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, 1998.
[ ] 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
of incorporation or organization) Identification No.)
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. [ x ]
The aggregate market value of 10,599,514 shares of voting stock held
by non-affiliates of the Registrant, based upon the closing sale price of the
Common Stock on March 15, 1999 of $18.75 per share as reported on the Nasdaq
National Market System, was $198,740,888. 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 15, 1999, the Registrant had 10,827,067 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 1999 Annual Meeting of Stockholders.
TABLE OF CONTENTS
-----------------
ITEM PAGE
PART I
ITEM 1 BUSINESS.............................................................. 4
Background....................................................... 4
Business Strategy................................................ 4
Significant Developments Since December 31, 1997................. 7
ITEM 2. PROPERTIES........................................................... 8
Domestic Operations.............................................. 8
International Operations......................................... 14
Key Relationships................................................ 14
Acquisitions..................................................... 15
Reserves......................................................... 16
Production....................................................... 17
Productive Wells................................................. 17
Drilling Activity................................................ 18
Domestic Acreage................................................. 19
Non-Oil and Gas Activities....................................... 19
Competition...................................................... 20
Markets and Major Customers...................................... 20
Government Regulations........................................... 20
Title to Properties.............................................. 21
Operational Hazards and Insurance................................ 21
Employees and Office Space....................................... 22
Glossary......................................................... 22
ITEM 3. LEGAL PROCEEDINGS.................................................... 24
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................. 24
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED SECURITY HOLDERS MATTERS..................................... 25
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA................................. 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................. 28
Overview......................................................... 28
Results of Operations............................................ 31
Liquidity and Capital Resources.................................. 35
Accounting Matters............................................... 41
Effects of Inflation and Changing Prices......................... 42
Financial Instrument Market Risk................................. 42
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.......................... 44
ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.................................. 44
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................. 44
ITEM 11. EXECUTIVE COMPENSATION.............................................. 44
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT...................................................... 44
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...................... 44
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K................................................. 45
PART I
ITEM 1. BUSINESS
Background
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. St. Mary's operations are focused
in five core operating areas in the United States: the Mid-Continent region; the
ArkLaTex region; south Louisiana; the Williston Basin; and the Permian Basin. As
of December 31, 1998, the Company had estimated net proved reserves of
approximately 8.6 MMBbls of oil and 132.6 Bcf of natural gas, or an aggregate of
184.3 BCFE (86% proved developed, 72% gas) with a PV-10 value before tax of
$125.1 million.
From January 1, 1994, through December 31, 1998, the Company added
estimated net proved reserves of 270.0 BCFE at an average finding cost of $5.84
per BOE. The Company's average annual production replacement was 220% during
this five-year period.
In 1998 production increased 10% to a total of 33.1 BCFE, or average
daily production of 90.6 MMcf per day. The Company's 1999 capital budget of
approximately $71.0 million includes $37.0 million for ongoing development and
exploration programs in the core operating areas, $25.0 million for niche
acquisitions of oil and gas properties and $9.0 million for higher-risk,
large-target exploration prospects.
The principal offices of the Company 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 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 $250 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.
-4-
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.
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 1992
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 1998, the Company participated in 137 gross wells
with an 87% success rate and 52 recompletions with an 85% 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 south Louisiana and Texas
during 1999, including prospects at its Stallion, South Horseshoe Bayou,
Edgerly, Patterson, North Parcperdue and Carrier projects.
-5-
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.
St. Mary's strong balance sheet positions the Company in 1999 to exploit
acquisition opportunities arising from dislocations occurring throughout the
upstream oil and gas sector. Many over-leveraged companies are expected to
divest assets during the year in order to reduce their debt levels in the
adverse climate of low prices and severely limited access to new capital. 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. 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.
Strategic Relationships. The Company cultivates strategic partnerships
with independent oil and gas operators having focused regional experience and
specialized technical skills. The Company's strategy is to serve as operator or,
alternatively, to maintain a majority interest in such ventures to ensure that
it can exercise significant influence over development and exploration
activities. In addition the Company seeks industry partners who are willing to
co-invest on substantially the same basis as the Company. For example, the
Company's operations in the Williston Basin are conducted through Panterra
Petroleum ("Panterra") in which St. Mary holds a 74% general partnership
interest. The managing partner of Panterra is Nance Petroleum Corporation
("Nance Petroleum"), the principal of which has over 25 years of experience in
the Williston Basin.
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.
-6-
Significant Developments Since December 31, 1997
Oil and Gas Property Sales. In order to continue to focus and
rationalize its operations, the Company sold certain non-strategic interests in
Oklahoma for net proceeds of approximately $22 million and various minor
interests in Canada for net proceeds of $1.2 million. Both of these sales
occurred in December 1998. The Company realized a pre-tax gain on the sale of
these properties of approximately $7.7 million. To accelerate the receipt of
proceeds from the Canadian property sale, the Company obtained a letter of
credit ("LOC") guaranteeing the payment of Canadian federal income tax
liabilities for the Company and its joint venture partners in the Canadian
properties. The Company expects the LOC to expire unused in 1999.
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 and an additional 35,000 shares to date in 1999.
Acquisitions of Oil and Gas Properties. In 1998 the Company completed 6
acquisitions of oil and gas properties for $4.2 million comprised of
supplemental acquisitions of $3.4 million in the Permian and Williston basins
and acquisitions of producing properties in Louisiana and the Anadarko Basin of
$800,000.
Reserve Revisions and Writedowns. The Company's year-end 1998 reserves
reflect property dispositions of 39.6 BCFE which includes 2.8 BCFE of current
year production, 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, of which 23.7 BCFE were
reclassified to the probable category.
Writedown of Russian Joint Venture Receivable. The Company reduced the
carrying amount of the receivable from Khanty Mansiysk Oil Corporation to its
minimum conversion value, incurring a charge to operations of $4.6 million for
the year ended December 31, 1998 (see Item 2, International Operations).
Writedown of Investment in Summo Minerals Corporation. The Company
wrote down its net investment in Summo Minerals Corporation to its net
realizable value in the fourth quarter of 1998 (see Item 2, Non-Oil and Gas
Activities).
-7-
ITEM 2. PROPERTIES
Domestic Operations
The Company's exploration, development and acquisition activities are
focused in five core operating areas: the Mid-Continent region; south Louisiana;
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, 1998, 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........ 577 75,186 78,648 42.7% $ 62,659 50.1%
ArkLaTex Region............. 578 40,061 43,529 23.6% 27,676 22.1%
South Louisiana............. 745 7,662 12,132 6.6% 12,628 10.1%
Williston Basin............. 3,821 3,094 26,020 14.1% 10,739 8.6%
Permian Basin............... 2,791 5,112 21,858 11.9% 10,162 8.1%
Other (1)................... 102 1,490 2,102 1.1% 1,262 1.0%
------- --------- --------- ------- ----------- -------
Total ...................... 8,614 132,605 184,289 100.0% $ 125,126 100.0%
======= ========= ========= ======= =========== =======
</TABLE>
- -----------
(1) Includes reserves associated with properties in Colorado, Kansas,
Mississippi, New Mexico, Texas, Utah and Wyoming.
Mid-Continent Region. The Company has been active in the Mid-Continent
region since 1973 where the Company's operations are managed by its 25-person,
Tulsa, Oklahoma office. The Company has ongoing exploration and development
programs in the Anadarko Basin of Oklahoma and the Sherman-Marietta Basin of
southern Oklahoma and northern Texas. The Mid-Continent region accounted for 43%
of the Company's estimated net proved reserves as of December 31, 1998 or 78.6
BCFE (77% proved developed and 96% gas). The Company participated in 67 gross
wells and recompletions in this region in 1998, including 21 Company-operated
wells.
The Company's development and exploration budget in the Mid-Continent
region for 1999 totals $22 million. The Company plans to operate 29 drilling
wells in the Mid-Continent region during 1999 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 and rationalization 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. This trend is expected to accelerate during 1999 and to offer St.
Mary new opportunities as a result of the acute cost and capital pressures in
the exploration and production sector.
-8-
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 and Red Fork formations. In addition, the Company will devote
approximately 23% 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 the Hunton and Arbuckle formations at depths
between 16,000 and 18,000 at the SW Mayfield Field.
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 during the second half of 1999.
South Louisiana Region. St. Mary's presence in south Louisiana dates to
the turn of the century 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 $6.9 million of gross oil and gas royalty revenue in 1998. The
south Louisiana region accounted for 6.6% of the Company's estimated net proved
reserves as of December 31, 1998, or 12.1 BCFE (86% proved developed and 63%
gas).
The Company's diverse activities in south Louisiana are managed by its
regional 3-person office in Lafayette, Louisiana, and include ongoing
development and exploration programs in St. Mary, Cameron, Lafourche, Jefferson
Davis, Vermilion and Calcasieu parishes. Advanced 3-D seismic imaging and
interpretation techniques are revitalizing exploration and development
activities in the Miocene trend of south Louisiana. St. Mary is applying the
latest technologies to unravel the region's complex geology and to extend
exploratory drilling into deeper untested formations.
St. Mary's 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 south Louisiana region.
The 1998 disappointments at South Horseshoe Bayou and at Atchafalaya
Bay discussed below underscore the risks inherent in the exploration for deep
gas reserves in south Louisiana. 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.
-9-
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 $223
million. St. Mary currently leases 14,419 acres of its fee lands and has an
additional 10,481 acres that are presently unleased. The Company's principal
lessees are Texaco, Vastar, Cabot, Mobil 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. Management is currently evaluating
whether to sidetrack or abandon the No. 3 well.
At year-end the Company reclassified 23.7 BCFE of reserves to the
probable category and wrote off 15.1 BCFE of reserves due to premature water
encroachment and mechanical problems. Despite these disappointments, South
Horseshoe Bayou has generated solid economic returns for the Company and still
has significant remaining potential. The two wells have produced 6.0 Bcf of gas
and 45 MBbls of oil, net to the Company's interest, through December 31, 1998.
An untested fault block to the north of the existing production will be
drilled in 1999 as part of the Company's continuing management and exploitation
of its fee lands. Permitting of the St. Mary Land & Exploration 24-1 well (25%
working interest and approximately 36% net revenue interest) is scheduled to be
completed by April, and drilling operations are expected to commence in May
1999. (see "Large-Target Exploration Projects").
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.
Stallion Prospect. The Company's Stallion prospect (31.25% working
interest) was spud in January 1999 and is currently drilling below 15,300 feet
toward a targeted total depth of approximately 17,800 feet. This 3-D prospect in
Cameron Parish, Louisiana is scheduled to test a series of MA sands along a
major east-west growth fault that produces from the same interval to the east at
the Little Pecan Lake, Lac Blanc and North Freshwater Bayou fields.
(see "Large-Target Exploration Projects").
-10-
Edgerly Prospect. 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 Company has identified a number of promising anomalies on the
3-D survey and in 1999 expects to test several Hackberry prospects at shallow
depths between 10,000 and 13,000 feet. The Company has an approximate 35%
working interest in the Edgerly prospect. (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. The project was delayed during
1998 due to the financial constraints of certain partners. However, the partner
group is exploring alternatives with other parties and hopes to proceed with the
drilling of the 19,500-foot MA sand test by mid 1999.
(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 prospect is
targeting Marg Tex sands in a fault block with other productive shallow sands. A
re-entry and sidetrack of the Phillips Sweezy No. 1 well is scheduled to begin
in May 1999. (see "Large-Target Exploration Projects").
ArkLaTex Region. The Company's operations in the ArkLaTex area are
managed by its 12-person office in Shreveport, Louisiana. The ArkLaTex region
accounted for 24% of the Company's estimated net proved reserves as of December
31, 1998, or 43.5 BCFE (92% proved developed and 92% gas). The Company's 1999
capital budget for the ArkLaTex region is $6.5 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 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 $10.8 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 445 producing wells, including 68 Company-operated wells, and
interests in leases totaling approximately 54,900 gross acres and mineral
servitudes totaling approximately 15,800 gross acres.
Activities in the ArkLaTex region during 1998 focused on the phased
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 completed an additional eight wells in 1998, bringing the field
total to 26 wells. Four additional locations are planned for 1999. Gross
production from the field has increased from 2.5 MMcf per day, when acquired in
1995, to the current rate of 18 MMcf per day. In 1999 the Company plans to
install additional gathering systems, compression and artificial lift upgrades
that are designed to sustain field production at approximately 20 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.
-11-
Development around the Company's 1995 discovery at the Haynesville
Field also continued in 1998 with St. Mary participating in the drilling of 14
new wells. St. Mary and others have drilled a total of 38 wells since the 1995
discovery. The Company operates 12 wells in the field and owns interests in an
additional 13 wells.
In 1999 the Company is focused 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 especially well positioned
to secure additional acquisitions in the ArkLaTex region during 1999 in the wake
of the dislocations and capital shortages being experienced by many of its
competitors.
Williston Basin Region. The Company's operations in the Williston Basin
are conducted through Panterra Petroleum, a general partnership formed in June
1991. The Company holds a 74% interest in Panterra, and the managing partner,
Nance Petroleum, owns a 26% interest. Nance Petroleum's principal activity is
the management of Panterra's interests in the Williston Basin. Panterra
currently owns interests in 62 fields within the basin's core producing area
including 134,000 gross acres, 78 Panterra-operated wells and 161 wells operated
by other parties.
The Williston Basin region accounted for 14% of the Company's estimated
net proved reserves as of December 31, 1998, or 26.0 BCFE (97% proved developed
and 88% oil). St. Mary has budgeted approximately $2.0 million as its share of
Panterra's 1999 development and exploration program.
Panterra'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, Panterra 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 Panterra achieve a 100%
success rate in its operated exploration and development program since 1991.
During periods of depressed oil prices or inflated costs the
partnership has the financial resources to capitalize on dislocations
experienced by other operators. Panterra uses these periods to replenish its
prospect inventory, to secure attractively priced acquisitions and to conduct
additional 3-D seismic work and technical studies in anticipation of cyclical
recovery in the industry.
