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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, 1996.
[ ] 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 9,560,325 shares of voting stock held by
non-affiliates of the Registrant, based upon the closing sale price of the
Common Stock on March 21, 1997 of $25.125 per share as reported on the Nasdaq
National Market System, was $240,203,166. Shares of Common Stock held by each
officer and director and by each person who owns 5% or more of the outstanding
Common Stock and who may be deemed an affiliate have been excluded. This
determination of affiliate status is not necessarily a conclusive determination
for other purposes.
As of March 21, 1997, the Registrant had 10,942,759 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 1997 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, 1995......... 5
ITEM 2. PROPERTIES.................................................... 6
Domestic Operations...................................... 6
International Operations.................................12
Key Relationships........................................13
Acquisitions.............................................13
Reserves.................................................13
Production...............................................14
Productive Wells.........................................15
Drilling Activity........................................15
Domestic and International Acreage.......................16
Non-Oil and Gas Activities...............................16
Competition..............................................17
Markets and Major Customers..............................17
Government Regulations...................................17
Title to Properties......................................18
Operational Hazards and Insurance........................18
Employees and Office Space...............................19
Glossary.................................................19
ITEM 3. LEGAL PROCEEDINGS.............................................21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........21
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED SECURITY HOLDERS MATTERS.............................22
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA..........................23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS...........................25
Overview.................................................25
Results of Operations....................................27
Liquidity and Capital Resources..........................29
Accounting Matters.......................................32
Effects of Inflation and Changing Prices.................33
TABLE OF CONTENTS
(Continued)
ITEM PAGE
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..................34
ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE..........................34
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...........34
ITEM 11. EXECUTIVE COMPENSATION.......................................34
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT...............................................34
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...............34
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K..........................................35
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 crude oil and natural gas. 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, 1996, the Company had estimated net proved reserves of
approximately 10.7 MMBbls of oil and 127.1 Bcf of natural gas, or an aggregate
of 31.9 MMBOE (84% proved developed, 66% gas) with a PV-10 Value of $296.5
million.
From January 1, 1994 through December 31, 1996, the Company added estimated
net proved reserves of 28.5 MMBOE at an average finding cost of approximately
$4.05 per BOE. Average daily production increased from 7.1 MBOE per day in 1992
to over 12.0 MBOE per day in December 1996. The Company added 15.9 MMBOE of
estimated net proved reserves in 1996, representing a 58% increase for the year,
at an average Finding Cost of approximately $3.30 per BOE. In 1996, the
Company's estimated net proved reserve additions replaced 422% of production,
including 229% from drilling, 144% from property acquisitions and 49% from
revisions. The Company's 1997 capital budget of $65.0 million includes (i) $43.0
million for ongoing development and exploration programs in the core operating
areas, including three 3-D seismic surveys totaling approximately 90 square
miles, (ii) $15.0 million for niche acquisitions of properties and (iii) $7.0
million for high-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 shareholder value through consistent
growth in per share reserves, production and the resulting cash flow and
earnings. A focused and balanced program of low to medium-risk exploration,
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 high-risk, large-target exploration prospects each have the
potential to significantly increase the Company's reserves and production.
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 high-risk large-target exploration prospects. Since 1992 St.
Mary has expanded its technical and operating staff and increased its drilling,
production and operating capabilities. Senior technical managers, each with over
25 years of experience, are based in regional offices located near core
properties and are supported by centralized administration in the Company's
Denver office. The Company believes that its long-standing presence, its
established networks of local industry relationships and its strategic acreage
holdings in its core operating areas provide a significant competitive
advantage. In addition, the Company believes that its prior investment in
experienced technical and managerial personnel will facilitate the expansion of
its operations without the need to significantly increase overhead costs.
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 ongoing, low to
medium-risk development and exploration programs. St. Mary conducts detailed
geologic studies and uses seismic imaging and advanced well completion
techniques to maximize the potential of its existing properties. For example, in
1996 the Company had a significant exploration success in the Box Church Field
in east Texas which added 26.4 Bcf of estimated net proved reserves. During
1996, the Company participated in 117 domestic gross wells with an overall 82%
success rate.
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Large-Target Prospects. The Company invests 10% to 15% of its annual
capital budget in high-risk, large-target exploration projects and currently has
an inventory of eight such projects in its core areas in various stages. The
Company's strategy is to test one or more of these large exploration targets
each year while furthering the development of early-stage projects and
continuing the evaluation of potential new exploration prospects. 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. The Company expects that three of its deep gas prospects in
south Louisiana will be drilled and tested during 1997, including its South
Horseshoe Bayou prospect which reached its target depth of 19,000 feet in
January and was completed and initially tested in February.
Selective Acquisitions. The Company seeks to make selective niche
acquisitions of properties which 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 the Company has specialized
geologic knowledge or operating experience has enabled it to acquire
attractively-priced and under-exploited properties. During the last three years,
the Company completed 21 acquisitions totaling $41.5 million at an average
acquisition cost of $3.89 per BOE.
Strategic Relationships. The Company has historically cultivated strategic
partnerships with independent oil and gas operators having specialized
experience and 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, the
principal of which has over 25 years of experience in the Williston Basin.
Significant Developments Since December 31, 1995
Follow-on Equity Offering. On February 26, 1997 St. Mary closed the sale by
the Company of 2,000,000 shares of common stock at $25.00 per share. The sale of
an additional 180,000 shares was closed on March 12, 1997 pursuant to the
exercise of the underwriters' over-allotment option. Total net proceeds of the
offering of approximately $51.3 million will be used to fund the Company's
exploration and development activities and potential acquisitions and for
general corporate purposes.
