basin for $2.8 million, of which the Company's share was $2.1 million. Follow-on
acquisitions relating to interests purchased in the Permian Basin in 1996
amounted to $1.2 million in 1998, and certain properties were acquired in Texas
for $510,000. Several smaller acquisitions were also completed during 1998
totaling $390,000. The Company spent $53.7 million in 1998 for unproved property
acquisitions and domestic exploration and development compared to $61.9 million
in 1997.
Commitments. As of December 31, 1999 the Company, as Operator, had a
turnkey contract in place with a drilling contractor for the Company's 1999 test
well at South Horseshoe Bayou. St. Mary's obligation to pay $5.6 million to the
contractor was contingent upon the well reaching a depth of 16,000 feet. In
February 2000 the well reached the specified depth, and St. Mary paid the amount
due under the contract. The Company's net share of the amount paid under the
contract was $2.3 million.
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 2000.
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.
-33-
<PAGE>
The Company anticipates spending approximately $105.0 million for
capital and exploration expenditures in 2000 with $60.5 million allocated for
ongoing exploration and development in its core operating areas, $32.5 million
for niche acquisitions of producing properties and $12.0 million for
large-target, higher-risk exploration and development.
Anticipated ongoing exploration and development expenditures for each
of the Company's core areas include $21.0 million in the Mid-Continent region,
$13.0 million in the Gulf Coast and Gulf of Mexico region, $10.0 million in the
ArkLaTex region, $12.0 million in the Williston Basin and $4.5 million allocated
within the Permian Basin and other.
The results of operations also include the results of the Company's
large-target exploration efforts. The Company has several prospects in its
pipeline of large-target exploration ideas and expects to test some of these
prospects in 2000.
On August 5, 2000, the Company and its partners will assume control of
a 30,450-acre top lease in the North Ward Estes Field in Ward County, Texas. The
Company will have a 21.2% working interest in the production from approximately
400 wells and the future development and production rights on this 50 square
mile property. The top lease will continue in effect for as long as oil and/or
gas is produced in paying quantities.
The amount and allocation of future capital and exploration
expenditures will depend upon a number of factors, including the number of
available acquisition opportunities and the Company's ability to assimilate such
acquisitions. Also, 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 activities 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 in 1999 is an example of this strategy.
In June 1999 the Company participated in a financing package
arrangement with 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 Company's total investment in Summo and to total accrued
interest on the note receivable resulting in a remaining net book value of $1.6
million, 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 continually analyzes its net investment in Summo and the effect of
worldwide copper price and inventory fluctuations on Summo's stock price. Future
development and financial success of Lisbon Valley are dependent upon these
factors. The Company owned 4.96 million shares or 18% of Summo as of December
31, 1999. In January 2000 Summo issued 1.02 million shares of its common stock
to the Company as payment of interest on the Company's note receivable from
Summo. On issuance of these shares the Company's ownership increased to 19%.
-34-
<PAGE>
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 a company's results of operations, cash flow and financial
condition. Beginning in 1998 the Company developed and implemented a formal plan
to mitigate the impact of Year 2000 compliance. The plan was fully implemented
before December 31, 1999. To date the Company has not encountered any material
Year 2000 compliance problems and has suffered no material adverse effects from
this issue.
Through December 31, 1999, the Company 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.
The Company did not specifically track its internal costs of addressing the Year
2000 issue. However, management does not believe these internal costs were
material.
The Company currently has no reason to believe that any Year 2000
compliance failures occurred or will occur or that its principal vendors,
customers and business partners are not Year 2000 compliant. However, there can
be no assurance that all Year 2000 problems have been identified and corrected.
Therefore, there can be no assurance that currently unknown Year 2000 issues
will not materially impact the Company's results of operations or adversely
affect its relationships with vendors, customers and other business partners in
the year 2000.
Accounting Matters
In June 1998, the FASB issued 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. 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" which extended the effective date of SFAS No. 133 to
all fiscal quarters of all fiscal years beginning after June 15, 2000. The
Company is currently reviewing the effects this Statement will have on the
financial statements in relation to the Company's hedging activities.
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.
-35-
<PAGE>
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. The
last half of 1998 and most of the first quarter of 1999 was characterized by
historically low oil prices and weakening gas markets. Investment funds left the
oil and gas sector and caused an abundance of available drilling rigs,
personnel, supplies and services with a corresponding reduction of costs. Oil
and gas prices have increased since the first quarter of 1999. The number of
active drilling rigs has increased along with the cost of personnel, supplies
and services. If oil and gas prices continue to increase, there could be a
return to shortages and corresponding increases in the cost to the Company of
exploration, drilling and production of oil and gas.
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 19% of its estimated 2000 gas
production at an average fixed price of $2.43 per MMBtu and approximately 22% of
its estimated 2000 oil production at an average fixed price of $20.96 per Bbl.
The Company has hedged less than 1% of its estimated 2001 gas and oil production
at average fixed prices of $2.46 per MMBtu and $15.76 per Bbl, respectively. In
2000 the Company has price collars on approximately 23% of its estimated gas
production with price ceilings between $2.50 and $2.94 per MMBtu and price
floors between $2.00 and $2.30 per MMBtu and approximately 27% of its estimated
oil production with price ceilings between $17.75 and $27.00 per Bbl and price
floors between $15.00 and $19.50 per Bbl. In 2001 the Company also has price
collars on approximately 22% of its estimated gas production with price ceilings
between $2.72 and $3.04 per MMBtu and price floors between $2.25 and $2.50 per
MMBtu and approximately 7% of its oil production with price ceilings between
$20.64 and 20.90 per Bbl and price floors between $16.44 and $16.70 per Bbl.
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 Audit Committee of the Company's Board of Directors also
periodically reviews these programs.
-36-
<PAGE>
Commodity Price Risk. The Company uses various hedging arrangements to
manage the Company's exposure to price risk 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 any price increases associated
with the hedged commodity. A hypothetical 10% change in the year-end market
prices of commodity-based swaps and futures contracts on a notional amount of
26.1 million MMBtu would have caused a potential $45,000 change in net income
(loss) before income taxes for the Company for contracts in place on December
31, 1999. A 10% change in the year-end market prices of commodity-based swaps
and future contracts on a notional amount of 1,398 MBbls would have caused a
potential $859,000 change in net income (loss) before income taxes for the
Company for oil contracts in place on December 31, 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 year 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. The sensitivity analysis presents the
hypothetical change in fair value of those financial instruments held by the
Company at December 31, 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 December 31, 1999, the Company had floating rate
debt of $13.0 million and had no fixed rate debt. Assuming constant debt levels,
the results of operations and cash flows impact for the next year resulting from
a one percentage point change in interest rates would be approximately $130,000
before taxes.
-37-
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements that constitute Item 8 follow the
text of this report. An index to the Consolidated Financial Statements and
Schedules appears in Item 14(a) of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item is incorporated by reference from
the Company's proxy statement for the 2000 annual meeting of stockholders to be
filed no later than April 30, 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from
the Company's proxy statement for the 2000 annual meeting of stockholders to be
filed no later than April 30, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by this Item is incorporated by reference from
the Company's proxy statement for the 2000 annual meeting of stockholders to be
filed no later than April 30, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference from
the Company's proxy statement for the 2000 annual meeting of stockholders to be
filed no later than April 30, 2000.
-38-
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement
Schedules:
Report of Independent Public Accountants........................... F-1
Consolidated Balance Sheets........................................ F-2
Consolidated Statements of Operations.............................. F-3
Consolidated Statements of Stockholders' Equity.................... F-4
Consolidated Statements of Cash Flows.............................. F-5
Notes to Consolidated Financial Statements......................... F-7
All other schedules are omitted because the required information is not
applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.
(b) Reports on Form 8-K. One report on Form 8-K dated December 29, 1999
was filed during the last quarter of 1999. This report on Form 8-K included Item
2 and Item 7 regarding the acquisition of King Ranch Energy, Inc. and Item 5
regarding the appointment of Robert L. Nance to St. Mary's board of directors to
replace Richard C. Kraus, who resigned.
(c) Exhibits. The following exhibits are filed with or incorporated
into this report on Form 10-K:
Exhibit
Number Description
- ------ -----------
2.1 Agreement and Plan of Merger dated July 27, 1999 among St. Mary Land &
Exploration Company, St. Mary Acquisition Corporation, King Ranch, Inc.
and King Ranch Energy, Inc. as amended by Amendment No. 1 and Amendment
No. 2 to Agreement and Plan of Merger dated November 8, 1999 (included
as Annex A to the joint proxy/consent statement and prospectus
contained in the registrant's Amendment #2 to Form S-4/A (Registration
No. 333-85537) filed on November 12, 1999 and incorporated herein by
reference)
2.2 Stock Exchange Agreement dated June 1, 1999 among St. Mary Land &
Exploration Company, Robert L. Nance, Penni W. Nance, Amy Nance Cebull
and Robert Scott Nance (filed as Exhibit 10.27 to the registrant's
Registration Statement on Form S-4 (Registration No. 333-85537) filed
on August 19, 1999 and incorporated herein by reference)
2.3 Stock Exchange Agreement dated June 1, 1999 among St. Mary Land &
Exploration Company, Robert L. Nance and Robert T. Hanley (filed as
Exhibit 10.28 to the registrant's Registration Statement on Form S-4
(Registration No. 333-85537) filed on August 19, 1999 and incorporated
herein by reference)
2.4 Stock Exchange Agreement dated June 1, 1999 between St. Mary Land &
Exploration Company and Robert T. Hanley (filed as Exhibit 10.29 to the
registrant's Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein by
reference)
3.1 Restated Certificate of Incorporation of St. Mary Land & Exploration
Company dated November 11, 1992 (filed as Exhibit 3.1A to the
registrant's Registration Statement on Form S-1 (Registration No.