Panterra plans to conduct six additional or extended 3-D surveys in
1999 over existing fields in the search for bypassed pay zones. In addition a
detailed reservoir simulation of the Bainville Field is scheduled for completion
and will be used to evaluate secondary recovery opportunities in this existing
field.
Permian Basin Region. The Permian Basin of New Mexico and west Texas is
the Company's newest area of concentration. 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
in the prevailing low oil price environment.
-12-
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, 1998,
or 21.9 BCFE (91% proved developed and 77% oil).
The Company's reservoir engineers have identified a number of
properties where the project economics of secondary recovery plans are still
acceptable under current prices. St. Mary's geoscientists have also warehoused a
number of high quality prospects for which future drilling is contingent upon a
stabilization of oil prices above $15 per barrel.
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. The Company's operations in
the Permian Basin during 1999 will focus on the expansion of the waterflood
project at Parkway and additional secondary recovery work at the Shugart and
Zuni fields.
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. In August 2000,
all production 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.
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 wherever appropriate, including 3-D seismic imaging, 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.
-13-
The following table summarizes the Company's active large-target
exploration projects. (see also "Properties").
<TABLE>
<CAPTION>
St. Mary St. Mary Expected
Working Royalty Test
Project Name Objective Location Interest(1) Interest(2) Date(3)
- ------------ --------- -------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Stallion MA Sands Cameron Parish, LA 31.2% - early 1999
South Horseshoe Rob, Operc St. Mary Parish, LA 25.0% 25.0% mid 1999
Edgerly Hackberry Calcasieu Parish, LA 35.0% - mid 1999
North Parcperdue Marg Tex Vermilion Parish, LA 25.0% - mid 1999
Patterson MA-3 , MA-7 St. Mary Parish, LA 25.0% - late 1999
Carrier Cotton Valley Reef Leon County, TX 22.0% - late 1999
</TABLE>
- ------------
(1) Working interests differ from net revenue interests due to royalty
interest burdens.
(2) Royalty interests are approximate and are subject to adjustment. St.
Mary has no capital at risk with respect to its royalty interests.
(3) Expected Test Date refers to the period during which the Company
anticipates the completion of an exploratory well.
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's
receivable is collateralized by the partnership interest sold and the Company
has the right, subject to certain conditions, to require KMOC to purchase the
receivable from the net proceeds of an initial public offering of KMOC common
stock. Alternatively, the Company may elect to convert all or a portion of its
receivable into KMOC common stock immediately prior to an initial public
offering of KMOC common stock or on or after February 11, 2000, whichever occurs
first. Uncertain economic conditions in Russia and lower oil prices have
affected the realizability of the convertible receivable. As a result, the
Company has reduced the carrying amount of the receivable to its minimum
conversion value, incurring a charge to operations of $4.6 million for the year
ended December 31, 1998.
Trinidad and Tobago. In 1997 the Company relinquished its 7.47%
reversionary interest in a 281,506-acre onshore exploration and production
license in the Caroni Basin of Trinidad and Tobago.
-14-
Key Relationships
The Company cultivates strategic partnerships with independent oil and
gas operators having region-specific experience and specialized technical
skills. The Company's strategy is to either serve as operator or maintain a
majority interest in such ventures to ensure that it can exercise significant
influence over development and exploration activities. In addition the Company
seeks industry partners who are willing to co-invest on substantially the same
basis as the Company. For example, the Company's operations in the Williston
Basin are conducted through Panterra in which St. Mary holds a 74% general
partnership interest. The managing partner of Panterra is Nance Petroleum, the
principal of which has over 25 years of experience in the Williston Basin.
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.
Although the Company periodically evaluates large acquisition packages
offered in competitive bid or auction formats, the Company has continued to
emphasize 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
affords a competitive advantage.
Faced with an overheated acquisition market where demand exceeded the
supply of economically sound opportunities, St. Mary chose to conserve its
capital resources in 1998 and completed only $4.2 million of property
acquisitions. During the last five years the Company has closed over $85 million
of niche acquisitions where proprietary geologic knowledge or operating
expertise have afforded the Company a competitive advantage.
The economic success of the Company's historical acquisitions has
resulted from a focus on smaller, negotiated transactions where St. Mary has
clearly identified opportunities that maximize their value. St. Mary's teams of
geoscientists and engineers evaluate each acquisition to quantify potential
opportunities arising from proprietary geologic concepts or advanced production
technologies. In addition, the acquired production is hedged for periods up to
two years to protect the Company's return on its investment.
In 1999 St. Mary has reserved $25 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.
Weak commodity prices and depressed oil and gas stock prices have
precipitated an important change in the acquisition market in early 1999. St.
Mary expects that quality acquisitions will always command premium prices given
the inherent costs and risks associated with developing new reserves. However,
the market in 1999 is expected to offer favorable opportunities for the
relatively few financially strong companies able to capitalize on this depressed
market.
-15-
Reserves
At December 31, 1998, Ryder Scott Company, independent petroleum
engineers, evaluated properties representing approximately 80% 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, 1998, as prepared by Ryder Scott
Company and St. Mary:
<TABLE>
<CAPTION>
As of December 31,
------------------------------
1998 (2) 1997 1996
-------- ---- ----
<S> <C> <C> <C>
Proved Reserves Data: (1)
Oil (MBbls).............................. 8,614 11,493 10,691
Gas (MMcf)............................... 132,605 196,230 127,057
MMCFE.................................... 184,289 265,188 191,202
PV-10 value (in thousands)............... $ 125,126 $ 262,006 $ 296,461
Proved developed reserves................ 86% 87% 84%
Production replacement................... (25%) 358% 422%
Reserve life (years)..................... 6.5 7.3 7.2
</TABLE>
- ------------
(1) Reserve data attributable to the Company's Russian joint venture have
been excluded from this table. Effective February 12, 1997, the
Company sold its Russian joint venture. See "International
Operations."
(2) 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,
of which 23.7 BCFE were reclassified to the probable category.
The present value of estimated future net revenues before income taxes
of the Company's reserves was $125.1 million as of December 31, 1998. This
present value is based on a benchmark of prices in effect at that date of $12.05
per barrel of oil (NYMEX) and $1.855 per million MMBtu of gas (Gulf Coast spot
price), both of which are adjusted for transportation and basis differential.
These prices were 34 percent and 20 percent lower, respectively, than prices in
effect at the end of 1997. Had the December 31, 1997, pricing assumptions been
applied, the PV-10 value and net reserves would have been $193.2 million and
202.5 BCFE, respectively.
-16-
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,
------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Operating Data:
Net production (1):
Oil (MBbls).......................................... 1,275 1,188 1,186
Gas (MMcf)........................................... 25,440 22,900 15,563
MMCFE................................................ 33,090 30,024 22,680
Average net daily production (1):
Oil (Bbls)........................................... 3,493 3,254 3,240
Gas (Mcf)............................................ 69,698 62,739 42,522
MCFE................................................. 90,656 82,263 61,962
Average sales price (2):
Oil (per Bbl)........................................ $ 12.98 $ 18.87 $ 18.64
Gas (per Mcf)........................................ $ 2.13 $ 2.33 $ 2.23
Additional per BOE data:
Lease operating expense.............................. $ 2.34 $ 2.09 $ 2.28
Production taxes..................................... $ 0.74 $ 0.96 $ 1.13
</TABLE>
-------------
(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. Management expects that the 1999 capital
investment program will partially offset this production loss.
(2) Includes the effects of the Company's hedging activities. (see
"Management's Discussion and Analysis of Financial Condition and
Results of Operations--Overview").
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,
1998. 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 585 162
Gas 822 128
----- ---
Total 1,407 290
===== ===
</TABLE>
-17-
Drilling Activity
The following table sets forth the wells in which the Company
participated during each of the three years indicated:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1998 1997 1996
---------------- ---------------- ---------------
Gross Net Gross Net Gross Net
------ ------- ------ ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Domestic:
Development:
Oil............................ 6 .28 10 3.06 17 3.91
Gas............................ 109 26.04 92 19.64 74 13.29
Non-productive................. 12 3.98 15 4.35 11 2.70
------ ------- ------ ------- ------ -------
Total...................... 127 30.30 117 27.05 102 19.90
------ ------- ------ ------- ------ -------
Exploratory:
Oil............................ 1 .50 4 1.21 - -
Gas............................ 3 .95 7 2.04 5 1.25
Non-productive................. 6 1.05 5 1.93 10 3.10
------ ------- ------ ------- ------ -------
Total...................... 10 2.50 16 5.18 15 4.35
------ ------- ------ ------- ------ -------
Farmout or non-consent 4 - 4 - 9 -
------ ------- ------ ------- ------ -------
International:
Development:
Oil........................... - - - - 22 3.96
Gas........................... - - - - - -
Non-productive................ - - - - - -
------ ------- ------ ------- ------ -------
Total................... - - - - 22 3.96
------ ------- ------ ------- ------ -------
Grand Total(1) ................ 141 32.80 137 32.23 148 28.21
====== ======= ====== ======= ====== =======
</TABLE>
---------------
(1) Does not include 1, 4 and 3 gross wells completed on The Company's fee
lands during 1998, 1997 and 1996, respectively.
All of the Company's drilling activities are conducted on a contract basis
with independent drilling contractors. The Company owns no drilling equipment.
-18-
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, 1998. 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.................................. 4,202 806 166 54 4,368 860
Louisiana................................. 26,854 10,930 14,977 4,754 41,831 15,684
Montana................................... 15,053 8,577 52,437 27,708 67,490 36,285
New Mexico................................ 7,840 1,999 4,159 1,624 11,999 3,623
North Dakota.............................. 28,516 9,329 43,111 23,065 71,627 32,394
Oklahoma.................................. 111,345 23,725 46,835 12,720 158,180 36,445
Texas..................................... 39,651 11,021 58,341 12,122 97,992 23,143
Other (3) ................................ 15,934 5,740 51,720 26,678 67,654 32,418
------- ------ ------- ------- ------- -------
Subtotal............................ 249,395 72,127 271,746 108,725 521,141 180,852
------- ------ ------- ------- ------- -------
Louisiana Fee Properties................... 13,084 13,084 11,830 11,830 24,914 24,914
Louisiana Mineral Servitudes............... 10,045 5,464 5,780 5,259 15,825 10,723
------- ------ ------- ------- ------- -------
Subtotal.............................. 23,129 18,548 17,610 17,089 40,739 35,637
------- ------ ------- ------- ------- -------
GRAND TOTAL .......................... 272,524 90,675 289,356 125,814 561,880 216,489
======= ====== ======= ======= ======= =======
</TABLE>
- ------------
(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
Non-Oil and Gas Activities
Summo Minerals. The Company, through a subsidiary, owns 9.9 million shares
or 37% of Summo Minerals Corporation ("Summo"), a North American copper mining
company focusing on finding late exploration stage, low to medium-sized copper
deposits in the United States amenable to the SX-EW extraction process. Summo's
common shares are listed on the Toronto Stock Exchange under the symbol "SMA."
The persistence of depressed commodity prices and increased worldwide inventory
levels of copper have caused Summo's stock price to decline. Management believes
that this stock price decline is not temporary and that its value is impaired.
Consequently, the Company wrote down its net investment in Summo to net
realizable value in the fourth quarter of 1998. Management believes the recorded
net investment is recoverable.
-19-
In May 1997, the Company entered into an agreement to receive a 55%
interest in Summo's Lisbon Valley Copper Project (the "Project") in return for
the Company contributing $4.0 million in cash, all of its outstanding stock in
Summo, and $8.6 million in letters of credit to a single purpose company, Lisbon
Valley Mining Company LLC ("LVMC"), formed to own and operate the Project. Summo
will contribute the property, all project permits and contracts, $3.2 million in
cash, and a commitment for $45 million senior debt financing in return for a 45%
interest in LVMC. The agreement is subject to certain conditions including the
finalization of the necessary project financing.
The Company has agreed to provide Summo with interim financing of up to
$3.5 million for the Project in the form of a loan bearing interest at the prime
rate plus 1% due in June 1999. As security for this loan, Summo pledged its
interest in LVMC to the Company in November 1998. As of December 31, 1998, $2.9
million was outstanding under the note, and additional amounts totaling $188,000
have been advanced to Summo under this loan to date in 1999. At the Company's
option, the principal amounts advanced by the Company under the note are
convertible into shares of Summo common stock at a defined conversion price.
Upon finalization of the necessary project financing for LVMC, the Company may
elect to deem the outstanding principal amount of the note as a capital
contribution in partial satisfaction of its capital commitments as set forth in
the May 1997 agreement. Accrued interest on the loan will be forgiven if the
Company makes this election.
In September 1998 Summo received final regulatory approval to develop the
Project. Future development and financial success of the Project are largely
dependent on the market price of copper, which is determined in world markets
and is subject to significant fluctuations. Current copper prices have declined
to ten-year lows and do not justify construction and development of the Project
at this time. Management believes that copper prices will recover and that the
Project will have considerable value at that time. The Company has the ability
to fund the carrying costs of the property and the intent to retain its interest
in the Project until copper prices do recover. However, there can be no
assurance that the Company will realize a return on its investment in Summo or
the Project.
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 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.
-20-
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.
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.
-21-
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, 1998, the Company had 110 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 34,500 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 and approximately 1,100 square feet in Lafayette,
Louisiana. 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.
-22-
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.
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.
MBtu. 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.
-23-
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%.
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.
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
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of 1998.
-24-
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. Prior to the commencement of
trading on December 16, 1992, no market for the stock existed. The range of high
and low bid prices for the quarterly periods in 1998 and 1997, as reported by
the Nasdaq National Market System, is set forth below:
<TABLE>
<CAPTION>
Quarter Ended High Low
---- ---
<S> <C> <C>
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
March 31, 1997 $31.000 $24.000
June 30, 1997 35.750 24.000
September 30, 1997 45.375 32.000
December 31, 1997 46.000 32.250
</TABLE>
On March 15, 1999, the closing sale price for the Company's common stock
was $18.75 per share.