Credit Facility. On April 1, 1996, the Company amended and restated its
Credit Facility with two banks to provide a $60 million collateralized
three-year revolving loan facility which thereafter converts at the Company's
option to a five-year term loan. The amount which may be borrowed from time to
time will depend upon the value of the Company's oil and gas properties and
other assets. The Company's borrowing base, which is redetermined annually, was
increased in February, 1997 to $60 million based on the increase in the
Company's estimated net proved reserves in 1996. Effective April 1, 1997 the
Company has reduced this commitment until the next redetermination to $10
million.
Russian Joint Venture. In order to focus on development and exploration
efforts in its five core operating areas, the Company decided in 1996 to sell
its interests in properties in Russia ("Russian joint venture"). As a result of
the closing of this sale which occurred on February 12, 1997, the Company
received cash consideration of approximately $5.2 million, approximately $1.7
million of common stock in Ural Petroleum Corporation ("UPC") and a receivable
in a form equivalent to a retained production payment of approximately $10.3
million plus interest at 10% per annum. See " Properties--International
Operations."
-5-
Acquisitions of Oil and Gas Properties. In 1996 the Company completed
eleven acquisitions of oil and gas properties for $21 million, including an
expansion of the Company's interests in the Permian Basin of New Mexico and west
Texas through the acquisition of a 90% interest in the oil and gas properties of
Siete Oil and Gas Company for $10 million.
Oil and Gas Property Sales. In order to continue to focus its development
and exploration activities, in 1996 the Company sold certain non-core oil and
gas properties in Wyoming and realized a net gain of approximately $2.3 million.
Personnel. In May 1996 David L. Henry joined the Company as Vice President
of Finance and Chief Financial Officer and in August 1996 Douglas W. York was
hired as Vice President of Acquisitions and Reservoir Engineering.
ITEM 2. PROPERTIES
Domestic Operations
The Company's exploration, development and acquisition activities are
focused in five core operating areas: the Mid-Continent region; the ArkLaTex
region; south Louisiana; the Williston Basin in North Dakota and Montana; and
the Permian Basin in west Texas and New Mexico. Set forth below is information
concerning each of the Company's major areas of operations based on the
Company's estimated net proved reserves as of December 31, 1996.
Oil Gas MBOE PV-10 Value
------- ------ ------------------- ------------------------
(MBbls) (MMcf) Amount Percent (In thousands) Percent
------- ------ ------ ------- -------------- -------
Mid-Continent Region........... 628 61,806 10,929 34.3% $113,466 38.3%
ArkLaTex Region................ 1,066 44,684 8,513 26.7% 89,740 30.3%
Williston Basin................ 5,648 3,734 6,270 19.7% 46,006 15.5%
South Louisiana................ 230 7,386 1,461 4.6% 19,424 6.6%
Permian Basin.................. 2,980 4,150 3,672 11.5% 19,499 6.6%
Other(1)....................... 139 5,297 1,022 3.2% 8,326 2.7%
------ ------- ------ ------ -------- ------
Total.......................... 10,691 127,057 31,867 100.0% $296,461 100.0%
====== ======= ====== ====== ======== ======
- -----------
(1) Excludes amounts attributable to the Company's Russian joint venture. On
February 12, 1997, the Company sold its Russian joint venture. See
"International Operations."
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 34%
of the Company's estimated net proved reserves as of December 31, 1996 or 10.9
MMBOE (92% proved developed and 94% gas). The Company participated in 75 gross
wells and recompletions in this region in 1996, including 17 Company-operated
wells. The Company's 1997 Mid-Continent capital budget of $26.5 million is
divided between low-risk exploration and development of the Granite Wash
formation, medium to high-risk prospects in the Red Fork and Upper and Lower
Morrow sands and continued exploration and development in the Sherman-Marietta
Basin. In addition, the Company has a 24.0% working interest in a large-target
prospect in the Cotton Valley Reef play of east Texas. The Company has arranged
commitments for three drilling rigs in the Mid-Continent region throughout 1997
and plans to drill 25 to 30 wells to be operated by the Company and participate
in an additional 30 wells to be operated by other entities.
-6-
Anadarko Basin. An extensive geologic study of the Granite Wash formation
in Washita and Beckham Counties, Oklahoma, undertaken by the Company in 1993 and
1994, has led to an ongoing, multi-year development program. Enhanced
understanding of the subsurface geology and application of advanced well
completion techniques have enabled the Company to exploit by-passed oil and gas
reserves and to improve reservoir recoveries. In 1995 and 1996 the Company
drilled or participated in a total of 28 gross wells in the Granite Wash, with
an overall 94% success rate. The Company's 1997 capital budget provides for
continuation of the Granite Wash program. The Company's activities in the
Granite Wash are balanced and complemented by its strategy to drill prospects,
particularly in the Red Fork and Upper and Lower Morrow formations in Beckham
and Roger Mills Counties, Oklahoma. These prospects target reserves at depths
ranging from 15,000 to 18,000 feet. St. Mary operated or participated in three
successful completions of exploratory wells in the Morrow channel sands during
1996 and approximately one-half of the Company's 1997 Mid-Continent exploration
and development budget is allocated to these Red Fork and Morrow prospects.