33-53512) and incorporated herein by reference)
3.2 Certificate of Amendment to Certificate of Incorporation of St. Mary
Land & Exploration Company dated June 22, 1998 (filed as Exhibit 3.2 to
the registrant's Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein by
reference)
3.3 Restated By-laws of St. Mary Land & Exploration Company as of June 15,
1994 (filed as Exhibit 3.3 to the registrant's Registration Statement
on Form S-4 (Registration No. 333-85537) filed on August 19, 1999 and
incorporated herein by reference)
-39-
<PAGE>
Exhibit
Number Description
- ------ -----------
4.1 St. Mary Land & Exploration Company Shareholder Rights Plan adopted on
July 15, 1999 (filed as Exhibit 4.1 to the registrant's Quarterly
Report on Form 10-Q/A (File No. 0-20872) for the quarter ended June 30,
1999 and incorporated herein by reference)
10.1 Stock Option Plan (filed as Exhibit 10.3 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512) and
incorporated herein by reference)
10.2 Stock Appreciation Rights Plan (filed as Exhibit 10.4 to the
registrant's Registration Statement on Form S-1 (Registration No.
33-53512) and incorporated herein by reference)
10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's Registration
Statement on Form S-1 (Registration No. 33-53512) and incorporated
herein by reference)
10.4 Net Profits Interest Bonus Plan (filed as Exhibit 10.6 to the
registrant's Registration Statement on Form S-1 (Registration No.
33-53512) and incorporated herein by reference)
10.5 Summary Plan Description/Pension Plan dated January 1, 1985 (filed as
Exhibit 10.7 to the registrant's Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by reference)
10.6 Non-qualified Unfunded Supplemental Retirement Plan, as amended (filed
as Exhibit 10.8 to the registrant's Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by reference)
10.7 Summary Plan Description Custom 401(k) Plan and Trust (filed as Exhibit
10.10 to the registrant's Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by reference)
10.8 Stock Option Agreement - Mark A. Hellerstein (filed as Exhibit 10.11 to
the registrant's Registration Statement on Form S-1 (Registration No.
33-53512) and incorporated herein by reference)
10.9 Stock Option Agreement - Ronald D. Boone (filed as Exhibit 10.12 to the
registrant's Registration Statement on Form S-1 (Registration No.
33-53512) and incorporated herein by reference)
10.10 Employment Agreement between Registrant and Mark A. Hellerstein (filed
as Exhibit 10.13 to the registrant's Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by reference)
10.11 Summary Plan Description 401(k) Profit Sharing Plan( filed as Exhibit
10.34 to the registrant's Annual Report on Form 10-K (File No. 0-20872)
for the year ended December 31, 1994 and incorporated herein by
reference)
10.12 Summary Plan Description/Pension Plan dated December 30, 1994 (filed as
Exhibit 10.35 to the registrant's Annual Report on Form 10-K (File No.
0-20872) for the year ended December 31, 1994 and incorporated herein
by reference)
10.13 Second Restated Partnership Agreement - Panterra Petroleum (filed as
Exhibit 10.41 to the registrant's Annual Report on Form 10-K (File No.
0-20872) for the year ended December 31, 1995 and incorporated herein
by reference)
10.14 Purchase and Sale Agreement between Siete Oil & Gas Corporation and St.
Mary Land & Exploration Company (filed as Exhibit 10.42 filed to the
registrant's Current Report on Form 8-K (File No. 0-20872) dated June
28, 1996, as amended by Registrant's Current Report on Form 8-K/A (File
No. 0-20872) dated June 28, 1996 and incorporated herein by reference)
10.15 Acquisition Agreement regarding the sale of St. Mary Land & Exploration
Company's interest in the Russian joint venture (filed as Exhibit 10.43
filed to the registrant's Current Report on Form 8-K (File No. 0-20872)
dated December 16, 1996 and incorporated herein by reference)
10.16 Employment Agreement between registrant and Ralph H. Smith, effective
October 1, 1995 (filed as Exhibit 99 filed to the registrant's Current
Report on Form 8-K (File No. 0-20872) dated January 28, 1997 and
incorporated herein by reference)
10.17 St. Mary Land & Exploration Company Employee Stock Purchase Plan (filed
as Exhibit 10.48 filed to the registrant's Annual Report on Form 10-K
(File No. 0-20872) for the year ended December 31, 1997 and
incorporated herein by reference)
-40-
<PAGE>
Exhibit
Number Description
- ------ -----------
10.18 Credit Agreement dated June 30, 1998 (filed as Exhibit 10.52 to the
registrant's Quarterly Report on Form 10-Q (File No. 0-20872) for the
quarter ended June 30, 1998 and incorporated herein by reference)
10.19 Purchase and Sale Agreement dated November 12, 1998 between ONEOK
Resources Company (filed as Exhibit 10.53 filed to the registrant's
Current Report on Form 8-K (File No. 0-20872) dated December 30, 1998
and incorporated herein by reference)
10.20 Credit Agreement between Panterra Petroleum and Colorado National Bank
dated June 17, 1997 (filed as Exhibit 10.25 to the registrant's Annual
Report on Form 10-K (File No. 0-20872) for the year ended December 31,
1998 and incorporated herein by reference)
10.21 Agreement between Summo Minerals Corporation, Summo USA Corporation,
St. Mary Land & Exploration Company, and St. Mary Minerals Inc. re: the
formation of Lisbon Valley Mining Company dated May 15, 1997 (filed as
Exhibit 10.26 to the registrant's Annual Report on Form 10-K (File No.
0-20872) for the year ended December 31, 1998 and incorporated herein
by reference)
10.22 Pledge and Security Agreement From Summo USA Corporation and Lisbon
Valley Mining Co. LLC to St. Mary Minerals Inc. dated November 23, 1998
(filed as Exhibit 10.27 to the registrant's Annual Report on Form 10-K
(File No. 0-20872) for the year ended December 31, 1998 and
incorporated herein by reference)
10.23 Deed of Trust, Assignment of Rents and Security Agreement by Lisbon
Valley Mining Co. LLC and Stewart Title Guaranty Company for the
benefit of St. Mary Minerals Inc. dated November 23, 1998 (filed as
Exhibit 10.28 to the registrant's Annual Report on Form 10-K (File No.
0-20872) for the year ended December 31, 1998 and incorporated herein
by reference)
10.24 St. Mary Land & Exploration Company Incentive Stock Option Plan, As
Amended on March 25, 1999 (filed as Exhibit 10.1 to registrant's
Quarterly Report on Form 10-Q (File No. 0-20872) for the quarter ended
March 31, 1999 and incorporated herein by reference)
10.25 St. Mary Land & Exploration Company Stock Option Plan, As Amended on
March 25, 1999 (filed as Exhibit 10.2 to registrant's Quarterly Report
on Form 10-Q (File No. 0-20872) for the quarter ended March 31, 1999
and incorporated herein by reference)
10.26 Net Profits Interest Bonus Plan, As Amended on September 19, 1996 and
July 24, 1997 and January 28, 1999 filed as Exhibit 10.3 to
registrant's Quarterly Report on Form 10-Q (File No. 0-20872) for the
quarter ended March 31, 1999 and incorporated herein by reference)
10.27 Loan and Stock Purchase Agreement dated June 25, 1999 among Resource
Capital Fund L.P., St. Mary Land & Exploration Company and St. Mary
Minerals Inc.(filed as Exhibit 10.30 to the registrant's Registration
Statement on Form S-4 (Registration No. 333-85537) filed on August 19,
1999 and incorporated herein by reference)
10.28 Credit Agreement dated June 25, 1999 among Summo Minerals Corporation,
Summo USA Corporation, Resource Capital Fund L.P. and St. Mary Minerals
Inc.(filed as Exhibit 10.31 to the registrant's Registration Statement
on Form S-4 (Registration No. 333-85537) filed on August 19, 1999 and
incorporated herein by reference)
10.29 Replacement Promissory dated June 25, 1999 payable to St. Mary Minerals
Inc. in the amount of $1,400,000 (filed as Exhibit 10.32 to the
registrant's Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein by
reference)
10.30 Pledge and Security Agreement dated June 25, 1999 among Summo Minerals
Corporation, Resource Capital Fund L.P., and St. Mary Minerals
Inc.(filed as Exhibit 10.33 to the registrant's Registration Statement
on Form S-4 (Registration No. 333-85537) filed on August 19, 1999 and
incorporated herein by reference)
10.31 Pledge and Security Agreement dated June 25, 1999 among Summo USA
Corporation, Resource Capital Fund L.P., and St. Mary Minerals Inc.
(filed as Exhibit 10.34 to the registrant's Registration Statement on
Form S-4 (Registration No. 333-85537) filed on August 19, 1999 and
incorporated herein by reference)
-41-
<PAGE>
Exhibit
Number Description
- ------ -----------
10.32 Warrant Agreement dated June 25, 1999 among Summo Minerals Corporation,
Resource Capital Fund L.P. and St. Mary Minerals Inc. (filed as Exhibit
10.35 to the registrant's Registration Statement on Form S-4
(Registration No. 333-85537) filed on August 19, 1999 and incorporated
herein by reference)
21.1* Subsidiaries of Registrant
23.1* Consent of Arthur Andersen LLP
23.2* Consent of Ryder Scott Company, L.P.
24.1* Power of Attorney (included on signature page of this document)
27.1* Financial Data Schedule
* Filed herewith.
(d) Financial Statement Schedules. See Item 14(c) above.