Holders. As of March 15, 1999, the number of record holders of the
Company's common stock was 152. 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 have been 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 declared in January 1997
and paid in February 1997. Dividends paid totaled $1,402,000 in each of the
years 1994 through 1996, $2,084,000 in 1997 and $2,190,000 in 1998.
-25-
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
the five years ended December 31, 1998, 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 the Company's
financial statements included elsewhere in this report.
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Operating revenues:
Oil production $ 16,545 $ 22,415 $ 22,100 $ 17,090 $ 14,006
Gas production 54,103 53,349 34,674 19,479 24,233
Gain on sale of Russian joint venture - 9,671 - - -
Gain on sale of proved properties 7,685 4,220 2,254 1,292 418
Gas contract settlements and other 411 1,391 523 789 6,128
--------- --------- --------- --------- ---------
Total operating revenues 78,744 91,046 59,551 38,650 44,785
--------- --------- --------- --------- ---------
Operating expenses:
Oil and gas production 17,005 15,258 12,897 10,646 10,496
Depletion, depreciation & amortization 24,912 18,366 12,732 10,227 10,134
Impairment of proved properties 17,483 5,202 408 2,676 4,219
Exploration 11,705 6,847 8,185 5,073 8,104
Abandonment and impairment of
unproved properties 4,457 2,077 1,469 2,359 1,023
General and administrative 7,097 7,645 7,603 5,328 5,261
Writedown of Russian convertible
receivable 4,553 - - - -
Writedown of investment
in Summo Minerals 3,949 - - - -
Other 141 281 78 152 493
(Income) loss in equity investees 661 325 (1,272) 579 348
--------- --------- --------- --------- ---------
Total operating expenses 91,963 56,001 42,100 37,040 40,078
--------- --------- --------- --------- ---------
Income (loss) from operations (13,219) 35,045 17,451 1,610 4,707
Non-operating expense 1,027 99 1,951 896 525
Income tax expense (benefit) (5,415) 12,325 5,333 (723) 445
--------- --------- --------- --------- ---------
Income (loss) from continuing operations (8,831) 22,621 10,167 1,437 3,737
Gain on sale of discontinued operations,
net of income taxes 34 488 159 306 -
--------- --------- --------- --------- ---------
Net income (loss) $ (8,797) $ 23,109 $ 10,326 $ 1,743 $ 3,737
========= ========= ========= ========= =========
</TABLE>
-26-
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(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 $ (0.81) $ 2.13 $ 1.16 $ 0.17 $ 0.43
Gain on sale of discontinued operations - 0.05 0.02 0.03 -
-------- -------- -------- -------- --------
Basic net income (loss) per share $ (0.81) $ 2.18 $ 1.18 $ 0.20 $ 0.43
======== ======== ======== ======== ========
Diluted net income (loss) per common share:
Income (loss) from continuing operations $ (0.81) $ 2.10 $ 1.15 $ 0.17 $ 0.43
Gain on sale of discontinued operations - 0.05 0.02 0.03 -
-------- -------- -------- -------- --------
Diluted net income (loss) per share $ (0.81) $ 2.15 $ 1.17 $ 0.20 $ 0.43
======== ======== ======== ======== ========
Cash dividends per share $ 0.20 $ 0.20 $ 0.16 $ 0.16 $ 0.16
Basic weighted average common shares
outstanding 10,937 10,620 8,759 8,760 8,763
Diluted weighted average common shares
outstanding 10,937 10,753 8,826 8,801 8,803
Other Data:
EBITDA (1) $ 8,363 $ 53,411 $ 30,183 $ 11,837 $ 14,841
Net cash provided by operating activities 45,388 43,111 24,205 17,713 20,271
Capital and exploration expenditures 57,855 89,213 52,601 32,307 31,811
Balance Sheet Data (end of period):
Working capital $ 9,785 $ 9,618 $ 13,926 $ 3,102 $ 9,444
Net property and equipment 143,825 157,481 101,510 71,645 59,655
Total assets 184,497 212,135 144,271 96,126 89,392
Long-term debt 19,398 22,607 43,589 19,602 11,130
Total stockholders' equity 134,742 147,932 75,160 66,282 66,034
</TABLE>
- ------------
(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.
-27-
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; south Louisiana; the
Williston Basin; and the Permian Basin.
The Company's objective is to build value per share by focusing its
resources within selected basins in the United States where management believes
established acreage positions, long-standing industry relationships and
specialized geotechnical and engineering expertise provide a significant
competitive advantage. The Company's ongoing development and exploration
programs are complemented by less predictable opportunities to acquire producing
properties having significant exploitation potential, to monetize assets at a
premium and to repurchase shares of its common stock at attractive values.
Internal exploration, drilling and production personnel conduct the
Company's activities in the Mid-Continent and ArkLaTex regions and in south
Louisiana. Activities in the Williston Basin are conducted through Panterra
Petroleum ("Panterra"), a general partnership in which the Company owns a 74%
interest. The Company proportionally consolidates its interest in Panterra.
Activities in the Permian Basin are primarily contracted through an oil and gas
property management company with extensive experience in the basin.
The Company's presence in south Louisiana includes active management of its
fee lands from which significant royalty income is derived. Royalty revenues
from the fee lands were $6.9, $8.8 and $8.1 million for the years 1998, 1997 and
1996, 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, of which 23.7 BCFE were reclassified to the probable reserve category and
15.1 BCFE were written off. An untested fault block to the north of the existing
production will be drilled at South Horseshoe Bayou in 1999.
-28-
St. Mary seeks to make selective niche acquisitions of oil and gas
properties that complement its existing operations, offer economies of scale and
provide further development and exploration opportunities based on proprietary
geologic concepts. Management believes that the Company's focus on smaller
negotiated transactions where it has specialized geologic knowledge or operating
experience has enabled it to acquire attractively-priced and under-exploited
properties.
The results of operations include several significant acquisitions made
during recent years and their subsequent further development by the Company. In
1996 the Company purchased a 90% interest in the producing properties of Siete
Oil & Gas Corporation for $10.0 million. A series of follow-on acquisitions of
smaller interests in these properties during 1997 and 1998 totaled $5.8 million.
The properties purchased from Siete solidified a new core area of focus in the
Permian Basin of New Mexico and west Texas. St. Mary purchased additional
interests in its Elk City Field located in Oklahoma in 1996 from Sonat
Exploration Company for $5.7 million. In 1997 the Company acquired an 85%
working interest in certain Louisiana properties of Henry Production Company for
$3.9 million. Also in 1997 the Company purchased the interests of Conoco, Inc.
in the Southwest Mayfield area in Oklahoma for $20.6 million. In late 1998 St.
Mary, through Panterra, acquired the interests of Texaco, Inc. in several fields
in the Williston Basin for $2.1 million.
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 1996 and 1997 the Company sold its interests in Wyoming for $2.9 million and
its non-operated interests in south Texas for $5.4 million, respectively. 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.
St. Mary has two principal equity investments, Summo Minerals Corporation
("Summo") and, until early 1997, the Company's Russian joint venture. The
Company accounts for its investments in Summo and The Limited Liability Company
Chernogorskoye ("the Russian joint venture") under the equity method and
includes its share of the income or loss from these entities in its consolidated
results of operations. In February 1997, the Company sold its interest in the
Russian joint venture to Khanty Mansiysk Oil Corporation ("KMOC"), formerly
known as Ural Petroleum Corporation, for $17.6 million.
In February 1997 the Company closed the sale of 2,000,000 shares of common
stock at $25.00 per share and closed the sale of an additional 180,000 shares in
March 1997, pursuant to the underwriters' exercise of the over-allotment option.
These transactions resulted in aggregate net proceeds of $51.2 million.
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.
-29-
In August 1998 the Company's Board of Directors authorized a stock
repurchase program whereby St. Mary may purchase from time-to-time, in open
market transactions or negotiated sales, up to 1,000,000 of its own common
shares. The Company has repurchased stock under this plan in 1998 and 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 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 45% of its estimated 1999 gas
production at an average fixed price of $2.10 per MMBtu, approximately 9% of its
estimated 1999 oil production at an average fixed price of $15.11 per Bbl and
approximately 8% of its estimated 2000 oil production at an average fixed price
of $14.76 per Bbl. The Company has also purchased options resulting in price
collars on approximately 7% of the Company's estimated 1999 gas production with
price ceilings between $2.00 and $2.63 per MMBtu and price floors between $1.50
and $1.90 per MMBtu.
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, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. All statements, other than statements of
historical facts, included in this Form 10-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
production of oil and gas, repayment of debt, business strategies, expansion and
growth of the Company's operations, Year 2000 readiness and other such matters
are forward-looking statements. These statements are based on certain
assumptions and analyses made by the Company in light of its experience and its
perception of historical trends, current conditions, expected future
developments and other factors it believes are appropriate in the circumstances.
Such statements are subject to a number of assumptions, risks and uncertainties,
general economic and business conditions, the business opportunities (or lack
thereof) that may be presented to and pursued by the Company, changes in laws or
regulations and other factors, many of which are beyond the control of the
Company. Readers are cautioned that any such statements are not guarantees of
future performance and that actual results or developments may differ materially
from those projected in the forward-looking statements.
-30-
Results of Operations
<TABLE>
<CAPTION>
The following table sets forth selected operating data for the periods indicated:
Years Ended December 31,
----------------------------
1998 1997 1996
------- ------- -------
(In thousands, except BOE data)
<S> <C> <C> <C>
Oil and gas production revenues:
Working interests............................ $63,771 $66,957 $48,685
Louisiana royalties.......................... 6,877 8,807 8,089
------- ------- -------
Total................................... $70,648 $75,764 $56,774
======= ======= =======
Net production:
Oil (MBbls).................................. 1,275 1,188 1,186
Gas (MMcf)................................... 25,440 22,900 15,563
------- ------- -------
MBOE......................................... 5,515 5,005 3,780
======= ======= =======
Average sales price (1):
Oil (per Bbl)................................ $12.98 $18.87 $18.64
Gas (per Mcf)................................ $ 2.13 $ 2.33 $ 2.23
Oil and gas production costs:
Lease operating expenses..................... $12,929 $10,463 $8,615
Production taxes............................. 4,076 4,795 4,282
------- ------- -------
Total................................... $17,005 $15,258 $12,897
======= ======= =======
Additional per BOE data:
Sales price................................... $12.81 $15.14 $15.02
Lease operating expenses...................... 2.34 2.09 2.28
Production taxes.............................. .74 .96 1.13
------- ------- -------
Operating margin......................... $ 9.73 $12.09 $11.61
Depletion, depreciation and amortization...... $ 4.52 $ 3.67 $ 3.37
Impairment of proved properties............... $ 3.17 $ 1.04 $ .11
General and administrative.................... $ 1.29 $ 1.53 $ 2.01
</TABLE>
- ----------
(1) Includes the effects of the Company's hedging activities.
Oil and Gas Production Revenues. 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
15.1 MBOE in 1998 compared to 13.7 MBOE 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.
-31-
The average realized oil price for 1998 decreased 31% to $12.98 per
Bbl, while average realized gas prices decreased 9% to $2.13 per Mcf, from their
respective 1997 levels. The Company hedged approximately 20.1% of its oil
production for 1998 or 257 MBbls at an average NYMEX price of $19.423. The
Company realized a $435,000 increase in oil revenue or $.34 per Bbl for 1998 on
these contracts compared to a $293,000 decrease or $.25 per Bbl in 1997. The
Company also hedged 45.3% of its 1998 gas production or 11,520 MMBtu at an
average indexed price of $2.343. The Company realized a $1.4 million increase in
gas revenues or $.06 per Mcf for 1998 from these hedge contracts compared to a
$2.9 million decrease in gas revenues or $.13 per Mcf in 1997.
Oil and gas production revenues increased $19.0 million, or 33% to
$75.8 million in 1997 compared to $56.8 million in 1996. Oil production volumes
remained constant between 1997 and 1996 while gas production volumes increased
47% in 1997 compared to 1996. Average net daily production reached 13.7 MBOE in
1997 compared to 10.3 MBOE in 1996. This production increase resulted from new
properties acquired and drilled during 1997. Major acquisitions included the
Southwest Mayfield properties purchased from Conoco, the acquisition of
Louisiana properties from Henry Production Company, and the additional interests
purchased in the Siete properties. Successful drilling results in the Box Church
Field in Texas and the South Horseshoe Bayou prospect in south Louisiana also
contributed to the 1997 production increase. These production increases were
partially offset by the sale of the Company's south Texas non-operated
properties. The average realized oil price for 1997 increased 1% to $18.87 per
Bbl, while realized gas prices increased 4% to $2.33 per Mcf, from their
respective 1996 levels. The Company hedged approximately 16% of its oil
production for 1997 or 185 MBbls at an average NYMEX price of $18.36. The
Company realized a $293,000 decrease in oil revenue or $.25 per Bbl for 1997 on
these contracts compared to a $2.6 million decrease or $2.20 per Bbl in 1996.
The Company also hedged 27% of its 1997 gas production or 6,687 MMBtu at an
average indexed price of $2.06. The Company realized a $2.9 million decrease in
gas revenues or $.13 per Mcf for 1997 from these hedge contracts compared to a
$1.65 million decrease or $.11 per Mcf in 1996.
Oil and Gas Production Costs. Oil and gas production costs consist of
lease operating expense and production taxes. Total production costs increased
$1.7 million, or 11% in 1998 to $17.0 million compared with $15.3 million in
1997, while total oil and gas production costs per BOE increased only 1% to
$3.08 in 1998 compared with $3.05 in 1997. Total production costs increased $2.4
million, or 18% in 1997 to $15.3 million compared with $12.9 million in 1996.