Sherman-Marietta Basin. In the geologically complex Sherman-Marietta Basin
the Company has established a significant acreage position in Cooke and Grayson
Counties, Texas in partnership with an independent operator with extensive
experience in the area. A twelve square mile 3-D seismic survey at the Company's
South Dexter prospect area in 1994 enabled the Company to interpret the area's
complex faulting and led to a discovery in the Ordovician Oil Creek sands during
1996. In 1997, the Company plans to continue further exploration in its Red
Branch prospect area where it has an approximate 34.1% working interest. The
Company continues to lease acreage in the basin and plans additional 3-D
projects during 1997 and 1998. See "Large-Target Exploration Projects."
Cotton Valley Reef Play. Within its inventory of large-target prospects,
the Company holds a 24.0% working interest in 10,060 acres in Leon County, Texas
in the rapidly developing Cotton Valley pinnacle 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 has identified a large structural
anomaly on its acreage at a depth of approximately 17,000 feet based on
interpretation of existing 2-D seismic data and, together with its partners,
plans to conduct a 52 square mile 3-D seismic survey in 1997. The Company
expects to complete processing and interpretation of the seismic data and final
evaluation of the prospective acreage by the end of 1997. See "Large-Target
Exploration Projects."
ArkLaTex Region. The Company's operations in the ArkLaTex area are managed
by the Company's 12-person office in Shreveport, Louisiana. 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. St. Mary's holdings in the ArkLaTex region are comprised of interests in
approximately 450 producing wells, including 51 Company-operated wells, and
interests in approximately 1,235 leases totaling approximately 46,000 gross
acres and 193 mineral servitudes totaling approximately 20,400 gross acres.
Since 1992, the Company has completed eight additional acquisitions of producing
properties in the region totaling $6.5 million and has undertaken an active
program of additional development and exploration in the ArkLaTex area. The
ArkLaTex area accounted for 27% of the Company's estimated net proved reserves
as of December 31, 1996 or 8.5 MMBOE (58% proved developed and 87% gas).
Activity in the Company's Shreveport office has increased substantially from
participation in six wells during 1995 to participation in 22 wells and six
workovers and recompletions during 1996, including eleven Company-operated
wells. The Company's 1997 capital budget provides for approximately $7.5 million
for ongoing development, including continuation of a significant
Company-operated development program at its Box Church Field in east Texas. In
1994 and 1995 the Company extended the Bayou D'Arbonne Field in Union Parish,
Louisiana with a total of six successful wells in the Cotton Valley Sand
formation. In addition, following the Company's discovery in 1995 at the
Haynesville Field in Clairborne Parish, Louisiana, St. Mary drilled three
successful offset wells in the Haynesville sands during 1996. Three additional
wells are planned at Haynesville in 1997.
-7-
Box Church Field. The Company and its partner acquired the Box Church Field
(approximately 2,112 gross acres) in Limestone County, Texas in four separate
transactions during 1995 and 1996. The Company's net acquisition cost totaled
$2.6 million, and the Company operates and holds an average 58% working interest
in three units comprising this field. At the time of the acquisition of the Box
Church Field, production was from the Smackover formation at depths below 10,000
feet. Since acquiring this field, St. Mary has increased production from the
Smackover formation from approximately 2.5 MMcf per day to over 5.0 MMcf per day
in December 1996.
During 1996, the Company made a significant exploration discovery in the
Box Church Field in the Upper and Lower Travis Peak (approximately 7,500 feet)
and Cotton Valley formations (approximately 9,000 feet). The discovery well
encountered 200 feet of pay in the Upper and Lower Travis Peak formations. The
well was completed in the Cotton Valley formation with multiple behind pipe
zones in the Travis Peak formations. During 1996, the Company drilled five
development wells, of which four were completed in the Cotton Valley formation
and the fifth well is currently undergoing completion in the Travis Peak
formation. In addition, the Company re-completed a previously drilled well in
the Cotton Valley formation and is currently drilling a fifth Cotton Valley
well. This exploration and development program in 1996 resulted in the addition
of 26.4 Bcf of estimated net proved reserves as of December 31, 1996,
approximately 73% of which are classified as proved undeveloped. Average daily
gross production during December 1996 for the Cotton Valley and Travis Peak
wells was over 16 MMcf per day. During 1997 and 1998, the Company plans to drill
seven Cotton Valley and five Travis Peak wells to fully develop this field. The
Company has arranged a commitment for a drilling rig throughout 1997 and expects
to drill approximately one well per month at an anticipated completed per well
cost of $850,000.
South Louisiana Region. The Company's operations in south Louisiana include
its royalty interests in St. Mary Parish and a number of large-target prospects
located both on its fee lands and in separate prospect areas in south Louisiana.
The south Louisiana region accounted for 5% of the Company's estimated net
proved reserves as of December 31, 1996 or 1.5 MMBOE (100% proved developed, 84%
gas).
Fee Lands. The Company owns approximately 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, which
established the Horseshoe Bayou Field, cumulative oil and gas revenues,
primarily landowner's royalties, to the Company from its south Louisiana
properties have exceeded $200 million. St. Mary owns royalty interests on these
lands, including production from the Bayou Sale, Horseshoe Bayou and Belle Isle
Fields on its fee lands. Approximately 15,500 acres are leased or subject to
lease options and 9,400 acres are presently unleased. The Company's principal
lessees are Texaco, Vastar and Oryx. Since 1994, several factors have
contributed to renewed development and exploration activity on the Company's fee
lands. In 1991 the Company's lessees conducted two separate 3-D seismic surveys
over portions of the Company's fee properties. Subsequent interpretation of this
data by the lessees has contributed to expanded drilling activity in 1995 and
1996 on the Company's fee lands, including successful completion of seven new
wells, 31 recompletions and 18 workovers during this two year period. In
addition, during the same time period, St. Mary undertook an independent
geological and engineering review of its fee properties and developed a
-8-
comprehensive technical data base. Based on this study the Company has
encouraged development by its lessees, facilitated the development of new
prospects on acreage not held by production and stimulated exploration interest
in deeper, untested horizons. These expanded activities, particularly at the
Belle Isle Field, have together largely offset the natural decline rate of the
existing production on the Company's fee lands during the past several years
with net production increasing by 16% in 1996. The Company's fee properties
currently have gross production of over 60 MMcf per day and 2.9 MBbls per day
and contributed approximately $8.6 million, or 15%, of St. Mary's gross revenues
in 1996. St. Mary's independent engineering studies have identified over 70
prospective zones of behind pipe reserves in existing wells on its fee lands.