-42-
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries:
We have audited the accompanying consolidated balance sheets of St. Mary Land &
Exploration Company (a Delaware corporation) and subsidiaries as of December 31,
1999 and 1998, and the related consolidated statements of operations,
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of St. Mary Land &
Exploration Company and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
/s/ARTHUR ANDERSEN LLP
Denver, Colorado,
February 17, 2000
F-1
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY DATA
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
<TABLE>
<CAPTION>
ASSETS December 31,
------ ------------
1999 1998
---- ----
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 14,195 $ 7,821
Accounts receivable 22,971 17,937
Prepaid expenses and other 2,173 795
Refundable income taxes 26 391
Deferred income taxes 90 125
----------------------
Total current assets 39,455 27,069
----------------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 292,323 241,021
Less accumulated depletion, depreciation and amortization (142,680) (124,541)
Unproved oil and gas properties, net of impairment
allowance of $8,984 in 1999 and $5,987 in 1998 28,556 25,588
Other property and equipment, net of accumulated depreciation
of $3,033 in 1999 and $2,294 in 1998 2,465 1,757
----------------------
180,664 143,825
Other assets: ----------------------
Khanty Mansiysk Oil Corporation receivable and stock 5,110 6,839
Summo Minerals Corporation investment and receivable 1,655 2,869
Restricted cash - 720
Other assets 3,554 3,175
----------------------
10,319 13,603
----------------------
$ 230,438 $ 184,497
======================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 25,743 $ 16,926
Current portion of stock appreciation rights 272 358
----------------------
Total current liabilities 26,015 17,284
----------------------
Long-term liabilities:
Long-term debt 13,000 19,398
Deferred income taxes 501 11,158
Stock appreciation rights 455 422
Other noncurrent liabilities 1,380 1,493
----------------------
15,336 32,471
----------------------
Commitments and contingencies (Notes 1,6,7,8)
----------------------
Minority interest 315 -
----------------------
Stockholders' equity:
Common stock, $.01 par value: authorized - 50,000,000 shares;
issued and outstanding - 13,946,955 shares in 1999 and
10,992,447 shares in 1998 139 110
Additional paid-in capital 124,114 67,761
Treasury stock - 182,800 shares in 1999 and 147,800shares in 1998, at cost (2,995) (2,470)
Retained earnings 67,230 69,341
Unrealized gain on marketable equity securities, net of taxes 284 -
----------------------
Total stockholders' equity 188,772 134,742
----------------------
$ 230,438 $ 184,497
======================
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-2
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Operating revenues:
Oil and gas production $ 72,494 $ 70,648 $ 75,764
Gain on sale of Russian joint venture - - 9,671
Gain (loss) on sale of proved properties (55) 7,685 4,220
Other oil and gas revenue 1,166 352 1,145
Other revenues 416 59 246
----------------------------------
Total operating revenues 74,021 78,744 91,046
----------------------------------
Operating expenses:
Oil and gas production 18,681 17,005 15,258
Depletion, depreciation and amortization 22,574 24,912 18,366
Impairment of proved properties 3,982 17,483 5,202
Exploration 11,593 11,705 6,847
Abandonment and impairment of unproved properties 6,616 4,457 2,077
General and administrative 9,172 7,097 7,645
Writedown of Russian convertible receivable - 4,553 -
Writedown of investment in Summo Minerals Corporation - 3,949 -
Loss in equity investees 58 661 325
Minority interest and other 1,744 141 281
----------------------------------
Total operating expenses 74,420 91,963 56,001
----------------------------------
Income (loss) from operations (399) (13,219) 35,045
Nonoperating income and (expense):
Interest income 1,008 638 1,043
Interest expense (933) (1,665) (1,142)
----------------------------------
Income (loss) from continuing operations before income taxes (324) (14,246) 34,946
Income tax expense (benefit) (406) (5,415) 12,325
----------------------------------
Income (loss) from continuing operations 82 (8,831) 22,621
Gain on sale of discontinued operations, net of taxes
of $17 in 1998 and $252 in 1997 - 34 488
----------------------------------
Net income (loss) $ 82 $ (8,797) $ 23,109
==================================
Basic earnings per common share:
Income (loss) from continuing operations $ .01 $ (.81) $ 2.13
Gain on sale of discontinued operations - - .05
----------------------------------
Basic net income (loss) per common share $ .01 $ (.81) $ 2.18
==================================
Diluted earnings per common share:
Income (loss) from continuing operations $ .01 $ (.81) $ 2.10
Gain on sale of discontinued operations - - .05
---------------------------------
Diluted net income (loss) per common share $ .01 $ (.81) $ 2.15
==================================
Basic weighted average shares outstanding 11,099 10,937 10,620
=================================
Diluted weighted average shares outstanding 11,164 10,937 10,753
=================================
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-3
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands, except share amounts)
<TABLE>
<CAPTION>
Accumulated
Common Stock Additional Treasury Stock Other Total
--------------- Paid-in Retained ---------------- Comprehensive Stockholder's
Shares Amount Capital Earnings Shares Amount Income Equity
--------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1996 8,759,214 $ 88 $ 15,801 $ 59,303 - $ - $ (32) $ 75,160
Comprehensive income:
Net income - - - 23,109 - - - 23,109
Unrealized gain on marketable equity
securities, net of taxes - - - - - - 32 32
------
Total comprehensive income 23,141
------
Cash dividends, $ .20 per share - - - (2,084) - - - (2,084)
Purchase and retirement of common stock (55) - (2) - - - - (2)
Sale of common stock, net of income tax
benefit of stock option exercises 2,217,664 22 51,627 - - - - 51,649
Directors' stock compensation 3,600 - 68 - - - - 68
------------------------------------------------------------------------------------
Balance, December 31, 1997 10,980,423 110 67,494 80,328 - - - 147,932
Comprehensive income:
Net loss - - - (8,797) - - - (8,797)
-------
Total comprehensive income (8,797)
-------
Cash dividends, $ .20 per share - - - (2,190) - - - (2,190)
Treasury stock purchases - - - - (147,800) (2,470) - (2,470)
Issuance for Employee Stock Purchase Plan 8,424 - 172 - - - - 172
Directors' stock compensation 3,600 - 95 - - - - 95
------------------------------------------------------------------------------------
Balance, December 31, 1998 10,992,447 110 67,761 69,341 (147,800) (2,470) - 134,742
Comprehensive income:
Net Income - - - 82 - - - 82
Unrealized gain on marketable equity
securities, net of taxes - - - - - - 284 284
-------
Total comprehensive income 366
-------
Cash dividends, $ .20 per share - - - (2,193) - - - (2,193)
Treasury stock purchases - - - - (35,000) (525) - (525)
Issuance for Employee Stock Purchase Plan 16,397 - 258 - - - - 258
Employee Stock Purchase Plan disqualified
distributions - - 20 - - - - 20
Sale of common stock, net of income
tax benefit of stock option exercises 8,830 - 124 - - - - 124
Directors' stock compensation 3,600 - 57 - - - - 57
Issuance of common stock for Acquisition
of Nance Petroleum Corporation 259,494 3 3,088 - - - - 3,091
Issuance of common stock for Acquisition
of King Ranch Energy, Inc 2,666,187 26 52,806 - - - - 52,832
------------------------------------------------------------------------------------
Balance, December 31, 1999 13,946,955 $ 139 $124,114 $ 67,230 (182,800) $(2,995) $ 284 $ 188,772
====================================================================================
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-4
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1999 1998 1997
---- ---- ----
Reconciliation of net income to net cash provided by operating activities:
<S> <C> <C> <C>
Net income (loss) $ 82 $ (8,797) $ 23,109
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Gain on sale of Russian joint venture - - (9,671)
Writedown of Russian convertible receivable - 4,553 -
Writedown of investment in Summo Minerals Corporation - 3,949 -
Loss (gain) on sale of proved properties 55 (7,685) (4,220)
Depletion, depreciation and amortization 22,574 24,912 18,366
Impairment of proved properties 3,982 17,483 5,202
Exploration 4,991 4,892 1,638
Abandonment and impairment of unproved properties 6,616 4,457 2,077
Loss in equity investees 58 661 325
Deferred income taxes (898) (5,431) 10,799
Other (29) 378 428
----------------------------------
37,431 39,372 48,053
Changes in current assets and liabilities:
Accounts receivable 4,983 6,502 (3,235)
Prepaid expenses 839 (2,109) 2,162
Refundable income taxes 365 (145) (189)
Accounts payable and accrued expenses (2,812) 1,762 (2,359)
Stock appreciation rights (86) 7 (1,199)
Deferred income taxes 35 (3) (122)
----------------------------------
Net cash provided by operating activities 40,755 45,386 43,111
----------------------------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 1,056 23,380 7,723
Capital expenditures (34,994) (54,375) (54,164)
Acquisition of oil and gas properties (5,294) (4,204) (27,291)
Sale of Russian joint venture - 75 5,608
Sale of Chelsea Corporation 2,066 - -
Investment in and loans to Summo Minerals Corporation (287) (788) (2,332)
Collections on loan to Summo Minerals Corporation 2,163 - -
Receipts from restricted cash 720 7,275 9,747
Deposits to restricted cash - (7,995) (6,829)
Cash received in the purchase of Nance Petroleum Corporation 635 - -
Cash received in the purchase of King Ranch Energy, Inc. 12,068 - -
Other (376) (350) 61
----------------------------------
Net cash used in investing activities (22,243) (36,982) (67,477)
----------------------------------
Cash flows from financing activities:
Proceeds from long-term debt 29,750 54,579 22,837
Repayment of long-term debt (39,537) (57,787) (43,819)
Proceeds from sale of common stock, net of offering costs 311 173 51,207
Repurchase of common stock (525) (2,470) -
Dividends paid (2,193) (2,190) (2,084)
Other 56 - (1)
----------------------------------
Net cash (used in) provided by financing activities (12,138) (7,695) 28,140
----------------------------------
Net increase in cash and cash equivalents 6,374 709 3,774
Cash and cash equivalents at beginning of period 7,821 7,112 3,338
----------------------------------
Cash and cash equivalents at end of period $ 14,195 $ 7,821 $ 7,112
==================================
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-5
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Supplemental schedule of additional cash flow information and noncash
activities:
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1999 1998 1997
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Cash paid for interest $ 916 $ 1,650 $ 1,248
Cash paid for income taxes 92 307 1,864
Cash paid for exploration expenses 11,826 11,873 6,462
</TABLE>
In February 1997 the Company sold its interest in the Russian joint venture for
$17,609,000, receiving $5,608,000 of cash, $1,869,000 of Khanty Mansiysk Oil
Corporation common stock, and a $10,134,000 receivable in a form equivalent to a
retained production payment.
In February 1997 the Company issued 3,600 shares of common stock to its
directors and recorded compensation expense of $68,175.