However, total oil and gas production costs per BOE declined 11% to $3.05 in
1997 compared to $3.41 per BOE in 1996.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion and amortization expense ("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. Significant contributors were the Southwest
Mayfield properties acquired from Conoco in the fourth quarter of 1997 and the
reduction of proved reserves at South Horseshoe Bayou. 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 BOE increased 23% to $4.52 in 1998 compared to $3.67
in 1997 due to higher drilling and acquisition costs per BOE 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. These
charges mainly resulted from a decline in the value of the Company's oil and gas
reserves brought about by lower prices at December 31, 1998, the reduction of
proved reserves at South Horseshoe Bayou, a $6.2 million charge associated with
the unsuccessful deep test at the Company's Atchafalaya prospect in south
Louisiana and marginal and unsuccessful development wells drilled in Oklahoma,
Texas and Louisiana.
-32-
Depreciation, depletion and amortization expense increased $5.7
million, or 44% to $18.4 million in 1997 compared with $12.7 million in 1996.
This increase resulted from new properties acquired and drilled in 1997. DD&A
expense per BOE increased 9% to $3.67 in 1997 compared to $3.37 in 1996 due to
higher drilling and acquisition costs per BOE. Impairment of proved oil and gas
properties increased $4.8 million to $5.2 million in 1997 compared with $408,000
in 1996. These charges resulted from a decline in the value of the Company's oil
properties in the Williston Basin due to lower oil prices at year-end 1997 and
the under-performance of a marginal field, as well as the under-performance of
several gas fields in the Mid-Continent region.
Abandonment and impairment of unproved properties increased $2.4
million or 115% to $4.5 million in 1998 compared to $2.1 million in 1997 due to
additional impairments taken during 1998. Abandonment and impairment of unproved
properties increased $608,000 or 41% to $2.1 million in 1997 compared to $1.5
million in 1996 due to additional impairments taken during 1997, partially
offset by fewer abandonments of expired leases.
Exploration. Exploration expense increased $4.9 million or 71% to $11.7
million for 1998 compared with $6.8 million in 1997 primarily due to higher
geological and geophysical costs and the drilling of ten exploratory dry holes
during 1998 in the Mid-Continent and south Louisiana regions, compared to better
exploratory drilling results in 1997. The payment of $795,000 in delay rentals
for the Company's Atachafalaya prospect area during 1998 also contributed to the
increase in exploration expense. Exploration expense decreased $1.3 million or
16% to $6.8 million for 1997 compared with $8.2 million in 1996 primarily as a
result of better exploratory drilling results in 1997 compared to 1996.
General and Administrative. General and administrative expenses
decreased $548,000 or 7% in 1998 compared to 1997 primarily due to the reduction
of expenses related to the Company's Stock Appreciation Rights ("SAR") plan and
a reduction in charitable contributions which is based on pre-tax income.
General and administrative expenses were unchanged at $7.6 million for 1997 from
1996. Increased compensation costs, charitable contributions and insurance
premium costs in 1997 were offset by a $1.4 million decrease in the expense
associated with the SAR plan.
Other operating expenses primarily consist of legal expenses in
connection with ongoing oil and gas activities and oversight of the Company's
mining investments. This expense decreased $140,000 or 50% in 1998 compared with
1997, primarily due to decreased activity in the pending litigation that seeks
to recover damages from the drilling contractor for the St. Mary Land &
Exploration No. 1 well at South Horseshoe Bayou. Other operating expense
increased $203,000 to $281,000 in 1997 compared with 1996, primarily due to
legal expenses associated with the pending litigation for the St. Mary Land &
Exploration No. 1 well.
Equity in Income of Russian Joint Venture. The Company accounted for
its investment in the Russian joint venture under the equity method and included
its share of income or loss from the venture in its results of operations up to
the point of sale. The equity in the net income of the Russian joint venture was
$201,000 in 1997 and $1.7 million in 1996. As discussed under Outlook, the
Company sold this investment in February 1997 resulting in a partial year of
equity income recorded in 1997.
-33-
Equity in Loss of Summo Minerals Corporation. The Company accounts for
its investment in Summo under the equity method and includes its share of
Summo's income or loss in its results of operations. The equity in the net loss
of Summo was $661,000 in 1998, $526,000 in 1997, and $457,000 in 1996. Increased
losses are due to general and administrative expenses associated with the
expansion of Summo's Denver office beginning in 1996 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 and was 49% in 1996.
Non-Operating Income and Expense. Net interest and other non-operating
expense increased $928,000 to $1.0 million in 1998 compared to $99,000 in 1997
due primarily to increased borrowings in 1998 to fund capital expenditures, and
to lower borrowings in 1997 resulting from cash received from the sale of common
stock. Net interest and other non-operating expense decreased $1.9 million to
$99,000 in 1997 due to the reduction of the Company's debt with the proceeds of
the sale of common stock in the first quarter of 1997.
Income Taxes. Income taxes provided a net benefit of $5.4 million for
1998 resulting in an effective tax rate of 38%. The benefit reflects the effect
of the book net operating loss and the compounded effect of Section 29 credits
incurred in years when the Company reports a book loss. Income tax expense was
$12.3 million in 1997 and $5.3 million in 1996, resulting in effective tax rates
of 35% and 34%, respectively. The expense amounts in 1997 and 1996 reflect
higher net income from continuing operations before income taxes for each year
compared to the previous year, offset partially by the utilization of Section 29
tax credits.
State tax expense was $24,000 in 1998, $1.6 million in 1997, and
$700,000 in 1996. The significant decrease in state taxes in 1998 was caused by
the book net operating loss which resulted from Louisiana activity in the South
Horseshoe Bayou and Atchafalaya Bay prospects plus the effects on Colorado and
other states of the Russian and Summo writedowns. Louisiana taxes for 1997
increased significantly as a result of higher Louisiana net income, primarily
from royalty income, and working interest income from South Horseshoe Bayou and
the Henry Production Company acquisition during 1997.
Net Income. 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% percent 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 & 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.
Net income for 1997 increased $12.8 million or 124% to $23.1 million
compared to $10.3 million in 1996. A 47% increase in gas volumes and modest
increases in oil and gas prices resulted in a $19.0 million increase in oil and
gas production revenues. A $9.7 million gain on the sale of the Company's
Russian joint venture, a $4.2 million gain on the sale of the Company's south
Texas properties and a $700,000 lease bonus received for exploration on the
Company's fee lands contributed to total operating revenues of $91.0 million.
These revenues were partially offset by the higher production expenses and DD&A
associated with increased production volumes, a $4.8 million increase in
impairment of proved properties and a $325,000 loss from equity investees.
The Company also realized gains net of income taxes from the sale of
discontinued real estate of $34,000 in 1998, $488,000 in 1997 and $159,000 in
1996, respectively.
-34-
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 the sale of common stock. The Company continually reviews
its capital expenditure budget based on changes in cash flow and other factors.
Cash Flow. The Company's net cash provided by operating activities
increased $2.3 million or 5% to $45.4 million in 1998 compared to $43.1 million
in 1997. A significant decrease in accounts receivable resulting from lower oil
and gas prices and reduced drilling activity was partially offset by increases
in prepaid expenses and cash paid for interest. Net cash provided by operating
activities increased 78% to $43.1 million in 1997 compared to $24.2 million in
1996. The significant increase in receipts for oil and gas revenues were
partially offset by higher production costs and increased exploration expenses.
The Company made cash payments of approximately $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 $30.5 million or 45% in
1998 to $37.0 million compared to $67.5 million in 1997. The decrease is
primarily 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.
Net cash used in investing activities increased $22.3 million or 49% in
1997 to $67.5 million compared to $45.2 million in 1996. This increase was
primarily due to significantly increased capital expenditures for the Company's
drilling programs, increased expenditures for acquisitions of oil and gas
properties and additional investment in and loans to Summo, partially offset by
$7.7 million of proceeds from the sale of oil and gas properties and $ 5.6
million in cash received from the sale of the Company's Russian joint venture.
Total 1997 capital expenditures, including acquisitions of oil and gas
properties, increased $33.0 million or 68% to $81.5 million in 1997 compared to
$48.5 million in 1996.
The Company was able to apply the majority of the proceeds from the
sales of oil and gas properties in 1997 and 1996 to acquisitions of oil and gas
properties in 1997 allowing tax-free exchanges of these properties for income
tax purposes. A portion 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 provided by (used in) financing activities decreased $35.8
million to net cash used of $7.7 million 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 sale of common stock compared to only $173,000 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.
-35-
Net cash provided by financing activities increased $5.5 million to
$28.1 million in 1997 compared to $22.6 million in 1996. The Company received
$51.2 million from the sale of common stock in the first quarter of 1997 and had
a net reduction of borrowings of $21.0 million in 1997. The Company borrowed
funds in 1996 for the expanded capital expenditure programs and reserve
acquisitions. The Company increased its quarterly dividend 25% to $.05 per share
effective with the quarterly dividend declared in January 1997 and paid in
February 1997, resulting in dividends paid in 1997 of $2.1 million compared to
$1.4 million in 1996.
The Company had $7.8 million in cash and cash equivalents and had
working capital of $9.8 million as of December 31, 1998 compared to $7.1 million
in cash and cash equivalents and working capital of $9.6 million as of December
31, 1997. A decrease in accounts receivable was offset by an decrease in
accounts payable and a slight increase in cash and cash equivalents.
Credit Facility. On June 30, 1998, the Company entered into a new
long-term revolving credit agreement that replaced the agreement dated March 1,
1993 and amended in April 1996. The new credit agreement specifies a maximum
loan amount of $200.0 million and had an initial aggregate borrowing base of
$115.0 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 December 1998 the borrowing base was reduced by the lender to $105.0
million as a result of the sale of certain producing properties in Oklahoma to
ONEOK. The accepted borrowing base was $40.0 million at December 31, 1998. 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, 1998 and 1997, $10.5 million and $14.5 million,
respectively, was outstanding under this credit agreement. These outstanding
balances accrue interest at rates determined by the Company's debt to total
capitalization ratio. During the revolving period of the loan, loan balances
accrue interest at the Company's option of either (a) the higher of the Federal
Funds Rate plus 1/2% or the prime rate, or (b) LIBOR plus 1/2% when the
Company's debt to total capitalization is less than 30%, up to a maximum of
either (a) the higher of the Federal Funds Rate plus 5/8% or the prime rate plus
1/8%, or (b) LIBOR plus 1-1/4% when the Company's debt to total capitalization
is equal to or greater than 50%.
Panterra, in which the Company has a 74% general partnership interest,
has a separate credit facility with a $21.0 million borrowing base as of
December 31, 1998, and $12.0 million and $11.0 million outstanding as of
December 31, 1998 and 1997, respectively. In June 1997, Panterra entered into
this credit agreement replacing a previous agreement due March 31, 1999. The new
credit agreement includes a revolving period converting to a five-year
amortizing loan on June 30, 2000. During the revolving period of the loan, loan
balances accrue interest at Panterra's option of either the bank's prime rate or
LIBOR plus 3/4% when the Partnership's debt to partners' capital ratio is less
than 30%, up to a maximum of either the bank's prime rate or LIBOR plus 1-1/4%
when the Partnership's debt to partners' capital ratio is greater than 100%.
Common Stock. In February 1997 the Company closed the sale of 2,000,000
shares of common stock at $25.00 per share and closed the sale of an additional
180,000 shares in March 1997 pursuant to the underwriters' exercise of the
over-allotment option. These transactions resulted in aggregate net proceeds of
$51.2 million. The proceeds of these sales were used to fund the Company's
exploration, development and acquisition programs, and pending such use were
used to repay borrowings under its credit facility.
-36-
In June 1998 the Company's stockholders approved an increase in the
number of authorized shares of the Company's common stock from 15,000,000 to
50,000,000 shares.
In August 1998 the Company's Board of Directors authorized a stock
repurchase program whereby St. Mary may purchase from time-to-time, in open
market transactions or negotiated sales, up to 1,000,000 of its common shares.
During 1998 the Company repurchased a total of 147,800 shares of its common
stock under the program for $2.5 million at a weighted-average price of $16.71
per share. In early 1999 the Company repurchased an additional 35,000 shares for
$15.00 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.
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>
Capital and Exploration Expenditures
--------------------------------------
For the Years Ended
December 31,
--------------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
<S> <C> <C> <C>
Development $32,191 $39,030 $16,709
Exploration:
Domestic 17,767 15,311 11,910
International - 16 84
Acquisitions:
Proved 4,204 27,291 20,957
Unproved 3,693 7,565 2,941
--------- --------- --------
Total $57,855 $89,213 $52,601
========= ========= =========
Russian joint venture (a) $ - $ - $ 3,881
========= ========= =========
</TABLE>
- ------------
(a) In February 1997, the Company sold its interest in the Russian joint
venture.
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.
-37-
The Company's total costs incurred in 1997 increased $36.6 million or
70% to $89.2 million compared to $52.6 million in 1996. Proved property
acquisitions increased $6.3 million to $27.3 million in 1997 compared to $21.0
million in 1996. In May 1997, the Company acquired an 85% working interest in
certain Louisiana properties of Henry Production Company for $3.8 million. In
November 1997, the Company acquired the interests of Conoco, Inc. in the
Southwest Mayfield area in Oklahoma for $20.3 million. Several smaller
acquisitions were also completed during 1997 totaling $560,000 in addition to
follow-on acquisitions relating to interests purchased in 1996. The Company
spent $61.9 million in 1997 for unproved property acquisitions and domestic
exploration and development compared to $31.6 million in 1996 as a result of the
Company's expanded drilling programs.
Outlook. The Company believes that its existing capital resources, cash
flows from operations and available borrowings are sufficient to meet its
anticipated capital and operating requirements for 1999.
The Company generally allocates approximately 85% of its capital budget
to low to moderate-risk exploration, development and niche acquisition programs
in its core operating areas. The remaining portion of the Company's capital
budget is directed to higher-risk, large exploration ideas that have the
potential to increase the Company's reserves by 25% or more in any single year.
The Company anticipates spending approximately $71.0 million for
capital and exploration expenditures in 1999 with $37.0 million allocated for
ongoing exploration and development in its core operating areas, $25.0 million
for niche acquisitions of producing properties and $9.0 million for
large-target, higher-risk exploration and development.