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, including two deep gas prospects which are located on
the Company's fee lands and are scheduled to be tested during 1997. The Company
believes that a successful deep test on its fee lands, in addition to adding
potentially significant reserves to the Company, would likely encourage
exploration activity on its fee lands in the largely untested horizons below
15,000 feet.
South Horseshoe Bayou Prospect. The South Horseshoe Bayou prospect is
located on St. Mary's fee lands in St. Mary Parish and is the first of three
significant deep gas tests in the region scheduled for 1997. St. Mary holds an
approximate 22.0% royalty interest and a 25.0% working interest, resulting in an
approximate 40% net revenue interest in this 3-D seismic-defined test of the Rob
and Operc sands at depths between 17,000 and 19,000 feet. On February 18, 1997
the Company announced that the South Horseshoe Bayou discovery had reached total
depth of 19,000 feet, had been completed in the uppermost pay zone below 17,300
feet and was testing directly into the sales line. In initial production tests
the well was producing 20 MMcf and 200 Bbls of condensate per day. See
"Large-Target Exploration Projects."
Mustang Sale Prospect. St. Mary holds an approximate 12.5% royalty interest
in the Mustang Sale prospect which is also located on the Company's south
Louisiana fee lands. This 3-D seismic-defined prospect was spud in February 1997
and is scheduled to test two Rob C sands on an untested fault block at a depth
of approximately 16,000 feet. See "Large-Target Exploration Projects."
Roanoke Prospect. St. Mary and its partners control approximately 8,800
gross acres at the Roanoke Prospect in Jefferson Davis Parish through a
combination of seismic permits, options and leases. The Roanoke Field,
originally discovered in 1934, has produced over 25 MMBbls of oil and 100 Bcf of
gas and is considered by the Company to be an excellent candidate for
re-evaluation using modern 3-D seismic imaging. The Company holds a 33.3%
working interest in the prospect and is targeting potential by-passed pays and
untested fault blocks in this mature, complexly faulted salt dome field. In late
1995 the Company conducted a 31 square mile 3-D seismic survey and completed
processing and interpretation of the seismic data during 1996. The first
prospect was spud in January 1997 and current drilling indicates there are
multiple pays, including the Frio and Hackberry sands, on an untested fault
block. See "Large-Target Exploration Projects."
Patterson Prospect. The Company's Patterson prospect is located to the
north of the Company's fee lands in St. Mary Parish. St. Mary holds a 25.0%
working interest in leases and options totaling approximately 5,000 acres in the
prospect area which lies within a major east-west producing trend between the
Garden City and Patterson Fields. In 1995 the Company and its partners drilled
an unsuccessful 19,000 foot test based on 2-D seismic data and existing well
control. St. Mary and its partners believe that the prospect area remains
prospective in several lower Miocene zones, including the Marg and Siph Davisi
formations, and the group will participate in a 20 square mile 3-D seismic
survey in early 1997 to further delineate this prospect. See "Large-Target
Exploration Projects."
Atchafalaya Bay Prospect. The Company (40% working interest) and a partner
were recently awarded seven tracts (2,845 gross acres) in a Louisiana state
lease sale. This is a 3-D seismic play approximately one mile south of the
Company's South Horseshoe Bayou discovery. One well is expected to be spud
before the end of 1997. See "Large-Target Exploration Projects."
-9-
Williston Basin Region. The Company's operations in the Williston Basin are
conducted through Panterra which was formed in June 1991. The Company holds a
74% general partnership interest in Panterra and the managing partner, Nance
Petroleum Corporation ("Nance Petroleum"), owns a 26% interest. Nance
Petroleum's principal activity is the management of Panterra's interest in the
Williston Basin. All of St. Mary's and Nance Petroleum's activities in the
Williston Basin are conducted through Panterra, which currently owns interests
in 360 producing wells, including 60 Panterra-operated wells located in 60
fields within the basin's core producing area.
The Williston Basin region accounted for 20% of the Company's estimated net
proved reserves as of December 31, 1996 or 6.3 MMBOE (93% proved developed and
90% oil). Since 1991 the Company's investment in Panterra has included
participation in 11 Panterra-operated development and exploration wells with a
100% success rate. St. Mary has budgeted approximately $6 million as its share
of Panterra's 1997 development and exploration program which includes five
Panterra-operated wells.
The Company's exploration and development activities in the Williston Basin
have focused on the application of 3-D seismic data to delineate structural and
stratigraphic features which were not previously discernible using conventional
2-D seismic. In 1994 the Company conducted a 4.5 square-mile 3-D seismic survey
at the North Bainville Field in Roosevelt County, Montana. This survey led to
the successful 1995 extension to the field in the Red River formation. During
1996 the Company completed an additional four wells at North Bainville and
completed an additional 21 square mile 3-D seismic survey. Panterra has
increased gross production at North Bainville from approximately 330 Bbls per
day in 1991 to over 2,000 Bbls per day at the end of 1996. Three additional
wells are planned in the North Bainville area in 1997.