In June 1997 an officer of the Company exercised 14,072 options to buy common
stock at $20.50 per share. As payment of the exercise price and taxes due, the
Company accepted 11,022 of the exercised shares, resulting in an increase in
shares outstanding of 3,050.
In January 1998 the Company issued 3,600 shares of common stock to its directors
and recorded compensation expense of $94,500.
In January 1999 the Company issued 3,600 shares of common stock to its directors
and recorded compensation expense of $54,612.
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.
In December 1999 the Company acquired King Ranch Energy, Inc. for 2,666,187
shares of the Company's common stock valued at $52,832,000. The acquisition was
accounted for as a purchase.
Following is a table of the non cash items acquired in the 1999 purchases of
Nance Petroleum Corporation and King Ranch Energy, Inc.:
<TABLE>
<CAPTION>
Nance King Ranch
Petroleum Energy
--------- ------
(in thousands)
<S> <C> <C>
Accounts receivable & other assets $ 789 $ 9,772
Property & equipment 6,365 25,056
Accounts payable (642) (4,490)
Deferred income taxes (667) 10,426
Long term debt (3,389) -
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-6
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999
1. Summary of Significant Accounting Policies:
Description of Operations:
St. Mary Land & Exploration Company ("St. Mary" or the "Company") is an
independent energy company engaged in the exploration, development, acquisition
and production of natural gas and crude oil. In February 1997 the Company
completed the sale of its interest in the Russian joint venture. In December
1998 the Company sold its remaining interests in properties located in Canada.
The Company's operations are conducted entirely in the United States.
Basis of Presentation:
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. Subsidiaries that are not
wholly-owned are accounted for using full consolidation with minority interest
or by the equity or cost method as appropriate. All significant intercompany
accounts and transactions have been eliminated.
The Company accounts for its investment in Summo Minerals Corporation
("Summo") under the cost method of accounting. The accounting for this
investment was changed from the equity method to the cost method in June 1999
due to a transfer of common shares that reduced the Company's ownership
percentage from 37% to 18%. The Company accounted for its investment in The
Limited Liability Company Chernogorskoye (the "Russian joint venture") under the
equity method until February 1997, when the Russian joint venture investment was
sold. The Company's interests in other oil and gas ventures and partnerships
were proportionately consolidated until September 1999. The Company's interests
are now accounted for using full consolidation with minority interest, including
its 58% investment in Box Church Gas Gathering, LLC and its 90% investment in
Roswell, LLC. The Company's 74% investment in Panterra Petroleum ("Panterra")
was proportionately consolidated until June 1999 when the remaining 26% was
acquired through the purchase of Nance Petroleum Corporation ("Nance").
Cash and Cash Equivalents:
The Company considers all highly liquid investments purchased with an
initial maturity of three months or less to be cash equivalents. The carrying
value of cash and cash equivalents approximates fair value because the
instruments have maturity dates of three months or less.
Concentration of Credit Risk:
Substantially all of the Company's receivables are within the oil and
gas industry, primarily from purchasers of oil and gas and from joint interest
owners. Although diversified within many companies, collectability is dependent
upon the general economic conditions of the industry. The receivables are not
collateralized and to date, the Company has had minimal bad debts.
The Company has accounts with separate banks in Denver, Colorado;
Houston, Texas; and Shreveport, Louisiana. At December 31, 1999 and 1998, the
Company had $12,120,000 and $4,697,000, respectively, invested in money market
funds consisting of corporate commercial paper, repurchase agreements and U.S.
Treasury obligations. The Company's policy is to invest in conservative, highly
rated instruments and to limit the amount of credit exposure to any one
institution.
F-7
<PAGE>
Oil and Gas Producing Activities:
The Company follows the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending determination of whether the well has found proved
reserves. If an exploratory well has not found proved reserves, the costs of
drilling the well are charged to expense. Exploratory dry hole costs are
included in cash flows from investing activities within the consolidated
statements of cash flows. The costs of development wells are capitalized whether
productive or nonproductive.
Geological and geophysical costs on exploratory prospects and the costs
of carrying and retaining unproved properties are expensed as incurred. An
impairment allowance is provided on a property-by-property basis when the
Company determines that the unproved property will not be developed. Depletion,
depreciation and amortization ("DD&A") of capitalized costs of proved oil and
gas properties is provided on a field-by-field basis using the units of
production method based upon proved reserves. The computation of DD&A takes into
consideration restoration, dismantlement and abandonment costs and the
anticipated proceeds from equipment salvage. The estimated restoration,
dismantlement and abandonment costs for onshore properties are expected to be
offset by the estimated residual value of lease and well equipment. The Company
had a recorded offshore abandonment liability of $8,627,000 as of December 31,
1999 based on total expected abandonment costs of $10,446,000. This liability is
included in accumulated DD&A on the consolidated balance sheets. The Company
recorded $34,000 of offshore abandonment liability accretion as part of DD&A
expense in the consolidated statements of operations for the year ended December
31, 1999.
The Company reviews its long-lived assets for impairments when events
or changes in circumstances indicate that an impairment 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. Expected future cash flows are calculated on all proved reserves with a
15% discount rate using escalated prices and including the estimated effects of
the Company's hedging contracts in place at year end. When the net capitalized
costs exceed the undiscounted future net revenue of a property, the cost of the
property is written down to fair value, which is determined using discounted
future net revenues. During 1999, 1998 and 1997 the Company recorded impairment
charges for proved properties of $3,982,000, $17,483,000 and $5,202,000,
respectively.
Sales of Producing and Nonproducing Properties:
The sale of a partial interest in a proved property is accounted for as
normal retirement, and no gain or loss is recognized as long as this treatment
does not significantly affect the unit-of-production amortization rate. A gain
or loss is recognized for all other sales of producing properties.
The sale of a partial interest in an unproved property is accounted for
as a recovery of cost when substantial uncertainty exists as to recovery of the
cost applicable to the interest retained. A gain on the sale is recognized to
the extent that the sales price exceeds the carrying amount of the unproved
property.
Other Property and Equipment:
Other property and equipment is recorded at cost. Costs of renewals and
improvements that substantially extend the useful lives of the assets are
capitalized. Maintenance and repairs are expensed when incurred. Depreciation is
provided using the straight-line method over the estimated useful lives of the
assets from 3 to 15 years. Gains and losses on dispositions of other property
and equipment are included in the results of operations.
Restricted Cash:
Proceeds from certain sales of oil and gas producing properties are
held in escrow and restricted for future acquisitions under a tax-free exchange
agreement. These funds are invested in money market funds consisting of
corporate commercial paper, repurchase agreements and U.S. Treasury obligations
and are carried at cost, which approximates market.
F-8
<PAGE>
Gas Balancing:
The Company uses the sales method to account for gas imbalances. Under
this method, revenue is recorded on the basis of gas actually sold by the
Company. The Company records revenue for its share of gas sold by other owners
that cannot be volumetrically balanced in the future due to insufficient
remaining reserves. Related receivables totaling $2,209,000 at December 31, 1999
and $1,928,000 at December 31, 1998 are included in other assets in the
accompanying balance sheets. The Company also reduces revenue for gas sold by
the Company that cannot be volumetrically balanced in the future due to
insufficient remaining reserves. Related payables totaling $733,000 at December
31, 1999 and $872,000 at December 31, 1998 are included in other liabilities in
the accompanying balance sheets. The Company's remaining underproduced gas
balancing position is included in the Company's proved oil and gas reserves (see
Note 12).
Financial Instruments:
The Company periodically uses commodity contracts to hedge or otherwise
reduce the impact of oil and gas price fluctuations. Gains and losses on
commodity hedge contracts are recognized as an adjustment to revenues when the
related oil or gas is sold. Cash flows from such transactions are included in
oil and gas operations.
In connection with these hedging transactions, the Company may be
exposed to nonperformance by other parties to such agreements, thereby
subjecting the Company to current oil and gas prices. However, the Company only
enters into hedging contracts with large financial institutions and does not
anticipate nonperformance by these institutions.
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. In June 1999 the FASB
issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB No. 133" which extended the
effective date of SFAS No. 133 to all fiscal quarters of all fiscal years
beginning after June 15, 2000. 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.
Income Taxes:
Deferred income taxes are provided on the difference between the tax
basis of an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively.
Earnings Per Share:
Basic net income per common share of stock is calculated by dividing
net income by the weighted average of common shares outstanding during each
year. 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. As of December 31, 1999, there
were 65,678 outstanding securities that would be considered dilutive. The
outstanding dilutive securities for the years ended December 31, 1998 and 1997
were 66,748 and 132,666, respectively. However, as the Company was in a net loss
position for the year ended December 31, 1998, all of the outstanding options at
that date were considered anti-dilutive and were therefore excluded from the
diluted earnings per share calculation. All net income of the Company is
available to common stockholders.
F-9
<PAGE>
Stock-Based Compensation:
The Company accounts for stock-based compensation using the intrinsic
value method prescribed in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB No. 25"). Compensation expense
for stock options, if any, is measured as the excess of the quoted market price
of the Company's stock at the date of grant over the amount an employee must pay
to acquire the stock.
SFAS No. 123, "Accounting for Stock-Based Compensation," established
accounting and disclosure requirements using a fair-value-based method of
accounting for stock-based employee compensation plans. The Company has elected
to remain on its current method of accounting as described above, and has
adopted the disclosure requirements of SFAS No. 123.
Comprehensive Income:
In 1998 the Company adopted SFAS No. 130, "Reporting Comprehensive
Income." This statement establishes rules for the reporting of comprehensive
income and its components. Comprehensive income consists of net income and
unrealized gains and losses on marketable equity securities held for sale and is
presented in the consolidated statements of stockholders' equity. The initial
adoption of SFAS No. 130 had no impact on total stockholders' equity. Prior year
financial statements have been reclassified to conform to the requirements of
SFAS No. 130.
Major Customers:
During 1999 one customer individually accounted for 13.3% of the
Company's total oil and gas production revenue. During 1998 no individual
customer accounted for 10% or more of the Company's total oil and gas production
revenue. During 1997 two customers individually accounted for 10.6% and 10.2% of
the Company's total oil and gas production revenue.