Anticipated ongoing exploration and development expenditures for each
of the Company's core areas include $22.0 million in the Mid-Continent region,
$6.5 million in the ArkLaTex region, $2.0 million in the Williston Basin and
$6.5 million allocated within the Permian Basin and south Louisiana regions.
The Company has several prospects in its pipeline of large-target
exploration ideas and expects to commence the drilling of six significant tests
in 1999 at its Stallion, South Horseshoe Bayou, Edgerly, North Parcperdue and
Patterson projects in south Louisiana, and at its Carrier project in east Texas.
The amount and allocation of future capital and exploration
expenditures will depend upon a number of factors including the number of
available acquisition opportunities, the Company's ability to assimilate such
acquisitions, the impact of oil and gas prices on investment opportunities, the
availability of capital and borrowing capability and the success of its
development and exploratory activity which could lead to funding requirements
for further development.
The Company continuously evaluates opportunities in the marketplace for
oil and gas properties and, accordingly, may be a buyer or a seller of
properties at various times. St. Mary will continue to emphasize smaller niche
acquisitions utilizing the Company's technical expertise, financial flexibility
and structuring experience. In addition, the Company is also actively seeking
larger acquisitions of assets or companies that would afford opportunities to
expand the Company's existing core areas, to acquire additional geoscientists or
to gain a significant acreage and production foothold in a new basin within the
United States.
-38-
The Company, through a subsidiary, owns 9.9 million shares or 37% of
Summo, a North American copper mining company focusing on finding late
exploration stage, low to medium-sized copper deposits in the United States
amenable to the SX-EW extraction process. Summo's common shares are listed on
the Toronto stock exchange under the symbol "SMA". The persistence of depressed
commodity prices and increased worldwide inventory levels of copper have caused
Summo's stock price to decline. Management believes that this stock price
decline is not temporary and that its value is impaired. Consequently, the
Company wrote down its net investment in Summo to net realizable value in the
fourth quarter of 1998. Management believes the recorded net investment is
recoverable.
In May 1997 the Company entered into an agreement to receive a 55%
interest in Summo's Lisbon Valley Copper Project (the "Project") in return for
the Company contributing $4.0 million in cash, all of its outstanding stock in
Summo, and $8.6 million in letters of credit to a single purpose company, Lisbon
Valley Mining Company LLC ("LVMC"), formed to own and operate the Project. Summo
will contribute the property, all project permits and contracts, $3.2 million in
cash, and a commitment for $45 million senior debt financing in return for a 45%
interest in LVMC. The agreement is subject to certain conditions including the
finalization of the necessary project financing.
The Company has agreed to provide Summo with interim financing of up to
$3.5 million for the Project in the form of a loan bearing interest at the prime
rate plus 1% due in June 1999. As security for this loan, Summo pledged its
interest in LVMC to the Company in November 1998. As of December 31, 1998, $2.9
million was outstanding under the loan, and additional amounts totaling $188,000
have been advanced to Summo under this loan to date in 1999. At the Company's
option, the principal amounts advanced by the Company under the note are
convertible into shares of Summo common stock at a defined conversion price.
Upon finalization of the necessary project financing for LVMC, the Company may
elect to deem the outstanding principal amount of the note as a capital
contribution in partial satisfaction of its capital commitments as set forth in
the May 1997 agreement. Accrued interest on the loan will be forgiven if the
Company makes this election.
In September 1998 Summo received final regulatory approval to develop
the Project. Future development and financial success of the Project are largely
dependent on the market price of copper, which is determined in world markets
and is subject to significant fluctuations. Current copper prices have declined
to ten-year lows and do not justify construction and development of the Project
at this time. Management believes that copper prices will recover and that the
Project will have considerable value at that time. The Company has the ability
to fund the carrying costs of the property and the intent to retain its interest
in the Project until copper prices do recover. However, there can be no
assurance that the Company will realize a return on its investment in Summo or
the Project.
In February 1997 the Company sold its interest in the Russian joint
venture to KMOC. The Company received cash consideration of approximately $5.6
million before transaction costs, KMOC common stock valued at approximately $1.9
million, and a 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's
receivable is collateralized by the partnership interest sold. The Company has
the right, subject to certain conditions, to require KMOC to purchase the
Company's receivable from the net proceeds of an initial public offering of KMOC
common stock. Alternatively, the Company may elect to convert all or a portion
of its receivable into KMOC common stock immediately prior to an initial public
offering of KMOC common stock or on or after March 10, 2000, whichever occurs
first. Uncertain economic conditions in Russia and lower oil prices have
affected the carrying value of the convertible receivable. Consequently, the
Company reduced the carrying amount of the receivable to its minimum conversion
value during 1998, incurring a pre-tax charge to operations of $4.6 million.
-39-
Impact of the Year 2000 Issue. The following Year 2000 statements
constitute a Year 2000 Readiness Disclosure within the meaning of the Year 2000
Information and Readiness Disclosure Act of 1998.
The Year 2000 Issue is the result of computer programs and embedded
computer chips being written or manufactured using two digits rather than four,
or other methods, to define the applicable year. Computer programs and embedded
chips that are date-sensitive may recognize a date using "00" as the year 1900
rather than the year 2000. This could result in a system failure or
miscalculations causing disruptions of operations, including, among other
things, a temporary inability to process transactions, operate equipment or
engage in normal business activities. Failure to correct a material Year 2000
compliance problem could result in an interruption in, or inability to conduct
normal business activities or operations. Such failures could materially and
adversely affect the Company's results of operations, cash flow and financial
condition.
The Company's approach to determining and mitigating the impact on the
Company of Year 2000 compliance issues is comprised of five phases:
i) Review and assessment of all internal information technology (IT)
systems and significant non-IT systems for Year 2000 compliance;
ii) Identify and prioritize systems with Year 2000 compliance issues;
iii) Repair or replace and test non-Year 2000 compliant systems;
iv) Survey and assess the Year 2000 readiness of the Company's
significant vendors, suppliers, purchasers and transporters of oil and
natural gas; and,
v) Design and implement contingency plans for those systems, if any, that
cannot be made Year 2000 compliant before December 31, 1999.
The Company completed phases i) and ii) of its plan by August 1998, and
identified the systems requiring repair or replacement in order to be Year 2000
compliant. This review and assessment was completed using outside consultants as
well as Company personnel. The Company determined that of its major systems, the
software it uses for reservoir engineering, its telephone system, a significant
number of the personal computers used by Company personnel and the computer
system used by Panterra should be updated or replaced.
Phase iii) of the Company's plan of repair and replacement of non-Year
2000 compliant systems is approximately 90% complete. The telephone system and
personal computers have been replaced with Year 2000 compliant hardware and
software as part of the Company's ongoing upgrade program. The Company purchased
a Year 2000 compliant release of the reservoir engineering system and
anticipates conversion to and testing of the new system in the second quarter of
1999. In the fourth quarter of 1998 Panterra licensed a Year 2000 compliant
system and converted to the new system in January 1999. The systems that have
been either upgraded or replaced will be further tested to confirm their Year
2000 compliance. This testing is planned for completion in the second quarter of
1999. The Company presently believes that other less significant IT and non-IT
systems can be upgraded to mitigate any Year 2000 issues with modifications to
existing software or conversions to new systems. Modifications or conversions to
new systems for the less significant systems, if not completed timely, would
have neither a material impact on the operations of the Company nor on its
results of operations.
-40-
Under phase iv) of the plan, the Company initiated formal
communications with its significant vendors, suppliers and purchasers and
transporters of oil and natural gas to determine the extent to which the Company
is vulnerable to those third parties' failures to remediate their own Year 2000
issues. The process of collecting information from these third parties is
approximately 40% complete. All of the responses received to date are positive
in assuring that the respondents will be Year 2000 compliant on a timely basis.
Completion of phase iv) of the plan is anticipated in the third quarter of 1999.
Until this phase of the plan is complete, management cannot currently predict if
third party compliance issues will materially affect the Company's operations.
There can be no assurance that the systems of these third parties will be
converted timely, or that a failure to remediate Year 2000 compliance issues by
another company would not have a material adverse effect on the Company.
Phase v) of the Company's Year 2000 plan, the design and implementation
of contingency plans for those systems, if any, that cannot be made Year 2000
compliant before December 31, 1999, will be addressed in the last half of 1999.
Through December 31, 1998, the Company has spent approximately $450,000
on its Year 2000 efforts. This includes the costs of consultants as well as the
cost of repair or replacement of non-compliant hardware and software systems.
Additional costs to complete the Company's plan are estimated at approximately
$50,000. The Company has not specifically tracked its internal costs of
addressing the Year 2000 issue. However, management does not believe these costs
to be material.
The Company has not completed a comprehensive analysis of the
operational problems and costs that would be reasonably likely to result from
the Company or its significant third parties' failure to timely complete efforts
to remediate Year 2000 issues. Potential "worst case" impacts could include the
inability of the Company to deliver its production to, or receive payment from,
third parties purchasing or transporting the Company's production; the inability
of third party vendors to provide needed materials or services to the Company
for ongoing or future exploration, development or producing operations; and the
inability of the Company to execute financial transactions with its banks or
third parties whose systems fail or malfunction.
The Company currently has no reason to believe that any of these
contingencies will occur or that its principal vendors, customers and business
partners will not be Year 2000 compliant. However, there can be no assurance
that the Company will be able to identify and correct all Year 2000 problems or
implement a satisfactory contingency plan. Therefore, there can be no assurance
that the Year 2000 issue will not materially impact the Company's results of
operations or adversely affect its relationships with vendors, customers and
other business partners.
Accounting Matters
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures about
Segments of an Enterprise and Related Information," effective for financial
statements for periods beginning after December 15, 1997. The Statement requires
the Company to report certain information about operating segments in its
financial statements and certain information about its products and services,
the geographic areas in which it operates and its major customers. The Company
operates predominantly in one industry segment, which is the exploration,
development and production of natural gas and crude oil, and the Company's
operations are conducted entirely in the United States
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. The Company is currently reviewing the effects this Statement will
have on the financial statements in relation to the Company's hedging
activities.
-41-
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 global influences on the supply and demand for petroleum products. Oil and
gas prices are further impacted by the quality of the oil and gas to be sold and
the location of the Company's producing properties in relation to markets for
the products. Oil and gas price increases or decreases have a corresponding
effect on the Company's revenues from oil and gas sales. Oil and gas prices also
affect the prices charged for drilling and related services. If oil and gas
prices increase, there could be a corresponding increase in the cost to the
Company for drilling and related services, although offset by an increase in
revenues. Also, as oil and gas prices increase, the cost of acquisitions of
producing properties increases, which could limit the number and accessibility
of quality properties on the market.
Material changes in oil and gas prices affect the current and future
value of the Company's estimated proved reserves and the borrowing capability of
the Company, which is largely based on the value of such proved reserves. Oil
and gas price changes have a corresponding effect on the value of the Company's
estimated proved reserves and the available borrowings under the Company's
credit facility.
During the first half of 1998 the Company experienced an increase in
the cost of drilling and related services resulting from shortages in available
drilling rigs, drilling and technical personnel, supplies and services. However,
service costs stabilized about mid-year 1998 and have begun to decline. The last
half of 1998 was characterized by historically low oil prices and weakening gas
markets. Capital has left the oil and gas industry and has caused a significant
drop in the number of working drilling rigs. Consequently, in early 1999 there
is an abundance of available drilling rigs, personnel, supplies and services
with a corresponding reduction of costs. If oil and gas prices 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.
Financial Instrument Market Risk
Directly, and through its 74% investment in Panterra, 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.
-42-
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
11,250 MMBtu would have caused a potential $1.9 million change in net loss
before income taxes for the Company for contracts in place on December 31, 1998.
Results of operations for Panterra (a non-taxable entity) would have changed by
$48,000 on a notional amount of 39 MBbls. These changes were not discounted to
present value since the latest expected maturity date of all of the swaps and
futures contracts is less 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, 1998, 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, 1998, the Company had floating rate
debt of $19.4 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 $190,000
before taxes.
-43-
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 1999 Annual Meeting of Stockholders.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from
the Company's Proxy Statement for the 1999 Annual Meeting of Stockholders.
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 1999 Annual Meeting of Stockholders.
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 1999 Annual Meeting of Stockholders.
-44-
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 (Arthur Andersen LLP)......... F-1
Report of Independent Accountants (PricewaterhouseCoopers LLP)......... F-2
Consolidated Balance Sheets............................................ F-3
Consolidated Statements of Operations.................................. F-4
Consolidated Statements of Stockholders' Equity........................ F-5
Consolidated Statements of Cash Flows.................................. F-6
Notes to Consolidated Financial Statements............................. F-8
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 30, 1998
regarding the sale of certain Oklahoma properties to ONEOK Resources Company was
filed during the last quarter of 1998.
(c) Exhibits. The following exhibits are filed with or incorporated into
this report on Form 10-K:
Exhibit
Number Description
3.1* Restated Certificate of Incorporation of the Registrant, as
amended
3.1A* Restated Certificate of Incorporation of the Registrant (as of
November 17, 1992)
3.2* Restated Bylaws of the Registrant
10.3* Stock Option Plan
10.4* Stock Appreciation Rights Plan
10.5* Cash Bonus Plan
10.6* Net Profits Interest Bonus Plan
10.7* Summary Plan Description/Pension Plan dated January 1, 1985
10.8* Non-qualified Unfunded Supplemental Retirement Plan, as amended
10.10* Summary Plan Description Custom 401(k) Plan and Trust
10.11* Stock Option Agreement - Mark A. Hellerstein
10.12* Stock Option Agreement - Ronald D. Boone
10.13* Employment Agreement between Registrant and Mark A. Hellerstein
10.14 Summary Plan Description 401(k) Profit Sharing Plan filed as
Exhibit 10.34 on Registrant's Annual Report on Form 10-K (File
No. 0-20872) for the year ended December 31, 1994
10.15 Summary Plan Description/Pension Plan dated December 30, 1994
filed as Exhibit 10.35 on Registrant's Annual Report on Form
10-K (File No. 0-20872) for the year ended December 31, 1994
-45-
10.16 Second Restated Partnership Agreement - Panterra Petroleum
filed as Exhibit 10.41 on Registrant's Annual Report on Form
10-K (File No. 0-20872) for the year ended December 31, 1995
10.17 Purchase and Sale Agreement between Siete Oil & Gas
Corporation and Registrant incorporated by reference from the
Exhibit 10.42 filed on 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
10.18 Acquisition Agreement regarding the sale of the Company's
interest in the Russian joint venture incorporated by
reference from the Exhibit 10.43 filed on Registrant's Current
Report on Form 8-K (File No. 0-20872) dated December 16, 1996
10.19 Employment Agreement between Registrant and Ralph H. Smith,
effective October 1, 1995, incorporated by reference from the
Exhibit 99 filed on Registrant's Current Report on Form 8-K
(File No.