The Company has begun to apply the experience gained at North Bainville to
several other fields in the Williston Basin where the Company holds significant
leasehold interests. In late 1995 and 1996 3-D seismic surveys were conducted
over the Brush Lake and Nameless Fields in Sheridan County, Montana and McKenzie
County, North Dakota respectively. During 1996 the Company completed two
successful Red River tests at Brush Lake. Two additional wells are planned at
the Brush Lake and Nameless fields in 1997.
Permian Basin Region. The Permian Basin of New Mexico and west Texas is the
Company's newest area of concentration. 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 Company established a presence in the basin
in 1995 through the acquisition of a 21.2% working interest in a top lease in
Ward and Winkler Counties, Texas which is believed to have significant deep
exploration potential in the virtually untested deeper formations on the 30,450
acre lease. The Company expanded its holdings in the basin during 1996 with the
acquisition of a 90% interest in the producing properties of Siete Oil & Gas
Corporation for $10.0 million. The Permian Basin region accounted for 12% of the
Company's estimated net proved reserves as of December 31, 1996 or 3.7 MMBOE
(96% proved developed and 81% oil).
Ward Estes. The Company acquired a 21.2% interest in the top lease in the
Ward Estes North Field in Ward County, Texas for $1.7 million in 1995. The top
lease covers 30,450 contiguous acres and becomes effective in August 2000 when
the existing base lease expires. Rights to all remaining production from the
leasehold will transfer to St. Mary and its partners in August 2000. Wells
covered by the base lease currently produce in excess of 4.0 MBbls per day from
relatively shallow formations and are expected to have significant remaining
reserves when the base lease expires. Recent engineering studies indicate that
the expanded application of a carbon dioxide flood is economic at current oil
prices. Although the deeper Siluro-Devonian and Ellenburger horizons have
yielded significant production from several large fields in the immediate area,
these deeper formations remain essentially untested on the Ward Estes lease. The
Company believes that the top lease provides it with the unusual combination of
a low-risk acquisition of long-lived oil reserves and a long term, large-target
exploration project. See "Large- Target Exploration Projects."
-10-
Siete Properties. In 1996 the Company completed the acquisition of a 90%
interest in the oil and gas properties of Siete Oil & Gas Corporation for $10.0
million. The acquisition included approximately 150 wells in southeast New
Mexico and west Texas producing from the Yates/Queen, Delaware and Bone Springs
sands at depths of between 3,500 and 7,500 feet which are operated by the
Company's 10% partner. The acquired reserves are approximately 80% oil and have
a reserve life of approximately 15 years. During the balance of 1996 the Company
completed a series of follow-on acquisitions of smaller interests in the Siete
properties which totaled $1.5 million.
Large-Target Exploration Projects. The Company invests approximately 10% to
15% of its annual capital budget in longer-term, high-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
each have the potential to materially increase the Company's reserves. The
Company's strategy is to maintain a pipeline of five to seven of these high-risk
prospects and to test one or more targets each year, while furthering the
development of early-stage projects and continuing the evaluation of potential
new exploration prospects.
The Company generally 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 wherever
appropriate to apply the latest technology, including 3-D seismic imaging, in
its prospect development and evaluation so as 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.
-11-
The following table summarizes the Company's active large-target
exploration projects. See also "Properties."
St. Mary St. Mary Expected
Working Royalty Drilling
Project Name Objective Location Interest(1) Interest(2) Date(3)
- ------------ --------- -------- ----------- ----------- -------
South Horseshoe completed
Bayou Rob, Operc, 19,000' St. Mary Parish, LA 25.0% 22.0% Feb 1997
Mustang Sale Rob, 16,000' St. Mary Parish, LA - 12.5% early 1997
Atchafalaya Bay Rob, Operc, 19,000' Atchafalaya Bay, LA 40.0% _ mid 1997
Roanoke(4) Frio, Hackberry Jefferson Davis Parish, LA 33.3% _ early 1997
Red Branch(4) Oil Creek/Penn Grayson & Cooke 34.1% _ 1997-1998
Counties, TX
Patterson(4) Marg, Siph Davisi St. Mary Parish, LA 25.0% _ 1998
Carrier(4) Cotton Valley Reef Leon County, TX 24.0% _ 1998-1999
Ward Estes(4) Siluro-Devonian Ward & Winkler 21.2% _ 2000
and Ellenburger Counties, TX
- -----------
(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 Drilling Date means the period during which the Company
anticipates the commencement of drilling and/or testing of an exploratory
well.
(4) The Company may seek the participation of additional industry partners
during the development of a project and accordingly may incur dilution of
its working and net revenue interests.
International Operations
The Company, through subsidiaries, has interests in Russia, Trinidad and
Tobago and Canada. Substantially all of the Company's international proved
reserves are in Russia.