Industry Segment and Geographic Information:
The Company operates predominantly in one industry segment, which is
the exploration, development and production of natural gas and crude oil, and
all of the Company's operations are conducted in the United States.
Consequently, the Company currently reports as a single industry segment.
Use of Estimates in the Preparation of Financial Statements:
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Reclassifications:
Certain amounts in the 1998 and 1997 consolidated financial statements
have been reclassified to correspond to the 1999 presentation.
F-10
<PAGE>
2. Accounts Receivable:
Accounts receivable are composed of the following:
<TABLE>
<CAPTION>
December 31,
--------------------------
1999 1998
------------- ------------
(In thousands)
<S> <C> <C>
Accrued oil and gas sales $17,672 $ 7,170
Due from joint interest owners 3,736 7,868
Other 1,563 2,899
------------- ------------
Total accounts receivable $22,971 $17,937
============= ============
</TABLE>
3. Acquisitions
On June 1, 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 $3,091,000 together with transaction costs of $56,000 and the
assumption of $3,189,000 of Nance debt. The acquisition included the 26% of
Panterra 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.
On December 17, 1999, the Company completed the purchase of KRE for
2,666,187 shares of common stock valued at $52,832,000 together with transaction
costs of $2,339,000. After the acquisition, KRE's name was changed to St. Mary
Energy Company ("SMEC"). The acquired properties are located primarily in the
Gulf of Mexico and the onshore Gulf Coast. The KRE acquisition has been
accounted for by the purchase method of accounting and, accordingly, the results
of operations of KRE for the period from December 17 to December 31, 1999 are
included in the accompanying consolidated financial statements. The purchase
price has been preliminarily allocated based on estimated fair values at the
date of acquisition, pending final determination of certain acquired balances.
The following unaudited pro forma information presents a summary of the
consolidated results of operations as if the acquisition had occurred at the
beginning of the periods presented.
<TABLE>
<CAPTION>
Year Year
Ended Ended
December 31, December 31,
------------ ------------
1999 1998
---- ----
(unaudited, in thousands
except per share amounts)
<S> <C> <C>
Total operating revenues $ 118,654 $ 118,151
Net income (loss) from continuing operations $ 1,676 $ (7,523)
Basic net income (loss) per share from
continuing operations $ 0.17 $ (0.55)
Diluted net income (loss) per share from
continuing operations $ 0.17 $ (0.55)
</TABLE>
These unaudited pro forma results have been prepared for comparative
purposes only and include certain adjustments such as reduced depreciation to
reflect lower fair market values assigned to oil and gas properties and
elimination of interest expense for a note payable to the parent corporation.
They do not purport to be indicative of results of operations that actually
would have resulted had the combination occurred at the beginning of the periods
presented, or future results of operations of the consolidated entities.
F-11
<PAGE>
4. Income Taxes:
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
For the Years Ended
December 31,
------------
1999 1998 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Current taxes:
Federal $ 183 $ 213 $ 485
State 315 141 972
Deferred taxes (940) (5,752) 10,677
Benefit of deduction for stock option exercises 36 - 443
-------------------------------------
Total income tax expense (benefit) $ (406) $ (5,398) $ 12,577
=====================================
Continuing operations $ (406) $ (5,415) $ 12,325
Discontinued operations - 17 252
-------------------------------------
Total income tax expense (benefit) $ (406) $ (5,398) $ 12,577
=====================================
</TABLE>
The above taxes from continuing operations are net of alternative fuels
credits (Internal Revenue Code Section 29) of $283,000 in 1999, $315,000 in 1998
and $525,000 in 1997.
The components of the net deferred tax liability are as follows:
<TABLE>
<CAPTION>
December 31,
------------
1999 1998
---- ----
(In thousands)
<S> <C> <C>
Deferred tax liabilities:
Oil and gas properties $ 3,314 $ 13,194
Other 581 833
----------------------
Total deferred tax liabilities 3,895 14,027
----------------------
Deferred tax assets:
Other, primarily employee benefits 611 696
State tax net operating loss carryforward 1,717 1,255
State and federal income tax benefit 876 930
Alternative minimum tax credit carryforward 1,278 1,123
----------------------
Total deferred tax assets 4,482 4,004
Valuation allowance (998) (1,010)
----------------------
Net deferred tax assets 3,484 2,994
----------------------
Total net deferred tax liabilities 411 11,033
Current deferred income tax assets 90 125
----------------------
Non-current net deferred tax liabilities $ 501 $ 11,158
======================
</TABLE>
In accordance with SFAS 109 the Company records purchase adjustments to
its long-term deferred income tax liability accounts. These adjustments more
closely align book and tax basis at the time of acquisition and mitigate the
effect of deferred income tax expense or reduced deferred income tax benefit on
future net income before income tax from acquisitions that utilize the purchase
method and that are considered to be tax-free basis transfers for tax accounting
purposes. During 1999 the Company adjusted its long-term deferred income tax
liability account for a $667,000 increase relating to its Nance stock
acquisition and recorded a $10,426,000 decrease for its KRE stock acquisition,
as Nance's book basis was greater than its tax basis, and KRE's tax basis was
greater than its book basis.
F-12
<PAGE>
At December 31, 1999, the Company had state net operating loss
carryforwards of approximately $33,200,000 which expire between 2000 and 2013
and Federal alternative minimum tax credit carryforwards of $1,278,000 which may
be carried forward indefinitely. The Company's valuation allowance relates in
part to its state net operating loss carryforwards, since the Company
anticipates that a portion of the carryovers from prior years will expire before
they can be utilized, and in part to a portion of the anticipated state benefit
from federal income tax expense incurred as the Company's existing taxable
temporary differences reverse. The net change in valuation allowance in 1999
results from the state benefit of federal income tax which is now offset by
reversing state temporary differences.
Federal income tax expense and benefit differs from the amount that
would be provided by applying the statutory U.S. Federal income tax rate to
income before income taxes for the following items:
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1999 1998 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Federal statutory taxes $ (137) $ (4,843) $ 11,881
Increase (reduction) in taxes resulting from:
State taxes (net of Federal benefit) 105 191 758
Statutory depletion (110) (119) (174)
Alternative fuels credits (Section 29) (283) (315) (525)
Change in valuation allowance (17) (289) 401
Other 36 (40) (16)
--------------------------------------
Income tax expense (benefit) from
continuing operations $ (406) $ (5,415) $ 12,325
======================================
</TABLE>
5. Long-term Debt and Notes Payable:
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 set at $80.0 million by the lender. At December 31, 1999, the
accepted borrowing base was $40.0 million. 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 December 31, 1999 and
1998, $13.0 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%. At December 31, 1999, the
Company's debt to capitalization ratio as defined under the credit agreement was
6.4%.
Panterra, in which the Company owned 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. In June 1999 the
Company used its primary credit facility to retire the balance due on the
Panterra credit facility.
The carrying value of long-term debt approximates fair value because
the debt is variable rate and reprices in the short term.
F-13
<PAGE>
The Company's estimated annual principal payments under the credit
agreement for the next five years are as follows:
<TABLE>
<CAPTION>
Years Ending
December 31, (In thousands)
----------------------- -------------------
<S> <C>
2000 $ -
2001 2,600
2002 2,600
2003 2,600
2004 2,600
Thereafter 2,600
-------------
Total $13,000
=============
</TABLE>
6. Commitments and Contingencies:
The Company leases office space under various operating leases with
terms extending as far as November 30, 2004. The Company has noncancelable
annual subleases with affiliates of approximately $79,000 for the same term as
the Company's primary office lease. Rent expense, net of sublease income, was
$611,000, $484,000 and $447,000 in 1999, 1998 and 1997, respectively. The
Company also leases office equipment under various operating leases. The annual
minimum lease payments for the next five years are presented below:
<TABLE>
<CAPTION>
Years Ending
December 31, (In thousands)
----------------------- -------------------
<S> <C>
2000 $ 888
2001 891
2002 630
2003 299
2004 101
</TABLE>
As of December 31, 1999, the Company, as Operator, had a turnkey
contract in place with a drilling contractor for the Company's 1999 test well at
South Horseshoe Bayou. St. Mary's obligation to pay $5.6 million to the
contractor was contingent upon the well reaching a depth of 16,000 feet. In
February 2000 the well reached the specified depth, and St. Mary paid the amount
due under the contract. The Company's net share of the amount paid under the
contract was $2.3 million
The Company realized a net loss of $2,561,000 on commodity contracts
for the year ended December 31, 1999, a net gain of $1,873,000 for the year
ended December 31, 1998, and a net loss of $3,242,000 for the year ended
December 31, 1997.