0-20872) dated January 28, 1997
10.20 St. Mary Land & Exploration Company Stock Option Plan dated
November 21, 1996, incorporated by reference from the Exhibit
10.47 filed on Registrant's Annual Report on Form 10-K (File
No. 0-20872) for the year ended December 31, 1996
10.21 St. Mary Land & Exploration Company Incentive Stock Option
Plan incorporated by reference from the Exhibit 10.48 filed on
Registrants Annual Report on Form 10-K (File No. 0-20872) for
the year ended December 31, 1996
10.22 St. Mary Land & Exploration Company Employee Stock Purchase
Plan incorporated by reference from the Exhibit 10.48 filed on
Registrants Annual Report on Form 10-K (File No. 0-20872) for
the year ended December 31, 1997
10.23 Credit Agreement dated June 30, 1998, incorporated by reference
from the Exhibit 10.52 filed on Form 10-Q dated June 30, 1998
10.24 Purchase and Sale Agreement dated November 12, 1998 between
ONEOK Resources Company, incorporated by reference from the
Exhibit 10.53 filed on Registrant's Current Report on Form 8-K
(File No.
0-20872) dated December 30, 1998
10.25 Credit Agreement between Panterra Petroleum and Colorado
National Bank dated June 17, 1997
10.26 Agreement between Summo Minerals Corporation, Summo USA Corpora-
tion, St. Mary Land & Exploration Company, and St. Mary Minerals
Inc. re the formation of Lisbon Valley Mining Company dated May
15, 1997
10.27 Pledge and Security Agreement From Summo USA Corporation and
Lisbon Valley Mining Co. LLC to St. Mary Minerals Inc. dated
November 23, 1998
10.28 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
21.1* Subsidiaries of Registrant
23.3 Consent of Arthur Andersen LLP
23.4 Consent of PricewaterhouseCoopers LLP
24.1 Power of Attorney (included on signature page of this document)
27.1 Financial Data Schedule
* Incorporated by reference from Registrant's Registration Statement
on Form S-1 (File No. 33-53512).
(d) Financial Statement Schedules. See Item 14(a) above.
-46-
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Board of Directors and Stockholders
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,
1998 and 1997, and the related consolidated statements of operations,
stockholders' equity, and cash flows for each of the two years in the period
ended December 31, 1998. 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 generally accepted auditing
standards. 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 financial statements referred to above present fairly, in
all material respects, the consolidated financial position of St. Mary Land &
Exploration Company and subsidiaries as of December 31, 1998 and 1997, and the
consolidated results of its operations and its cash flows for each of the two
years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Denver, Colorado,
February 17, 1999.
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
Board of Directors and Stockholders
St. Mary Land & Exploration Company and Subsidiaries:
We have audited the accompanying consolidated statements of operations,
stockholders' equity, and cash flows of St. Mary Land & Exploration Company and
Subsidiaries for the year ended December 31, 1996. 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 audit.
We conducted our audit in accordance with generally accepted auditing standards.
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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated results of operations and cash flows of
St. Mary Land & Exploration Company and Subsidiaries for the year ended December
31, 1996, in conformity with generally accepted accounting principles.
PricewaterhouseCoopers LLP
Denver, Colorado March 3, 1997, except for the effects of adopting Statement of
Financial Accounting Standards No. 128, "Earnings Per Share," as discussed in
Note 1, as to which the date is March 19, 1998.
F-2
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,
--------------------------
1998 1997
--------- ---------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 7,821 $ 7,112
Accounts receivable 17,937 24,320
Prepaid expenses and other 795 112
Refundable income taxes 391 246
Deferred income taxes 125 122
--------- ---------
Total current assets 27,069 31,912
--------- ---------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 241,021 246,468
Unproved oil and gas properties, net of impairment
allowance of $5,987 in 1998 and $3,032 in 1997 25,588 28,615
Other 4,051 3,386
--------- ---------
270,660 278,469
Less accumulated depletion, depreciation, amortization and impairment (126,835) (120,988)
--------- ---------
143,825 157,481
--------- ---------
Other assets:
Khanty Mansiysk Oil Corporation receivable and stock 6,839 12,003
Summo Minerals Corporation investment and receivable 2,869 6,691
Restricted cash 720 -
Other assets 3,175 4,048
--------- ---------
13,603 22,742
--------- ---------
$184,497 $212,135
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 16,926 $ 21,817
Accrued expenses - 126
Current portion of stock appreciation rights 358 351
--------- ---------
Total current liabilities 17,284 22,294
--------- ---------
Long-term liabilities:
Long-term debt 19,398 22,607
Deferred income taxes 11,158 16,589
Stock appreciation rights 422 989
Other noncurrent liabilities 1,493 1,724
--------- ---------
32,471 41,909
--------- ---------
Commitments and contingencies (Notes 1,3,6,7,8)
Stockholders' equity:
Common stock, $.01 par value: authorized - 50,000,000 shares in 1998 and
15,000,000 shares in 1997; issued and outstanding - 10,992,447
shares in 1998 and 10,980,423 shares in 1997 110 110
Additional paid-in capital 67,761 67,494
Treasury stock - 147,800 shares, at cost (2,470) -
Retained earnings 69,341 80,328
--------- ---------
Total stockholders' equity 134,742 147,932
--------- ---------
$184,497 $212,135
========= =========
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-3
<TABLE>
ST. MARY LAND & EXPORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
<CAPTION>
For the Years Ended December 31,
-----------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Operating revenues:
Oil and gas production $ 70,648 $ 75,764 $ 56,774
Gain on sale of Russian joint venture - 9,671 -
Gain on sale of proved properties 7,685 4,220 2,254
Other revenues 411 1,391 523
----------- ----------- -----------
Total operating revenues 78,744 91,046 59,551
----------- ----------- -----------
Operating expenses:
Oil and gas production 17,005 15,258 12,897
Depletion, depreciation and amortization 24,912 18,366 12,732
Impairment of proved properties 17,483 5,202 408
Exploration 11,705 6,847 8,185
Abandonment and impairment of unproved properties 4,457 2,077 1,469
General and administrative 7,097 7,645 7,603
Writedown of Russian convertible receivable 4,553 - -
Writedown of investment in Summo Minerals Corporation 3,949 - -
(Income) loss in equity investees 661 325 (1,272)
Other 141 281 78
----------- ----------- -----------
Total operating expenses 91,963 56,001 42,100
----------- ----------- -----------
Income (loss) from operations (13,219) 35,045 17,451
Nonoperating income and (expense):
Interest income 638 1,043 186
Interest expense (1,665) (1,142) (2,137)
----------- ----------- -----------
Income (loss) from continuing operations before income taxes (14,246) 34,946 15,500
Income tax expense (benefit) (5,415) 12,325 5,333
----------- ----------- -----------
Income (loss) from continuing operations (8,831) 22,621 10,167
Gain on sale of discontinued operations, net of taxes
of $17 in 1998, $252 in 1997 and $82 in 1996 34 488 159
----------- ----------- -----------
Net income (loss) $ (8,797) $ 23,109 $ 10,326
=========== =========== ===========
Basic earnings per common share:
Income (loss) from continuing operations $ (.81) $ 2.13 $ 1.16
Gain on sale of discontinued operations - .05 .02
=========== =========== ===========
Basic net income (loss) per common share $ (.81) $ 2.18 $ 1.18
=========== =========== ===========
Diluted earnings per common share:
Income (loss) from continuing operations $ (.81) $ 2.10 $ 1.15
Gain on sale of discontinued operations - .05 .02
=========== =========== ===========
Diluted net income (loss) per common share $ (.81) $ 2.15 $ 1.17
=========== =========== ===========
Basic weighted average shares outstanding 10,937 10,620 8,759
=========== =========== ===========
Diluted weighted average shares outstanding 10,937 10,753 8,826
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-4
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 Stockholders'
Shares Amount Capital Earnings Shares Amount Income Equity
----------- ------ --------- --------- --------- -------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995 8,761,855 $ 88 $ 15,835 $ 50,378 (2,572) $ (34) $ 15 66,282
Comprehensive income:
Net income - - - 10,326 - - - 10,326
Unrealized loss on marketable
equity securities available
for sale - - - - - - (47) (47)
-------------
Total comprehensive income 10,279
-------------
Cash dividends, $ .16 per share - - - (1,401) - - - (1,401)
Purchase and retirement of
common stock (69) - - - - - - -
Retirement of treasury stock (2,572) - (34) - 2,572 34 - -
----------- ------ --------- -------- --------- -------- ------------- -------------
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 available
for sale - - - - - - 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
=========== ====== ========= ========= ========= ======== ============= =============
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
F-5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Years Ended December 31,
---------------------------------------------
1998 1997 1996
--------- ---------- ----------
<S> <C> <C> <C>
Reconciliation of net income to net cash provided by operating activities:
Net income (loss) $ (8,797) $ 23,109 $ 10,326
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 - -
Gain on sale of proved properties (7,685) (4,220) (2,254)
Depletion, depreciation and amortization 24,912 18,366 12,732
Impairment of proved properties 17,483 5,202 408
Exploratory dry hole costs 4,892 1,638 3,048
Abandonment and impairment of unproved properties 4,457 2,077 1,469
Loss (income) in equity investees 661 325 (1,272)
Deferred income taxes (5,431) 10,799 4,634
Other 378 428 17
--------- ---------- ----------
39,372 48,053 29,108
Changes in current assets and liabilities:
Accounts receivable 6,502 (3,235) (8,810)
Prepaid expenses (2,109) 2,162 (478)
Refundable income taxes (145) (189) 119
Accounts payable and accrued expenses 1,762 (2,359) 2,788
Stock appreciation rights 7 (1,199) 1,550
Deferred income taxes (3) (122) (72)
--------- ---------- ----------
Net cash provided by operating activities 45,386 43,111 24,205
--------- ---------- ----------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 23,380 7,723 3,082
Capital expenditures (54,375) (54,164) (27,504)
Acquisition of oil and gas properties (4,204) (27,291) (20,957)
Purchase of interest in St. Mary Operating Company - - 3,059
Sale of Russian joint venture 75 5,608 (209)
Investment in and loans to Summo Minerals Corporation (788) (2,332) (500)
Receipts from restricted cash 7,275 9,747 -
Deposits to restricted cash (7,995) (6,829) (2,918)
Other (350) 61 772
--------- ---------- ----------
Net cash used in investing activities (36,982) (67,477) (45,175)
--------- ---------- ----------
Cash flows from financing activities:
Proceeds from long-term debt 54,579 22,837 42,996
Repayment of long-term debt (57,787) (43,819) (19,009)
Proceeds from sale of common stock, net of offering costs 173 51,207 -
Repurchase of common stock (2,470) - -
Dividends paid (2,190) (2,084) (1,402)
Other - (1) -
--------- ---------- ----------
Net cash (used in) provided by financing activities (7,695) 28,140 22,585
--------- ---------- ----------
Net increase in cash and cash equivalents 709 3,774 1,615
Cash and cash equivalents at beginning of period 7,112 3,338 1,723
--------- ---------- ----------
Cash and cash equivalents at end of period $ 7,821 $ 7,112 $ 3,338
========= ========== ==========
</TABLE>
F-6
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,
------------------------------------
1998 1997 1996
-------- --------- ---------
(in thousands)
<S> <C> <C> <C>
Cash paid for interest $ 1,650 $ 1,248 $ 1,953
Cash paid for income taxes 307 1,864 (305)
Cash paid for exploration expenses 11,873 6,462 4,843
</TABLE>
In March 1996, the Company acquired the remaining 35% shareholder interest in
St. Mary Operating Company for $234,000 and assumed net liabilities of $339,000,
resulting in acquired cash of $3.1 million.
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.
The accompanying notes are an integral part
of these consolidated financial statements.
F-7
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998
1. Summary of Significant Accounting Policies:
Description of Operations:
St. Mary Land & Exploration Company (the "Company") is an independent
energy company engaged in the exploration, development, acquisition and
production of natural gas and crude oil. 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. In February 1997 the Company
completed the sale of its interest in the Russian joint venture.
Basis of Presentation:
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. All significant intercompany accounts
and transactions have been eliminated.
The Company accounts for its investment in Summo Minerals Corporation
("Summo") under the equity method of accounting. 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. In March 1996 the Company completed its purchase of
the remaining stock of St. Mary Operating Company ("SMOC"). The purchase
increased the Company's ownership in SMOC from 65% to 100%. Through March 31,
1996, the Company accounted for its investment in SMOC using the equity method
of accounting. The Company's interests in other oil and gas ventures and
partnerships are proportionately consolidated, including its 74% investment in
Panterra Petroleum ("Panterra").
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, collectibility 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 and
Shreveport, Louisiana. At December 31, 1998 and 1997, the Company had $4,697,000
and $7,295,000, 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-8
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. 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 to the extent that capitalized costs of
unproved properties, on a field-by-field basis, are not considered to be
realizable. 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 are expected to be offset by
the estimated residual value of lease and well equipment.
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. 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 discounted future net revenues from the producing property.
During 1998, 1997 and 1996 the Company recorded impairment charges for proved
properties of $17,483,000, $5,202,000 and $408,000, respectively.
Gains and losses are recognized on sales of entire interests in proved
and unproved properties. Sales of partial interests are generally treated as
recoveries of costs.