Russian Joint Venture. Until recently, Chelsea Corporation ("Chelsea"), a
wholly-owned, second tier subsidiary of the Company, owned a 36% interest in the
Anderman/Smith International - Chernogorskoye Partnership which owns a 50%
interest in a venture developing the Chernogorskoye oil field in western Siberia
(the "Russian joint venture"). On December 16, 1996, the Company executed an
Acquisition Agreement to sell its Russian joint venture to UPC. Closing of the
transaction occurred on February 12, 1997. In accordance with the terms of the
Acquisition Agreement, Chelsea received cash consideration of approximately $5.2
million, approximately $1.7 million of UPC common stock and a receivable in a
form equivalent to a retained production payment of approximately $10.3 million
plus interest at 10% per annum from the limited liability company formed to hold
the Russian joint venture. Chelsea's receivable is collateralized by the
partnership interest sold. Chelsea has the right, subject to certain conditions,
to require UPC to purchase Chelsea's receivable from the net proceeds of an
initial public offering of UPC common stock or alternatively, Chelsea may elect
to convert all or a portion of its receivable into UPC common stock immediately
prior to an initial public offering of UPC common stock.
Trinidad and Tobago. The Company has entered into an agreement with Conwest
Exploration Inc. covering the Company's 281,506 acre onshore exploration and
production license in the Caroni Basin, Trinidad and Tobago. The agreement
provides that Conwest will pay 100% of the Company's 18.675% commitment to the
phase I and optional phase II work programs under the license agreement. The
total commitments under the license include 275 km. of 2-D seismic and
simultaneous gravity data in phase I, and an additional 100 km. of 2-D seismic
and the drilling of two exploratory wells in phase II.
The agreement provides for cash payments of $150,000 in 1995 upon signing,
$112,500 in February 1996, and $95,700 in February 1997. The Company's interest
in the project at the conclusion of the phase II commitments will be 7.47%.
-12-
Key Relationships
The Company has historically cultivated strategic partnerships with
independent oil and gas operators having specialized experience and 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 in which St.
Mary holds a 74% general partnership interest. The managing partner of Panterra
is Nance Petroleum Corporation, 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 which 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 which generally
attract less competition and where the Company's technical expertise, financial
flexibility and structuring experience affords a competitive advantage. The
Company seeks acquisitions that offer additional development and exploration
opportunities such as its series of acquisitions in the Box Church Field of east
Texas during 1995 and 1996. During each of the three years ending December 31,
1996, the Company engaged in a number of acquisition transactions. During 1994,
the Company completed four acquisitions totaling $12.4 million. During 1995 and
1996, the Company purchased six parcels for $8.1 million and eleven parcels for
$20.9 million, respectively. The Company has budgeted $15.0 million in 1997 for
property acquisitions.
Reserves
At December 31, 1996, Ryder Scott, independent petroleum engineers,
evaluated properties representing approximately 81.5% of 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.
-13-
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, 1996, as prepared by Ryder Scott and
by the Company.
As of December 31,
------------------
1996 1995 1994
---- ---- ----
Reserve Data: (1)
Oil (MBbls)........................ 10,691 7,509 6,667
Gas (MMcf)......................... 127,057 75,705 62,515
MBOE............................... 31,867 20,127 17,096
PV-10 value (in thousands)......... $296,461 $120,192 $84,688
Proved developed reserves.......... 84% 89% 93%
Production replacement............. 422% 203% 207%
Reserve life (years)............... 8.4 6.5 5.6
- -----------
(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."
Production
The following table summarizes the average net daily volumes of oil and gas
produced from properties in which the Company held an interest during the
periods indicated.
Year Ended December 31,
-----------------------
1996 1995 1994
---- ---- ----
Operating Data: (1)
Net production:
Oil (MBbls).............................. 1,186 1,044 937
Gas (MMcf)............................... 15,563 12,434 12,577
MBOE..................................... 3,780 3,116 3,033
Average net daily production:
Oil (Bbls)............................... 3,240 2,852 2,567
Gas (Mcf)................................ 42,522 33,973 34,458
BOE...................................... 10,327 8,514 8,310
Average sales price: (2)
Oil (per Bbl)............................ $18.64 $16.37 $14.95
Gas (per Mcf)............................ $ 2.23 $1.56 $1.93
Additional per BOE data:
Lease operating expense.................. $2.28 $2.49 $2.54
Production taxes......................... $1.13 $0.93 $0.92
- -----------
(1) Excludes operating data attributable to the Company's Russian joint
venture.
(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 with financial counterparties, to
manage its exposure to fluctuations in commodity prices. The Company also
employs limited use of exchange-listed financial futures and options as part of
its hedging program for crude oil.
-14-
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,
1996. Productive wells are either producing wells or wells capable of commercial
production although currently shut in. One or more completions in the same bore
hole 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.
Domestic International Total
--------------- ------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Oil 529 136 34 6 563 142
Gas 884 105 - - 884 105
----- --- --- -- ----- ---
Total 1,413 241 34 6 1,447 247
===== === === == ===== ===
Drilling Activity
The following table sets forth the wells in which the Company participated
during each of the three years indicated.
Year Ended December 31,
-----------------------
1996 1995 1994
-------------- -------------- --------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Domestic:
Development:
Oil.............................. 17 3.91 6 1.52 4 1.07
Gas.............................. 74 13.29 38 7.75 30 4.91
Non-productive................... 11 2.70 6 2.00 3 0.33
--- ----- -- ----- -- -----
Total........................ 102 19.90 50 11.27 37 6.31
=== ===== == ===== == =====
Exploratory:
Oil.............................. - - 5 1.56 1 0.25
Gas.............................. 5 1.25 8 0.74 14 2.26
Non-productive................... 10 3.10 16 4.19 19 3.82
--- ----- -- ----- -- ----
Total........................ 15 4.35 29 6.49 34 6.33
=== ===== == ===== == =====
Farmout or non-consent 9 - 4 - 7 -
=== ===== == ===== == =====
International:
Development:
Oil.............................. 22 3.96 5 0.90 13 1.28
Gas.............................. - - 1 0.06 2 0.07
Non-productive................... - - - - 2 0.02
--- ----- -- ----- -- -----
Total........................ 22 3.96 6 0.96 17 1.37
=== ===== == ===== == =====
Exploratory:
Oil.............................. - - - - - -
Gas.............................. - - - - 1 0.05
Non-productive................... - - - - 1 0.09
--- ----- -- ----- -- -----
Total........................ - - - - 2 0.14
=== ===== == ===== == =====
Farmout or non-consent - - - - - -
=== ===== == ===== == =====
Grand Total(1) ................... 148 28.21 89 18.72 97 14.15
=== ===== == ===== == =====
- ----------
(1) Does not include 6, 4 and 3 gross wells completed on the Company's fee
lands during 1994, 1995 and 1996, respectively.