F-14
<PAGE>
The Company had the following commodity contracts in place as of
December 31, 1999, to hedge or otherwise reduce the impact of oil and gas price
fluctuations:
<TABLE>
<CAPTION>
Swaps
- -----
Average
-------
Product Volumes/month Fixed Price Duration
- ------- ------------- ----------- --------
<S> <C> <C> <C>
Natural Gas 30,000 MMBtu $2.4633 1/00 - 6/01
Natural Gas 250,000 MMBtu $2.4150 1/00 - 12/00
Natural Gas 250,000 MMBtu $2.5000 1/00 - 12/00
Natural Gas 15,000 MMBtu $2.1800 1/00 - 12/00
Natural Gas 37,000 MMBtu $2.2100 1/00 - 12/00
Natural Gas 13,000 MMBtu $2.3000 1/00 - 12/00
Natural Gas 18,000 MMBtu $2.2600 1/00 - 12/00
Oil 4,000 Bbls $15.2078 1/00 - 5/01
Oil 7,000 Bbls $16.3000 1/00 - 12/00
Oil 7,500 Bbls $14.7500 1/00 - 12/00
Oil 7,000 Bbls $21.0500 1/00 - 12/00
Oil 15,000 Bbls $27.0118 1/00 - 12/00
Oil 10,000 Bbls $23.1432 3/00 - 7/00
</TABLE>
<TABLE>
<CAPTION>
Collars
- -------
Average
-------
Product Volumes/month Ceiling Price Floor Price Duration
- ------- ------------- ------------- ----------- --------
<S> <C> <C> <C> <C>
Natural Gas 200,000 MMBtu $2.6500 $2.0000 1/00 - 12/00
Natural Gas 150,000 MMBtu $2.5000 $2.0000 1/00 - 12/00
Natural Gas 199,000 MMBtu $2.9400 $2.3000 1/00 - 12/00
Natural Gas 197,000 MMBtu $2.9000 $2.3000 1/00 - 12/00
Natural Gas 150,000 MMBtu $2.9400 $2.3000 1/01 - 12/01
Natural Gas 150,000 MMBtu $2.9000 $2.3000 1/01 - 12/01
Natural Gas 250,000 MMBtu $2.8775 $2.3540 1/01 - 12/01
Natural Gas 250,000 MMBtu $2.8192 $2.3540 1/01 - 12/01
Oil 7,000 Bbls $17.7500 $17.5000 1/00 - 12/00
Oil 7,000 Bbls $21.0000 $18.0000 1/00 - 12/00
Oil 10,000 Bbls $20.6400 $16.4400 1/00 - 12/00
Oil 10,000 Bbls $20.9000 $16.7000 1/00 - 12/00
Oil 10,000 Bbls $25.1000 $19.5000 1/00 - 12/00
Oil 12,500 Bbls $27.0000 $17.0000 1/00 - 12/00
Oil 7,500 Bbls $20.6400 $16.4400 1/01 - 12/01
Oil 7,500 Bbls $20.9000 $16.7000 1/01 - 12/01
</TABLE>
The fair value of the Company's commodity hedging contracts based on
year-end futures pricing would have caused the Company to pay approximately
$2,299,000 if these contracts had been terminated on December 31, 1999.
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 or greater than 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 attempts to limit 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. Including hedges entered
into since December 31, 1999, and those detailed above, the Company has hedged
as follows:
F-15
<PAGE>
<TABLE>
<CAPTION>
Swaps:
- ------
Average
-------
Year Product Percentage Fixed Price Pricing
---- ------- ---------- ----------- -------
<S> <C> <C> <C> <C>
2000 Natural Gas 17% $2.4269 MMBtu
2001 Natural Gas <1% $2.4633 MMBtu
2000 Oil 22% $20.9634 Bbl
2001 Oil 1% $15.7600 Bbl
</TABLE>
<TABLE>
<CAPTION>
Collars:
- --------
Highest Lowest
------- ------
Year Product Percentage Ceiling Price Floor Price Pricing
---- ------- ---------- ------------- ----------- -------
<S> <C> <C> <C> <C> <C>
2000 Natural Gas 21% $2.9400 $2.0000 MMBtu
2001 Natural Gas 22% $2.9400 $2.3000 MMBtu
2000 Oil 27% $27.0000 $16.4400 Bbl
2001 Oil 7% $20.9000 $16.4400 Bbl
</TABLE>
7. Compensation Plans:
In January 1992 the Company adopted two compensation plans for key
employees. A cash bonus plan allows participants to receive up to 50% of their
aggregate base salary. Any awards under the cash bonus plans are based on a
combination of company and individual performance. The Company accrued $71,000
for cash bonuses in 1998 that were paid in 1999, and the Company accrued
$2,293,000 for cash bonuses in 1999 to be paid in 2000. A net profits interest
bonus plan allows participants to receive an aggregate 10% net profits interest
after the Company has recovered 100% of its investment in various pools of oil
and gas wells completed or acquired during a given year. This interest increases
to 20% after the Company recovers 200% of its investment. The Company records
compensation expense once it recovers its investment and net profits
attributable to the properties are payable to the employees. The Company
recorded compensation expense of $574,000 in 1999 and $229,000 in 1998 relating
to net profits attributable to these properties.
Through September 1992 the Company had a restricted stock bonus plan
("Plan") covering officers and key employees. Participants have the option at
any time to sell shares acquired under the Plan to the Company at their fair
market values. At December 31, 1999, there were 24,785 shares issued and
outstanding under the Plan.
In March 1992 the Company adopted a stock appreciation rights ("SAR")
plan for officers and directors. SARs vest over a four-year period, with payment
occurring five years after the date of grant. The SAR plan replaced the
restricted stock bonus plan. Between 1993 and 1996 the Company awarded a total
of 171,412 share rights with values ranging from $11.50 to $14.00 per share.
Compensation expense recognized under the SAR plan was $280,000 in 1999 and
$161,000 in 1997. Compensation expense was reduced by $197,000 in 1998 under the
SAR plan. In November 1996 the Company terminated future awards under the
Company's SAR plan and capped the value of the share rights under the SAR plan
at the then fair market value of the Company's common stock of $20.50 per share.
The resulting liability is classified as current and long-term in the
consolidated balance sheets, based on expected payment dates. SAR compensation
expense recorded after the termination of future awards relates to the vesting
of SARs outstanding at the time of the termination of future awards and to the
fluctuation of the stock price below the capped price of $20.50.
F-16
<PAGE>
The Company has a defined contribution pension plan ("401(k) Plan")
which is subject to the Employee Retirement Income Security Act of 1974. The
401(k) Plan allows eligible employees to contribute up to 9% of their base
salaries. The Company matches each employee's contributions up to 6% of the
employee's base salary and also may make additional contributions at its
discretion. The Company's contributions to the 401(k) Plan amounted to $288,000,
$269,000, and $231,000 for the years ended December 31, 1999, 1998, and 1997,
respectively.
In September 1997 the Board of Directors approved the St. Mary Land &
Exploration Company Employee Stock Purchase Plan ("Stock Purchase Plan"), which
became effective January 1, 1998. Under the Stock Purchase Plan eligible
employees may purchase shares of the Company's common stock through payroll
deductions of up to 15% of eligible compensation. The purchase price of the
stock is 85% of the lower of the fair market value of the stock on the first or
last day of the purchase period. The Stock Purchase Plan is intended to qualify
under Section 423 of the Internal Revenue Code. The Company has set aside
500,000 shares of its common stock to be available for issuance under the Stock
Purchase Plan. In 1999 and 1998 shares issued under the Stock Purchase Plan
totaled 16,397 and 8,424, respectively. Total proceeds to the Company for the
issuance of these shares was $258,000 and $173,000 in 1999 and 1998,
respectively. The Company recorded compensation expense of $20,000 in 1999 due
to nonqualified dispositions of stock acquired by employees under the Stock
Purchase Plan. No compensation expense was recorded in 1998 related to the Stock
Purchase Plan.
In 1990 and 1991 the Company granted certain officers options to
acquire 54,614 shares of common stock at an exercise price of $3.30 per share.
The options are now fully vested and expire ten years from the respective dates
of grant. In 1997 34,614 of these options were exercised and in 1999 5,000 of
these options were exercised. There were 15,000 of these options outstanding at
December 31, 1999.
In 1996 the Company established the St. Mary Land & Exploration Company
Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock
Option Plan (collectively, the "Option Plans"). The Option Plans grant options
to purchase shares of the Company's common stock to eligible employees,
contractors, and current and former members of the Board of Directors. In 1999
the stockholders approved an increase in the number of shares of the Company's
common stock reserved for issuance under the Option Plans from 700,000 shares to
1,650,000 shares. In 1997 participants exercised 14,072 options under the Option
Plans at $20.50 per share, and an additional 74,057 and 109,781 options were
granted at $29.375 and $35.00 per share, respectively. In 1998 the Company
granted 251,774 options at an exercise price of $18.50 per share, and no options
were exercised under the Option Plans. In 1999 the Company granted 311,746
options at an exercise price of $24.75 per share, and 3,830 options were
exercised under the Option Plans. All options granted to date under the Option
Plans have been granted at exercise prices equal to the respective market prices
of the Company's common stock on the grant dates.
F-17
<PAGE>
A summary of the status of the Company's Stock Option Plans, including
the 1990 and 1991 options and changes during the last three years follows:
<TABLE>
<CAPTION>
For the Years Ended December 31,
------------------------------------------------------------------------------
1999 1998 1997
-------------------------- ------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------- ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 721,218 $ 22.55 479,343 $ 24.80 354,092 $ 18.38
Granted 311,746 24.75 251,774 18.50 183,838 32.79
Exercised 8,830 9.89 - - 48,686 8.27
Forfeited 25,007 26.42 9,899 28.63 9,901 15.62
------------- ------------ ------------
Outstanding at end of year 999,127 23.25 721,218 22.55 479,343 24.80
============= ============ ============
Options exercisable at year end 325,938 20.65 164,670 18.41 129,173 17.84
============= ============ ============
Weighted average fair value of
options granted during the year $ 10.25 $ 8.16 $ 15.05
============= ============ ============
</TABLE>
A summary of additional information related to the options outstanding as
of December 31, 1999 follows:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
------------------------------------------------- ------------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Number Contractual Exercise Number Exercise
Exercise Prices Outstanding Life Price Exercisable Price
- ------------------------------ ----------------- ---------------- -------------- --------------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
$ 3.30 - $ 3.30 15,000 1.0 year $ 3.30 15,000 $ 3.30
18.50 - 20.50 470,272 6.5 years 19.49 233,001 20.50
24.75 - 29.38 418,818 9.2 years 25.51 77,937 24.75
35.00 - 35.00 95,037 8.0 years 35.00 - -
----------------- ---------------
Total 999,127 7.7 years 23.25 325,938 20.72
================= ===============
</TABLE>
SFAS No. 123 establishes a fair value method of accounting for
stock-based compensation plans either through recognition or disclosure. The
Company accounts for stock-based compensation under 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 employee
stock options equals the market price of the underlying stock on the date of
grant, no compensation expense is recognized under APB No. 25. Pro forma
information regarding net income and earnings per share is required by SFAS No.
123 and has been determined as if the Company had accounted for its employee
stock options under the fair value method of that Statement.