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 are included in
operations.
Restricted Cash:
Proceeds from the sales of certain oil and gas producing properties are
held in escrow and restricted for future acquisitions under a tax-free exchange
agreement. These funds have been 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.
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 balanced in the future due to insufficient remaining reserves.
Related receivables totaling $1,928,000 at December 31, 1998 and $1,955,000 at
December 31, 1997 are included in other assets in the accompanying balance
sheets. The Company also reduces revenue for gas sold by the Company that cannot
be balanced in the future due to insufficient remaining reserves. Related
payables totaling $872,000 at December 31, 1998 and $1,105,000 at December 31,
1997 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).
F-9
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. The Company realized a net gain of $1,873,000 on these
contracts for the year ended December 31, 1998 and realized net losses of
$3,242,000 and $4,253,000 on these contracts for the years ended December 31,
1997 and 1996, respectively.
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.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," effective for all fiscal
quarters of fiscal years beginning after June 15, 1999. The Statement requires
companies to report all derivatives at fair value as either assets or
liabilities and bases the accounting treatment of the derivatives on the reasons
an entity holds the instrument. The Company is currently reviewing the effects
this Statement will have on the financial statements in relation to the
Company's hedging activities.
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 share of common 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, 1998, there
were 66,748 securities that would normally be considered dilutive. However, as
the Company was in a net loss position for the year ended December 31, 1998, all
of the outstanding options were considered anti-dilutive and were therefore
excluded from the diluted earnings per share calculation. The outstanding
dilutive securities for the years ended December 31, 1997 and 1996 were 132,666
and 66,326, respectively. All net income of the Company is available to common
stockholders.
F-10
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 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 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 1997 and 1996 consolidated financial statements
have been reclassified to correspond to the 1998 presentation.
F-11
2. Accounts Receivable:
Accounts receivable are composed of the following:
<TABLE>
<CAPTION>
December 31,
--------------------------
1998 1997
------------- ------------
(In thousands)
<S> <C> <C>
Accrued oil and gas sales $ 7,170 $ 13,373
Due from joint interest owners 7,868 8,360
Other 2,899 2,587
============= ============
$ 17,937 $ 24,320
============= ============
</TABLE>
3. Summo Minerals Corporation Investment and Receivable:
As of December 31, 1998 and 1997, the Company owned 9,924,093 shares
(37% of total shares outstanding) of Summo, a North American mining company,
with a total cost of $5,859,000. The Company also owned warrants to acquire an
additional 616,090 shares of Summo common stock as of December 31, 1998 and
1997. These warrants expired January 12, 1999. The market value of this
investment declined to $705,000 at December 31, 1998. For the years ended
December 31, 1998, 1997 and 1996 the Company reported equity in losses from
Summo of $661,000, $526,000 and $457,000, respectively.
In May 1997 the Company entered into an agreement to receive a 55%
interest in Summo's Lisbon Valley Copper Project (the "Project") in return for
the Company contributing $4,000,000 in cash, all of its outstanding stock in
Summo, and $8,600,000 in letters of credit to a single purpose company, Lisbon
Valley Mining Company LLC ("LVMC"), formed to own and operate the Project. Summo
will contribute the property, all project permits and contracts, $3,200,000 in
cash, and a commitment for $45,000,000 of senior debt financing in return for a
45% interest in LVMC. The agreement is subject to certain conditions, including
finalization of the necessary project financing. In September 1998, Summo
received final regulatory approval to develop the Project.
The Company has agreed to provide Summo with interim financing of up to
$3,471,000 for the Project in the form of a loan due in June 1999 bearing
interest at the prime rate plus 1%. As security for this loan, Summo has pledged
its interest in LVMC to the Company by entering into a pledge and security
agreement, a deed of trust, and an assignment of rents and security agreement.
All of these agreements are dated November 23, 1998. As of December 31, 1998 and
1997, the amounts outstanding under this loan were $2,869,000 and $2,081,000,
respectively. Additional amounts totaling $188,000 have been advanced to Summo
under this loan to date in 1999.
F-12
The principal amount of the note outstanding at December 31, 1998 is
convertible into shares of Summo common stock at a conversion price equal to the
weighted-average trading price of the common stock on the Toronto Stock Exchange
for the twenty trading days immediately prior to and including December 31,
1998. The principal amount of advances made by the Company to Summo during 1999
are convertible into shares of Summo common stock at a conversion price equal to
the weighted-average trading price of the common stock on the Toronto Stock
Exchange for the twenty trading days immediately prior to and including June 12,
2000. Upon capitalization of LVMC the outstanding loan principal shall
constitute a capital contribution in partial satisfaction of the Company's
capital commitments set out in the May 1997 agreement, and any accrued interest
on the loan shall be forgiven.
Future development and financial success of the Project are largely
dependent on the market price of copper, which is determined in world markets
and is subject to significant fluctuations. Current copper prices have declined
to ten-year lows and do not justify construction and development of the Project
at this time. Management believes that copper prices will recover and that the
Project will have considerable value at that time. The Company has the ability
to fund the carrying costs of the property and the intent to retain its interest
in the Project until copper prices do recover.
The Company has analyzed its net investment in Summo and the effect of
persistent depressed copper prices and increased worldwide copper inventory
levels on Summo's stock price. Management believes Summo's stock price decline
is not temporary and that its value is impaired. Consequently, the Company wrote
down its net investment in Summo to net realizable value in the fourth quarter
of 1998. Management believes the recorded net investment is recoverable.
4. Income Taxes:
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
For the Years Ended
December 31,
--------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
<S> <C> <C> <C>
Current taxes:
Federal $ 213 $ 485 $ 81
State 141 972 700
Deferred taxes (5,752) 10,677 4,634
Benefit of deduction for stock
option exercises - 443 -
--------- --------- ---------
Total income tax expense (benefit) $ (5,398) $ 12,577 $ 5,415
========= ========= =========
Continuing operations $ (5,415) $ 12,325 $ 5,333
Discontinued operations 17 252 82
--------- --------- ---------
Total income tax expense (benefit) $ (5,398) $ 12,577 $ 5,415
========= ========= =========
</TABLE>
The above taxes from continuing operations are net of alternative fuels
credits (Internal Revenue Code Section 29) of $315,000 in 1998, $525,000 in 1997
and $551,000 in 1996.
F-13
The components of the net deferred tax liability are as follows:
<TABLE>
<CAPTION>
December 31,
---------------------
1998 1997
--------- ---------
(In thousands)
<S> <C> <C>
Deferred tax liabilities:
Oil and gas properties $ 13,194 $ 18,279
Other 833 2,478
--------- ---------
Total deferred tax liabilities 14,027 20,757
--------- ---------
Deferred tax assets:
Other, primarily employee benefits 696 1,496
State tax net operating loss carryforward 1,255 1,989
State and federal income tax benefit 930 1,320
Alternative minimum tax credit carryforward 1,123 784
--------- ---------
Total deferred tax assets 4,004 5,589
Valuation allowance (1,010) (1,299)
--------- ---------
Net deferred tax assets 2,994 4,290
--------- ---------
Total net deferred tax liabilities 11,033 16,467
Current deferred income tax assets 125 122
--------- ---------
Non-current net deferred tax liabilities $ 11,158 $ 16,589
========= =========
</TABLE>
At December 31, 1998, the Company had state net operating loss
carryforwards of approximately $25,800,000 which expire between 1999 and 2012
and alternative minimum tax credit carryforwards of $1,123,000 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 1998 results from
the current year calculation of deferred state income tax for Oklahoma and the
state benefit of federal income tax which is not 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,
------------------------------------
1998 1997 1996
-------- ---------- ---------
(In thousands)
<S> <C> <C> <C>
Federal statutory taxes $(4,843) $ 11,881 $ 5,270
Increase (reduction) in taxes resulting from:
State taxes (net of Federal benefit) 191 758 1,212
Statutory depletion (119) (174) (173)
Alternative fuels credits (Section 29) (315) (525) (551)
Change in valuation allowance (289) 401 (504)
Other (40) (16) 79
-------- ---------- ---------
Income tax expense (benefit) from
continuing operations $(5,415) $ 12,325 $ 5,333
======== ========== =========
</TABLE>
F-14
5. Long-term Debt and Notes Payable:
On June 30, 1998, the Company entered into a new long-term revolving
credit agreement that replaced the agreement dated March 1, 1993 and amended in
April 1996. The new credit agreement specifies a maximum loan amount of
$200,000,000, and the initial aggregate borrowing base was $115,000,000. The
lender may periodically re-determine the aggregate borrowing base. In December
1998 the borrowing base was reduced by the lender to $105,000,000 as a result of
the sale of certain producing properties in Oklahoma. The accepted borrowing
base was $40,000,000 at December 31, 1998. 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, 1998 and
1997, $10,500,000 and $14,450,000, respectively, was outstanding under this
credit agreement.
Effective June 30, 1998, interest on borrowings during the revolving
period and commitment fees on the unused portion of the accepted borrowing base
are calculated as follows:
INTEREST RATES:
Debt to Capitalization Ratio Interest Rate
- ---------------------------- -------------
Less than 0.3 to 1.0 The Company's option of
(a) LIBOR + 0.50% or
(b) the higher of the Federal Funds
Rate + 0.5% or the Prime Rate
Greater than or equal
to 0.3 to 1.0 The Company's option of
but less than 0.4 to 1.0 (a) LIBOR + 0.75% or
(b) the higher of the Federal Funds
Rate + 0.5% or the Prime Rate
Greater than or equal The Company's option of
to 0.4 to 1.0 (a) LIBOR + 1.00% or
but less than 0.5 to 1.0 (b) the higher of the Federal Funds
Rate + 0.5% or the Prime Rate
Greater than or equal The Company's option of
to 0.5 to 1.0 (a) LIBOR + 1.25% or
(b) the higher of the Federal Funds
Rate + 0.625% or
the Prime Rate + 0.125%
COMMITMENT FEES:
Debt to Capitalization Ratio Short-Term Tranche Long-Term Tranche
- ---------------------------- ------------------ -----------------
Less than 0.5 to 1.0 0.125% 0.25%
Greater than or equal to 0.5 to 1.0 0.375% 0.50%
At December 31, 1998, the Company's debt to capitalization ratio as
defined under the credit agreement was 0.13 to 1.0.
Panterra, in which the Company has a 74% general partnership ownership
interest, has a separate credit facility with a $21,000,000 borrowing base as of
December 31, 1998, and $12,000,000 and $11,000,000 outstanding as of December
31, 1998 and 1997, respectively. In June 1997, Panterra entered into this credit
agreement replacing a previous agreement, which was due March 31, 1999. The new
credit agreement includes a revolving period converting to a five-year
amortizing loan on June 30, 2000. During the revolving period of the loan, loan
balances accrue interest at Panterra's option of either the bank's prime rate or
LIBOR plus 0.75% when the Partnership's debt to partners' capital ratio is less
than 30%, up to a maximum of either the bank's prime rate or LIBOR plus 1.25%
when the Partnership's debt to partners' capital ratio is greater than 100%. At
December 31, 1998, Panterra's debt to partners' capital ratio as defined was
66%.
F-15
The carrying value of long-term debt approximates fair value because
the debt is variable rate and reprices in the short term.
The Company's liability for estimated annual principal payments for the
next five years under both notes payable are as follows:
<TABLE>
<CAPTION>
Years Ending
December 31, (In thousands)
---------------------- --------------
<S> <C>
1999 $ -
2000 1,173
2001 3,670
2002 3,229
2003 2,959
Thereafter 8,367
-------------
$ 19,398
=============
</TABLE>
6. Commitments and Contingencies:
The Company leases office space under various operating leases with terms
extending as far as June 30, 2003. The Company has noncancelable annual
subleases with affiliates of approximately $75,000 for the same term as the
Company's primary office lease. Rent expense, net of sublease income, was
$484,000, $447,000 and $426,000 in 1998, 1997 and 1996, respectively. The
Company also leases various office equipment under 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>
1999 $ 626
2000 637
2001 633
2002 369
2003 133
</TABLE>
On January 29, 1999, the Company obtained a commitment for a letter of
credit ("LOC") from an U.S. bank. The beneficiary of the LOC is a Canadian bank,
and the LOC is used as collateral for an irrevocable letter of guarantee ("ILG")
which was furnished to the Canadian federal taxing authority. The ILG was
provided on behalf of the Company and its joint venture partners securing
possible Canadian federal tax liabilities resulting from the sale of assets in
Canada.
F-16
The Company had the following commodity contracts in place as of
December 31, 1998, to hedge or otherwise reduce the impact of oil and gas price
fluctuations:
Product Volumes/month Fixed Price Duration
----------- ------------- ----------- -----------
Natural Gas 100,000 MMBtu $2.3450 1/99 - 3/99
Natural Gas 100,000 MMBtu $2.1900 1/99 - 4/99
Natural Gas 100,000 MMBtu $2.1200 1/99 - 10/99
Natural Gas 170,000 MMBtu $2.0900 1/99 - 10/99
Natural Gas 330,000 MMBtu month $1.9450 1/99 - 12/99
Natural Gas 220,000 MMBtu $2.3100 1/99 - 12/99
Natural Gas 50,000 MMBtu $2.0350 2/99 - 4/99
Natural Gas 220,000 MMBtu $2.6300 (a) 5/99 - 9/99
- ----------
(a) Price collar contract. Price ceiling shown, price floor equals
$1.90 per MMbtu.
The fair value of the Company's commodity hedging contracts based on
year-end futures pricing would have caused the Company to receive approximately
$776,000 if these contracts had been terminated on December 31, 1998.
At December 31, 1998, Panterra, in which the Company owns a 74%
interest, held various hedge contracts covering 39,000 Bbls of future crude oil
production. These contracts expire at various dates through May 1999. Panterra
will receive fixed prices ranging from 15.68 per Bbl to 16.80 per Bbl. If the
open hedging contracts had been liquidated at December 31, 1998, Panterra would
have recognized a gain of approximately $152,000.