-15-
All of the Company's drilling activities are conducted on a contract basis
with independent drilling contractors. The Company owns no drilling equipment.
Domestic and International Acreage
The following table sets forth the gross and net acres of developed and
undeveloped domestic oil and gas leases, fee properties, mineral servitudes and
lease options held by the Company as of December 31, 1996. Undeveloped acreage
includes leasehold interests which may already have been classified as
containing proved undeveloped reserves.
Developed Acreage Undeveloped
Acreage (1) Acreage (2) Total
------------------- ------------------- -------------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
Domestic:
Arkansas............................... 4,274 585 167 40 4,441 625
Louisiana.............................. 28,098 7,612 9,210 1,530 37,308 9,142
Montana................................ 11,299 7,341 26,009 20,571 37,308 27,912
New Mexico............................. 3,960 1,038 4,160 1,340 8,120 2,378
North Dakota........................... 27,627 11,129 57,561 20,349 85,188 31,478
Oklahoma............................... 109,476 19,773 53,179 13,402 162,655 33,175
Texas.................................. 49,745 9,672 56,050 10,003 105,795 19,675
Other.................................. 16,814 5,483 147,414 59,063 164,228 64,546
------- ------- ------- ------- ------- -------
Subtotal........................... 251,293 62,633 353,750 126,298 605,043 188,931
------- ------- ------- ------- ------- -------
Louisiana Fee Properties............... 12,735 12,735 12,179 12,179 24,914 24,914
Louisiana Mineral Servitudes........... 10,584 5,822 5,511 5,191 16,095 11,013
Louisiana Lease Options................ - - 5,852 1,951 5,852 1,951
------- ------- ------- ------- ------- -------
Subtotal........................... 23,319 18,557 23,542 19,321 46,861 37,878
------- ------- ------- ------- ------- -------
Total.............................. 274,612 81,190 377,292 145,619 651,904 226,809
------- ------- ------- ------- ------- -------
International (3)
Canada................................. 6,400 281 32,640 1,131 39,040 1,412
Trinidad and Tobago.................... - - 281,506 21,029 281,506 21,029
------- ------- ------- ------- ------- -------
Total.............................. 6,400 281 314,146 22,160 320,546 22,441
------- ------- ------- ------- ------- -------
Grand Total............................. 281,012 81,471 691,438 167,779 972,450 249,250
======= ======= ======= ======= ======= =======
- -----------
(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) Excludes 46,373 gross acres and 8,347 net acres in the Russian Republic.
Effective February 12, 1997, the Company sold its Russian joint venture.
See "International Operations."
Non-Oil and Gas Activities
Summo Minerals. Through December 31, 1996, St. Mary Minerals Inc. ("St.
Mary Minerals"), a wholly-owned subsidiary of the Company, has invested a total
of approximately $5.6 million and has acquired a total of 9,644,093 common
shares of Summo Minerals Corporation ("Summo Minerals") representing 49% of the
issued and outstanding common shares and 6,261,000 warrants to purchase common
shares, exercisable at prices between Cdn $1.10 and Cdn $1.21 and which expire
between October 17, 1997 and October 17, 1998. Summo Minerals is a
development-stage, publicly-traded Canadian based mining company engaged in the
development of medium-sized copper deposits in the United States and its common
shares are listed on the Toronto and the Vancouver stock exchanges under the
symbol "SMA". The Company's investment in Summo Minerals had a market value of
$8.4 million at December 31, 1996.
-16-
Summo Minerals' recent activities have focused on the development of its
Lisbon Valley property comprised of approximately 5,940 acres of unpatented
mining claims and mineral leases located approximately 45 miles southeast of
Moab, Utah in San Juan County. Summo Minerals is in the development stage and
plans to raise funds to commence operations through debt and equity financings
in 1997. The Company currently expects to invest no more than $2.0 million in
1997 in Summo Minerals. It is possible that the Company may elect to exercise
some or all of its warrants in order to ultimately realize the amount of any
appreciation in the value of the warrants. The Company currently intends to
exercise such warrants if the common share price is substantially in excess of
the warrant price. The total cash payment in connection with such exercise would
be approximately $3.1 million. There can be no assurance that the Company will
realize a return on its investment in Summo Minerals.
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 and development 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
Substantially all of the Company's oil and gas production is sold on the
spot market. During 1996, sales to an individual customer constituted 17.3% of
total revenues. There were no oil and gas customers of the Company that
represented more than 10% of its oil and gas revenues in 1995 or 1994.
Government Regulations
The Company's business is subject to various federal, state and local laws
and governmental regulations which 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, the payment of which 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.