F-18
<PAGE>
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair value of the options granted in
1999 was estimated using the following weighted-average assumptions: risk-free
interest rate of 6.42%; dividend yield of 0.82%; volatility factor of the
expected market price of the Company's common stock of 41.52%; and expected life
of the options of 4.8 years. The fair value of options granted in 1998 was
estimated using the following weighted-average assumptions: risk-free interest
rate of 4.6%; dividend yield of 1.08%; volatility factor of the expected market
price of the Company's common stock of 40.16%; and expected life of the options
of 7.5 years. The fair value of options granted in 1997 was estimated using the
following weighted-average assumptions: risk-free interest rate of 5.7%;
dividend yield of 0.49%; volatility factor of the expected market price of the
Company's common stock of 37.29%; and expected life of the options of 7.1 years.
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. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, it
is management's opinion that the existing models do not necessarily provide a
reliable single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. Had
compensation cost been determined based on the fair value at grant dates for
stock option awards consistent with SFAS No. 123, the Company's net income and
earnings per share would have been reduced to the pro forma amounts indicated
below:
<TABLE>
<CAPTION>
Pro Forma for the Years
Ended December 31,
------------------------------------------
1999 1998 1997
------------------------------------------
(In thousands, except
per share amounts)
<S> <C> <C> <C>
Net income (loss) applicable As reported $ 82 $ (8,797) $ 23,109
to common stock Pro forma $ (1,530) $ (9,682) $ 22,443
Basic earnings (loss) per share As reported $ .01 $ (.81) $ 2.18
Pro forma $ (0.14) $ (.89) $ 2.11
Diluted earnings (loss) per share As reported $ .01 $ (.81) $ 2.15
Pro forma $ (0.14) $ (.89) $ 2.09
</TABLE>
The effects of applying SFAS No. 123 in the pro forma disclosure are
not necessarily indicative of actual future amounts, and SFAS No. 123 does not
apply to awards granted prior to 1995. Additional awards in future years are
anticipated.
F-19
<PAGE>
8. Pension and Other Postretirement Benefits
The Company's employees participate in a non-contributory pension plan
covering substantially all employees who meet age and service requirements (the
qualified plan). The Company also has a supplemental non-contributory pension
plan covering certain management employees (the nonqualified plan) and a
postretirement non-contributory health care plan. The Company's disclosures
about pension and other postretirement benefits are as follows:
<TABLE>
<CAPTION>
Pension Plans Other Benefits
December 31, December 31,
------------ ------------
1999 1998 1999 1998
---- ---- ---- ----
(In thousands) (In thousands)
<S> <C> <C> <C> <C>
Change in benefit obligations:
Benefit obligation at beginning of year $ 2,470 $ 1,926 $ 185 $ 141
Service Cost 178 201 25 24
Interest Cost 172 151 11 11
Actuarial gain (loss) (84) 472 (63) 9
Benefits paid (148) (280) - -
------------------------------------------------
Benefit obligation at end of year $ 2,588 $ 2,470 $ 158 $ 185
================================================
Change in plan assets:
Fair value of plan assets at beginning of year $ 1,212 $ 932 $ - $ -
Actual return on plan assets 165 179 - -
Employer contribution 363 381 - -
Benefits paid (148) (280) - -
------------------------------------------------
Fair value of plan assets at end of year $ 1,592 $ 1,212 $ - $ -
================================================
Funded Status $ (996) $(1,258) $ (158) $ (185)
Unrecognized net actuarial loss 615 867 (1) 64
Unrecognized prior service cost (36) (43) - -
------------------------------------------------
Prepaid (accrued) benefit cost $ (417) $ (434) $ (159) $ (121)
================================================
</TABLE>
The Company's nonqualified pension plan was the only pension plan with
an accumulated benefit obligation in excess of plan assets. The plan's
accumulated benefit obligation was $300,000 at December 31, 1999, and $274,000
at December 31, 1998. There are no plan assets in the nonqualified plan due to
the nature of the plan. The Company's other plan for postretirement benefits
also has no plan assets. The aggregate benefit obligation for that plan is
$159,000 as of December 31, 1999, and $121,000 as of December 31, 1998.
Assumptions used in the measurement of the Company's benefit obligation
are as follows:
<TABLE>
<CAPTION>
Pension Plans Other Benefits
December 31, December 31,
------------ ------------
1999 1998 1999 1998
---- ---- ---- ----
(In thousands) (In thousands)
<S> <C> <C> <C> <C>
Weighted-average assumptions:
Discount rate 8.00% 6.50% 6.50% 7.00%
Expected return on plan assets 8.00% 8.00% N/A N/A
Rate of compensation increase 5.00% 5.00% N/A N/A
</TABLE>
F-20
<PAGE>
For measurement purposes, an 8% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2000. The rate was
assumed to decrease gradually to 6 percent for 2003 and remain at that level
thereafter.
<TABLE>
<CAPTION>
Pension Plans Other Benefits
December 31, December 31,
------------ ------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
(In thousands) (In thousands)
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic benefit cost:
Service cost $ 178 $ 201 $ 192 $ 25 $ 24 $ 19
Interest cost 172 151 100 11 11 9
Expected return on plan assets (88) (179) (84) - - -
Amortization of prior service cost 83 174 21 - - -
Recognized net actuarial loss - - - 2 2 2
-------------------------------------------------------------
Net periodic benefit cost $ 345 $ 347 $ 229 $ 38 $ 37 $ 30
=============================================================
</TABLE>
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% 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.
The Company has one nonpension postretirement benefit plan; a
noncontributory health care plan.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plan. A 1% change in assumed health care
cost trend rates would have the following effects (in thousands):
<TABLE>
<CAPTION>
1% Increase 1% Decrease
----------- -----------
<S> <C> <C>
Effect on total of service and interest cost components
of net periodic postretirement health care benefit cost $ 9 $ 7
Effect on the health care component of the accumulated
postretirement benefit obligation $ 29 $ 23
</TABLE>
9. Sale of Oklahoma Properties:
On December 15, 1998, the Company closed the sale of a package of
non-strategic properties to ONEOK Resources Company for a purchase price of
$22,201,000. The Company received $22,117,000 in cash proceeds, net of
transaction costs and customary closing adjustments made to reflect
post-effective date revenues and expenses. The transaction was consummated
pursuant to a Purchase and Sale Agreement dated November 12, 1998, effective as
of September 1, 1998. The assets sold consist of producing oil and gas wells and
undeveloped leasehold acreage within eight fields located in Beckham and Roger
Mills counties, Oklahoma.
The majority of the proceeds from this property sale were used to
reduce the Company's outstanding bank debt in anticipation of re-deploying this
capital in the Company's drilling, exploration and acquisition programs in 1999.
F-21
<PAGE>
10. Investment in Russian Joint Venture:
In September 1991 the Company acquired a 22% interest in The Limited
Liability Company Chernogorskoye through Anderman Smith
International-Chernogorskoye Partnership (the "Partnership"), collectively the
"Russian joint venture." The Russian joint venture is developing the
Chernogorskoye field in western Siberia. The Company's interest in the Russian
joint venture was reduced to 18% in 1993. On December 16, 1996, the Company
executed an Acquisition Agreement to sell its interest in the Russian joint
venture to Khanty Mansiysk Oil Corporation ("KMOC"), formerly Ural Petroleum
Corporation. In accordance with the terms of the Acquisition Agreement, the
Company received cash consideration of $5,608,000 before transaction costs, KMOC
common stock valued at $1,869,000, and a receivable in a form equivalent to a
retained production payment of approximately $11,217,000 plus interest at 10%
per annum from the limited liability company formed to hold the Russian joint
venture interest. The Company has accrued an obligation of $1,083,000 for
commissions to be paid when proceeds are received on the receivable leaving net
proceeds of $10,134,000. The Company's receivable is collateralized by the
Partnership interest sold. The transaction closed on February 12, 1997, and the
Company recorded a gain on the sale of $9,671,000. The Company's equity in
income for the Russian joint venture for 1997 through the date of sale was
$203,000. In 1998 uncertain economic conditions in Russia and lower oil prices
affected the realizability of the convertible receivable. As a result, the
Company reduced the carrying amount of the receivable to its minimum conversion
value, incurring a charge to operations of $4,553,000 for the year ended
December 31, 1998. In August 1999 the Company sold Chelsea Corporation
("Chelsea"), the subsidiary that held the Company's original common stock
investment in 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. As of December 31, 1999 the Company still held
the receivable from KMOC which was recorded at its minimum conversion value of
$5,110,000. On February 10, 2000, the Company elected to convert all of its
receivable into additional shares of KMOC stock.
11. Summo Minerals Corporation Investment and Receivable:
As of December 31, 1999 and 1998, the Company owned 4,962,046 shares
(18% of total shares outstanding) and 9,924,093 common shares (37% of total
shares outstanding) of Summo, a North American mining company, with a total cost
of $3,799,000 and $5,859,000, respectively. The recorded net book value of the
stock was $255,000 and zero at December 31, 1999 and 1998, respectively.
Included in the net book value was unrealized gain on marketable equity
securities of $284,000 for December 31, 1999 and zero at December 31, 1998. The
Company also owned warrants to acquire an additional 17,500,000 and 616,090
shares of Summo common stock as of December 31, 1999 and 1998, respectively. The
market value of the Company's investment in Summo common stock was $412,000 and
$705, 000 at December 31, 1999 and 1998, respectively. As of December 31, 1999
and 1998, the Company held a note receivable from Summo of $1,400,000 and
$2,869,000, respectively. The loan is secured by Summo's interest in Summo's
Lisbon Valley Copper Project and bears interest at LIBOR plus 2.5%.
In June 1999 the Company participated in a financing package
arrangement with 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
the Company's note receivable from Summo and transferring 4,962,047 Summo common
shares to RCF. 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. Management believes the note receivable is
realizable. As a result of the new financing arrangement, the Company is not
obligated to fund any future loans to Summo. The Company continuously analyzes
its net investment in Summo and the effect of copper prices and worldwide copper
inventory levels on Summo's stock price.