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, 1998, and those detailed above, the Company has hedged
approximately 45% of its estimated 1999 gas production at an average fixed price
of $2.10 per MMBtu, approximately 9% of its estimated 1999 oil production at an
average fixed price of $15.11 per Bbl and approximately 8% of its estimated 2000
oil production at an average fixed price of $14.76 per Bbl. The Company has also
purchased options resulting in price collars on approximately 7% of the
Company's estimated 1999 gas production with price ceilings between $2.00 and
$2.63 per MMBtu and price floors between $1.50 and $1.90 per MMBtu.
7. Compensation Plans:
In January 1992, the Company adopted two compensation plans for key
employees. A cash bonus plan not to exceed 50% of the participants' aggregate
base salaries was adopted, and any awards are based on performance. 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 the year. This
interest is increased 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 $229,000 in 1998 and $416,000 in 1997 relating
to net profits attributable to these properties.
F-17
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, 1998, there were 28,455 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 was reduced by $197,000 in 1998 under the SAR plan.
Compensation expense recognized under the SAR plan was $161,000 and $1,567,000
in 1997 and 1996, respectively. 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.
The Company has a defined contribution pension plan ("401(k) Plan")
qualified under the Employee Retirement Income Security Act of 1974. This 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 $269,000, $231,000 and
$199,000 for the years ended December 31, 1998, 1997 and 1996, respectively.
During 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. The
Company has reserved 700,000 shares of its own common stock for issuance under
the Option Plans. The Company intends to increase the number of shares of common
stock available for issuance under the Option Plans and to seek shareholder
approval of such increase in 1999. During 1996 options to purchase 256,598
shares of the Company's common stock were granted under the Option Plans at an
exercise price of $20.50 in connection with the termination of future awards
under the Company's SAR plan. Also during 1996, options to purchase 42,880
shares were granted under the Option Plans at an exercise price $24.875. The
vesting periods of these options vary from 0 to 3 years, and the options are
exercisable for the period from five to ten years after the date of grant. No
options under the Option Plans were exercised during the year ended December 31,
1996. In 1997 14,072 options under the Option Plans were exercised at $20.50 per
share, and an additional 74,057 and 107,423 options were granted at $29.375 and
$35.00 per share, respectively. During the year ended December 31, 1998, 251,774
options were granted and no 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-18
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, leaving 20,000 options
outstanding. None of these options were exercised in 1998.
A summary of the status of the Company's Stock Option Plan, including the
1990 and 1991 options, and changes during the last three years follows:
<TABLE>
<CAPTION>
For the Years Ended December 31,
------------------------------------------------------------------------------
1998 1997 1996
-------------------------- ------------------------- -------------------------
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 479,343 $ 24.80 354,092 $ 18.38 $ 3.30
54,614
Granted 251,774 18.50 181,480 32.70 299,478 21.13
Exercised - - - -
48,686 8.27
Forfeited 9,899 28.63 20.50 - -
7,543
------------- ------------ ------------ ------------ ------------ ------------
Outstanding at end of year 721,218 $ 22.55 479,343 $ 24.80 354,092 $ 18.38
============= ============ ============ ============ ============ ============
Options exercisable at year end 164,670 $ 18.41 129,173 $ 17.84 145,576 $ 14.05
============= ============ ============ ============ ============ ============
Weighted average fair value of
options granted during the year $ 8.16 $ 15.05 $ 8.06
============= ============ ============
</TABLE>
A summary of additional information related to the options outstanding
as of December 31, 1998 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>
$ 3.30 - $ 3.30 20,000 2.0 years $ 3.30 20,000 $ 3.30
-
18.50 18.50 251,774 10.0 years 18.50 - -
-
20.50 24.88 273,558 5.4 years 21.15 144,670 20.50
-
29.38 35.00 175,886 8.6 years 32.69 - -
----------------- ---------------
Total
721,218 7.7 years 22.55 164,670 18.41
================= ===============
</TABLE>
F-19
SFAS No. 123 establishes a fair value method of accounting for
stock-based compensation plans either through recognition or disclosure. The
Company has elected to continue following 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.
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair value of options granted in 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 .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 fair value of the options granted in 1996 was estimated using
the following weighted-average assumptions: risk-free interest rate of 6.2%;
dividend yield of .76%; volatility factor of the expected market price of the
Company's common stock of 37.88%; and expected life of the options of 4.8 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,
------------------------------------
1998 1997 1996
--------- -------- --------
(In thousands, except per share amounts)
<S> <C> <C> <C>
Net income (loss) applicable As reported $ (8,797) $ 23,109 $ 10,326
to common stock Pro forma $ (9,682) $ 22,443 $ 9,607
Basic earnings (loss) per share As reported $ (.81) $ 2.18 $ 1.18
Pro forma $ (.89) $ 2.11 $ 1.10
Diluted earnings (loss) per share As reported $ (.81) $ 2.15 $ 1.17
Pro forma $ (.89) $ 2.09 $ 1.09
</TABLE>
F-20
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.
On September 18, 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 Company has set aside 500,000 shares of its
common stock to be available for issuance under the Stock Purchase Plan, and
8,424 shares were sold under the Stock Purchase Plan in 1998. No compensation
expense was recorded in 1998 related to the plan.
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 is as follows:
<TABLE>
<CAPTION>
Pension Plans Other Benefits
--------------------- ---------------------
December 31, December 31,
--------------------- ---------------------
1998 1997 1998 1997
-------- -------- -------- -------
(In thousands) (In thousands)
<S> <C> <C> <C> <C>
Change in benefit obligations:
Benefit obligation at beginning of year $ 1,926 $ 1,330 $ 141 $ 110
Service Cost 201 192 24 19
Interest Cost 151 100 11 9
Actuarial gain 472 330 9 3
Benefits paid (280) (26) - -
-------- -------- -------- -------
Benefit obligation at end of year $ 2,470 $ 1,926 $ 185 $ 141
======== ======== ======== =======
Change in plan assets:
Fair value of plan assets at beginning of year $ 932 $ 874 - -
Actual return on plan assets 179 84 - -
Employer contribution 381 - - -
Benefits paid (280) (26) - (4)
-------- -------- -------- -------
Fair value of plan assets at end of year $ 1,212 $ 932 $ - $ (4)
======== ======== ======== =======
Funded Status $(1,258) $ (994) $ (185) $ (145)
Unrecognized net actuarial loss 867 576 64 57
Unrecognized prior service cost (43) (50) - -
-------- -------- -------- -------
Prepaid (accrued) benefit cost $ (434) $ (468) $ (121) $ (88)
======== ======== ======== =======
</TABLE>
F-21
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 $274,000 at December 31, 1998, and $271,000
at December 31, 1997. 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
$121,000 as of December 31, 1998, and $88,000 as of December 31, 1997.
Assumptions used in the measurement of the Company's benefit obligation
are as follows:
<TABLE>
<CAPTION>
Pension Plans Other Benefits
------------------- -------------------
December 31, December 31,
------------------- -------------------
1998 1997 1998 1997
----- ----- ----- -----
(In thousands) (In thousands)
<S> <C> <C> <C> <C>
Weighted-average assumptions:
Discount rate 6.50% 7.00% 7.00% 7.00%
Expected return on plan assets 5.00% 5.00% N/A N/A
Rate of compensation increase 8.00% 8.00% N/A N/A
</TABLE>
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,
----------------- --------------
1998 1997 1998 1997
------- ------- ----- ------
(In thousands) (In thousands)
<S> <C> <C> <C> <C>
Components of net periodic benefit cost:
Service cost $ 201 $ 192 $ 24 $ 19
Interest cost 151 100 11 9
Expected return on plan assets (179) (84) - -
Amortization of prior service cost 174 21 - -
Recognized net actuarial loss - - 2 2
------- ------- ----- ------
Net periodic benefit cost $ 347 $ 229 $ 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 $ 11 $ 4
Effect on the health care component of the accumulated
postretirement benefit obligation $ (37) $ 29
</TABLE>
F-22
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.
10. Investment in Russian Joint Venture:
In September 1991 the Company, through an affiliate, acquired a 22%
interest in The Limited Liability Company Chernogorskoye (the "Russian joint
venture"). The Company's interest in the Russian joint venture was reduced to
18% in 1993. The Russian joint venture is developing the Chernogorskoye field in
western Siberia. 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 $10,134,000 plus interest at 10% per annum from the
limited liability company formed to hold the Russian joint venture interest. The
Company's receivable is collateralized by the partnership interest sold. The
Company has the right, subject to certain conditions, to require KMOC to
purchase the Company's receivable from the net proceeds of an initial public
offering of KMOC common stock. Alternatively, the Company may elect to convert
all or a portion of its receivable into KMOC common stock immediately prior to
an initial public offering of KMOC common stock or on or after March 10, 2000,
whichever occurs first. 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. Uncertain economic conditions in Russia and lower oil prices have
affected the realizability of the convertible receivable. As a result, the
Company has 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.
Summarized financial information of the Russian joint venture for the
last full year owned by the Company is shown below:
<TABLE>
<CAPTION>
For the Year Ended
December 31, 1996
-------------------------
(Unaudited, in thousands)
<S> <C>
Income Statement:
Oil and gas revenues $ 60,367
Operating expenses (44,752)
Interest and other expenses (9,199)
---------
Net income $ 6,416
=========
</TABLE>
F-23
11. Real Estate Assets:
In a prior year the Company made the decision to sell its remaining
real estate projects. Accordingly, the Company's real estate activities since
that time have been presented as discontinued operations in the consolidated
statements of income. The Company's remaining real estate assets consist of land
held for sale with a carrying cost of $1,095,000 and $1,149,000 as of December
31, 1998 and 1997, respectively, which in the opinion of management is less than
the estimated net realizable values.
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,
-------------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
<S> <C> <C> <C>
Development costs $ 32,191 $ 39,030 $ 16,709
Exploration costs:
Domestic 17,767 15,311 11,910
International - 16 84
Acquisitions:
Proved 4,204 27,291 20,957
Unproved 3,693 7,565 2,941
--------- --------- ---------
Total $ 57,855 $ 89,213 $ 52,601
========= ========= =========
Russian joint venture,
equity method (a) $ - $ - $ 3,881
========= ========= =========
</TABLE>
- --------------
(a) In February 1997, the Company sold its interest in the
Russian joint venture (see note 10).
F-24
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 1998, 1997, 1996 and 1995
was prepared by the Company and Ryder Scott Company. 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.
Presented below is a summary of the changes in estimated domestic
reserves of the Company and its share of the Russian joint venture reserves:
<TABLE>
<CAPTION>
For the Years Ended December 31,
------------------------------------------------------------------
1998 1997 1996
-------------------- --------------------- --------------------
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 11,493 196,230 10,691 127,057 7,509 75,705
Revisions of previous estimates (2,437) (42,430) (502) (7,486) 706 6,706
Discoveries and extensions 336 38,744 1,203 77,876 1,343 44,018
Purchases of minerals in place 679 1,225 1,328 24,809 2,625 16,894
Sales of reserves (182) (35,724) (39) (3,126) (306) (703)
Production (1,275) (25,440) (1,188) (22,900) (1,186) (15,563)
---------- -------- ---------- -------- ---------- --------
End of year (a) 8,614 132,605 11,493 196,230 10,691 127,057
========== ======== ========== ======== ========== ========
Proved developed U.S. reserves:
Beginning of year 10,268 168,229 10,015 100,027 6,829 66,230
========== ======== ========== ======== ========== ========
End of year 7,723 112,189 10,268 168,229 10,015 100,027
========== ======== ========== ======== ========== ========
Russian joint venture reserves:
End of year (b) - - - - 7,146 2,444
========== ======== ========== ======== ========== ========
</TABLE>
- -------------
(a) At December 31, 1998, 1997 and 1996, includes approximately 2,022,
1,982 and 1,622 MMcf, respectively representing the Company's
underproduced gas balancing position.
(b) In February 1997, the Company sold its interest in the Russian
joint venture (see note 10).
F-25
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 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.
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>
As of December 31,
-----------------------------------
1998 1997 1996
--------- --------- ---------
(In Thousands)
<S> <C> <C> <C>
Future cash inflows $328,630 $629,001 $691,945
Future production and
development costs (128,120) (202,503) (196,677)
Future income taxes (39,471) (120,742) (155,805)
--------- --------- ---------
Future net cash flows 161,039 305,756 339,463
10% annual discount (59,093) (118,409) (136,233)
--------- --------- ---------
Standardized measure of
discounted future net cash flows $101,946 $187,347 $203,230
========= ========= =========
Russian joint venture standardized
measure of discounted future net
cash flows (a) $ - $ - $ 23,681
========= ========= =========
</TABLE>
- -------------
(a) In February 1997, the Company sold its interest in the Russian joint
venture (see note 10).
F-26
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,
-----------------------------------
1998(a) 1997 1996
--------- --------- ---------
(In thousands)
<S> <C> <C> <C>
Standardized measure,
beginning of year $187,347 $203,230 $ 87,699
Sales of oil and gas produced,
net of production costs (53,643) (60,506) (43,877)
Net changes in prices and
production costs (78,974) (132,465) 71,882
Extensions, discoveries and other,
net of production costs 36,495 112,698 90,974
Purchase of minerals in place 5,548 40,647 26,241
Development costs incurred
during the year 12,964 11,305 6,833
Changes in estimated future
development costs 1,641 (2,998) (1,166)
Revisions of previous quantity estimates (39,303) (8,885) 19,350
Accretion of discount 26,152 29,646 12,019
Sales of reserves in place (26,435) (5,493) (1,224)
Net change in income taxes 50,994 19,089 (61,459)
Other (20,840) (18,921) (4,042)
--------- --------- ---------
Standardized measure, end of year $101,946 $187,347 $203,230
========= ========= =========
</TABLE>
- -------------
(a) The standardized measure for the year ended December 31, 1998, was
based on a year-end gas price of $1.86 per MMBtu and a year-end
oil price of $12.05 per BbL. Using these prices the present value
of future net revenues discounted at 10% before tax is
$125,126,000.
F-27