F-22
<PAGE>
The transfer of Summo common shares to RCF reduced the Company's
ownership percentage in Summo from 37% to 18%. Consequently, the accounting for
this investment was changed from the equity method to the cost method in June
1999. For the years ended December 31, 1998 and 1997, the Company reported
equity in losses from Summo of $661,000 and $526,000, respectively. 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 records
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
December 31, 1999 was $284,000. This represents the difference in trading value
of the Company's ownership in Summo common stock and the recorded basis of the
common stock owned by the Company, net of taxes.
In January 2000, Summo issued 1,016,594 shares of its common stock to
the Company as payment of interest on the company's note receivable from Summo.
Due to the receipt of these shares, the Company's ownership percentage increased
to 19%.
12. Disclosures About Oil and Gas Producing Activities:
Costs Incurred in Oil and Gas Producing Activities:
Costs incurred in oil and gas property acquisition, exploration and
development activities, whether capitalized or expensed, are summarized as
follows:
<TABLE>
<CAPTION>
For the Years Ended
December 31,
------------
1999 1998 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Development costs $ 22,166 $ 32,191 $ 39,030
Exploration costs:
Domestic 20,809 17,767 15,311
International - - 16
Acquisitions:
Proved 33,080 4,204 27,291
Unproved 15,129 3,693 7,565
--------------------------------------
Total $ 91,184 $ 57,855 $ 89,213
======================================
</TABLE>
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 1999, 1998, and 1997 was
prepared by Ryder Scott Company and St. Mary. The Company emphasizes that
reserve estimates are inherently imprecise and that estimates of new discoveries
are more imprecise than those of proved producing oil and gas properties.
Accordingly, these estimates are expected to change as future information
becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods.
F-23
<PAGE>
Presented below is a summary of the changes in estimated domestic
reserves of the Company:
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1999 1998 1997
---- ---- ----
Oil or Oil or Oil or
Condensate Gas Condensate Gas Condensate Gas
---------- --- ---------- --- ---------- ---
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
<S> <C> <C> <C> <C> <C> <C>
Total proved U.S. reserves:
Developed and undeveloped:
Beginning of year 8,614 132,605 11,493 196,230 10,691 127,057
Revisions of previous estimates 3,308 (10,445) (2,437) (42,430) (502) (7,486)
Discoveries and extensions 2,062 43,501 336 38,744 1,203 77,876
Purchases of minerals in place 6,323 65,129 679 1,225 1,328 24,809
Sales of reserves (24) (343) (182) (35,724) (39) (3,126)
Production (1,383) (22,805) (1,275) (25,440) (1,188) (22,900)
--------------------------------------------------------------
End of year (a) 18,900 207,642 8,614 132,605 11,493 196,230
==============================================================
Proved developed U.S. reserves:
Beginning of year 7,723 112,189 10,268 168,229 10,015 100,027
==============================================================
End of year 16,688 169,379 7,723 112,189 10,268 168,229
==============================================================
</TABLE>
[FN]
- ---------
(a) At December 31, 1999, 1998 and 1997, includes approximately 1,802,
2,022, and 1,982 MMcf, respectively representing the Company's
underproduced gas balancing position.
</FN>
Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities,"
prescribes guidelines for computing a standardized measure of future net cash
flows and changes therein relating to estimated proved reserves. The Company has
followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying benchmark prices and costs, including transportation and
basis differential, in effect at year-end to the year-end estimated quantities
of oil and gas to be produced in the future. Estimated future income taxes are
computed using current statutory income tax rates, including consideration for
estimated future statutory depletion and alternative fuels tax credits. The
resulting future net cash flows are reduced to present value amounts by applying
a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the FASB and, as such, do not necessarily reflect the Company's
expectations of actual revenues to be derived from those reserves, nor their
present worth. The limitations inherent in the reserve quantity estimation
process, as discussed previously, are equally applicable to the standardized
measure computations since these estimates are the basis for the valuation
process.
F-24
<PAGE>
The following summary sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in SFAS No. 69:
<TABLE>
<CAPTION>
For the Years Ended
December 31,
------------
1999 1998 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Future cash inflows $ 900,199 $ 328,630 $ 629,001
Future production and
development costs (344,350) (128,120) (202,503)
Future income taxes (150,239) (39,471) (120,742)
--------------------------------------
Future net cash flows 405,610 161,039 305,756
10% annual discount (144,296) (59,093) (118,409)
--------------------------------------
Standardized measure of
discounted future net cash flows $ 261,314 $ 101,946 $ 187,347
======================================
</TABLE>
The principle sources of change in the standardized measure of
discounted future net cash flows are as follows:
<TABLE>
<CAPTION>
For the Years Ended
December 31,
------------
1999 1998 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Standardized measure,
beginning of year $ 101,946 $ 187,347 $ 203,230
Sales of oil and gas produced,
net of production costs (53,814) (53,643) (60,506)
Net changes in prices and
production costs 82,976 (78,974) (132,465)
Extensions, discoveries and other,
net of production costs 76,198 36,495 112,698
Purchase of minerals in place 105,728 5,548 40,647
Development costs incurred
during the year 5,816 12,964 11,305
Changes in estimated future
development costs (25,281) 1,641 (2,998)
Revisions of previous quantity estimates 10,976 (39,303) (8,885)
Accretion of discount 11,474 26,152 29,646
Sales of reserves in place (542) (26,435) (5,493)
Net change in income taxes (76,907) 50,994 19,089
Other 22,744 (20,840) (18,921)
--------------------------------------
Standardized measure, end of year $ 261,314 $ 101,946 $ 187,347
======================================
</TABLE>
F-25
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
-----------------------------------
(Registrant)
Date: March 10, 2000 By: /s/ THOMAS E. CONGDON
-------------------------
Thomas E. Congdon, Chairman of the Board
GENERAL POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Thomas E. Congdon and Mark A.
Hellerstein, and each of them, his true and lawful attorney-in-fact and agents
with full power of substitution and resubstitution, for him and in his name,
place and stead, in any and all capacities, to sign any amendments to this
report on Form 10-K, and to file the same, with exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission,
hereby ratifying and confirming all that each of said attorneys-in-fact, or his
substitute or substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
/s/ THOMAS E. CONGDON
- ---------------------
Thomas E. Congdon Chairman of the Board of Directors March 10, 2000
/s/ MARK A. HELLERSTEIN
- ----------------------- President, Chief Executive Officer, March 10, 2000
Mark A. Hellerstein and Director
/s/ RONALD D. BOONE
- ------------------- Executive Vice President, Chief March 10, 2000
Ronald D. Boone Operating Officer and Director
/s/ RICHARD C. NORRIS
- --------------------- Vice President-Finance, March 10, 2000
Richard C. Norris Secretary and Treasurer
/s/ GARRY A. WILKENING
- ---------------------- Vice President-Administration March 10, 2000
Garry A. Wilkening and Controller
/s/ LARRY W. BICKLE
- -------------------
Larry W. Bickle Director March 10, 2000
/s/ DAVID C. DUDLEY
- -------------------
David C. Dudley Director March 10, 2000
/s/ ROBERT L. NANCE
- -------------------
Robert L. Nance Director March 10, 2000
/s/ R. JAMES NICHOLSON
- ----------------------
R. James Nicholson Director March 10, 2000
<PAGE>
Signature Title Date
- --------- ----- ----
/s/ AREND J. SANDBULTE
- ----------------------
Arend J. Sandbulte Director March 10, 2000
/s/ JOHN M. SEIDL
- -----------------
John M. Seidl Director March 10, 2000
/s/ WILLIAM J. GARDINER
- -----------------------
William J. Gardiner Director March 10, 2000
/s/ JACK HUNT
- -------------
Jack Hunt Director March 10, 2000
EXHIBIT 21.1
SUBSIDIARIES
OF
ST. MARY LAND & EXPLORATION COMPANY
A. Wholly-owned subsidiaries of St. Mary Land & Exploration Company, a
Delaware corporation:
1. St. Mary Minerals, Inc., a Colorado corporation
2. Parish Corporation, a Colorado corporation
3. St. Mary Operating Company, a Colorado corporation
4. Nance Petroleum Corporation, a Montana corporation
5. St. Mary Energy Company, a Delaware corporation
B. Other subsidiaries of St. Mary Land & Exploration Company
1. Box Church Gas Gathering LLC, a Colorado limited liability company
(58.6754%)
2. Roswell LLC, a Texas limited liability company (90%)
C. Wholly-owned subsidiaries of Parish Corporation:
1. Natasha Corporation, a Colorado corporation
2. Lucy Corporation, a Colorado corporation
D. Partnership interests held by Parish Corporation:
1. Hilltop Investment Partners, a Colorado general partnership (50%)
2. C-470 Venture, a Colorado general partnership (68.858%)
3. Parish Ventures, a Colorado general partnership (100%)
E. Subsidiaries of Lucy Corporation:
1. St. Mary East Texas LP, a Texas limited partnership (99%) (the
remaining 1% interest is held by St. Mary Land & Exploration
Company)
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report included in this Form 10-K into St. Mary Land & Exploration Company's
previously filed Form S-8 Registration Statement No. 33-6185, Form S-8
Registration Statement No. 333-30055 and Form S-8 Registration Statement No.
333-58273.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado,
March 9, 2000.
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
The undersigned hereby consents to the references to our firm in the
form and context in which they appear in the Annual Report on Form 10-K of St.
Mary Land and Exploration Company for the year ended December 31, 1999. We
hereby further consent to the use of information contained in our reports, as of
January 1, 1998, 1999 and 2000 setting forth the estimates of revenues from St.
Mary Land & Exploration Company's oil and gas reserves. We further consent to
the incorporation by reference thereof into St. Mary Land & Exploration
Company's Form S-8 (Registration No. 33-61850), Form S-8 (Registration No.
333-30055), and Form S-8 (Registration No. 333-58273).
Very truly yours,
/s/ RYDER SCOTT COMPANY, L.P.
-----------------------------
RYDER SCOTT COMPANY, L.P.
Denver, Colorado,
March 10, 2000.
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