-17-
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. For instance, legislation has been introduced
in Congress that would reclassify certain exploration and production wastes as
"hazardous wastes" which would make the reclassified wastes subject to much more
stringent handling, disposal and clean-up requirements. If such legislation were
enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. Initiatives to further
regulate the disposal of oil and gas wastes are also pending in certain states,
and these various initiatives could have a similar impact on the Company.
Title to Properties
Substantially all of the Company's domestic 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. Substantially all of the Company's oil and gas properties are and
will continue to be mortgaged to secure borrowings under the Company's credit
facilities. The Company performs only a minimal title investigation before
acquiring undeveloped properties.
The Company relies upon sovereign ownership of rights granted under license
or concession agreements by foreign governments and conducts no independent
title investigation. Concession negotiations generally are undertaken through
local legal counsel to ensure compliance with local laws. In the event the
Company acquires previously granted rights to explore for, develop or produce
oil or gas in a foreign country, it generally relies on local legal counsel for
the title work.
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 of which 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 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 effect 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.
-18-
Employees and Office Space
As of December 31, 1996, the Company had 96 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 offices, of which 7,200 square feet is subleased, approximately
12,200 square feet of office space in Tulsa, Oklahoma, approximately 7,300
square feet of office space in Shreveport, Louisiana and approximately 500
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.
Behind pipe reserves. Estimated net proved reserves in a formation in which
production casing has already been set in the wellbore but has not been
perforated and production tested.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
of six Mcf of gas (including gas liquids) to one Bbl of oil.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
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.
-19-
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.
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.
MMcf. One million cubic feet.
MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
required to raise the temperature of a one-pound mass of water one degree
Fahrenheit.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
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. Reserve Life, expressed in years, represents the estimated net
proved reserves at a specified date divided by actual production for the
trailing 12-month period.
-20-
Royalty. That 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
a share 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 which 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
While the Company has been named as a defendant in certain lawsuits arising
in the ordinary course of business, 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 1996.
-21-
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY
HOLDERS MATTERS
Market Information. The Company's common stock is traded on the Nasdaq
National Market System under the symbol MARY. The stock began trading December
16, 1992; no market for the stock existed before that date. The range of high
and low bid prices for the quarterly periods in 1995 and 1996, as reported by
the Nasdaq National Market System, is set forth below:
Quarter Ended High Low
------------- ---- ---
March 31, 1995 $14.000 $12.500
June 30, 1995 13.625 10.875
September 30, 1995 14.875 12.875
December 31, 1995 15.000 13.250
March 31,1996 16.625 13.500
June 30, 1996 17.875 15.875
September 30, 1996 17.000 14.250
December 31, 1996 27.375 16.500
On March 21, 1997 the closing sale price for the Company's common stock was
$25.125 per share.
Holders. As of March 21, 1997, the number of record holders of the
Company's common stock was 155. Management believes, after inquiry, that the
number of beneficial owners of the Company's common stock is in excess of 1,100.
Dividends. The Company has paid cash dividends in each of the last 58
consecutive calendar years. Annual dividends of $0.16 per share have been paid
quarterly in each of the years 1987 through 1996. These dividends totaled
approximately $1,171,000 for the years 1987 through 1992 and $1,402,000 in each
of the years 1993 through 1995 and $1,401,000 in 1996. The Company's line of
credit agreement with NationsBank and Norwest Bank limits cumulative dividends
from December 31, 1992 forward to $3,000,000 plus cumulative net income from
December 31, 1991, which totals $38,128,000 at December 31, 1996. The Company
increased its quarterly dividend 25% to $.05 per share effective with the
quarterly dividend declared in January 1997 and payable February 1997.
-22-
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, 1996, were derived from the Consolidated
Financial Statements of the Company which have been audited by Coopers & Lybrand
L.L.P., independent accountants. 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.
Year Ended December 31,
---------------------------------------------------
1996 1995 1994 1993 1992
------- ------- ------- ------- -------
(In thousands, except per share data)
Income Statement Data:
Operating revenues:
Oil production.............................. $22,100 $17,090 $14,006 $13,685 $11,949
Gas production.............................. 34,674 19,479 24,233 24,523 23,296
Gas contract settlements and other.......... 2,777 2,081 6,546 424 15,413
------- ------- ------- ------- -------
Total operating revenues..................... 59,551 38,650 44,785 38,632 50,658
------- ------- ------- ------- -------
Operating expenses:
Oil and gas production...................... 12,897 10,646 10,496 9,341 7,793
Depletion, depreciation and amortization.... 12,732 10,227 10,134 8,775 6,213
Impairment of proved properties............. 408 2,676 4,219 3,498 1,565
Exploration................................. 8,185 5,073 8,104 5,457 3,615
Abandonment and impairment of unproved
properties.............................. 1,469 2,359 1,023 1,020 1,264
General and administrative.................. 7,603 5,328 5,261 4,712 4,544
Gas contract disputes and other............. 78 152 493 638 1,332
(Income) loss in equity investees........... (1,272) 579 348 659 1,026
------- ------- ------- ------- -------
Total operating expenses..................... 42,100 37,040 40,078 34,100 27,352
------- ------- ------- ------- -------
Income from operations....................... 17,451 1,610 4,707 4,532 23,306
Non-operating expense........................ 1,951 896 525 62 791
Income tax expense (benefit)................. 5,333 (723) 445 1,065 7,328
------- ------- ------- ------- -------
Income from continuing operations............ 10,167 1,437 3,737 3,405 15,187
Gain on sale of discontinued operations,
net of income taxes........................ 159 306 - - 430
Income before cumulative effect of change
in accounting principle.................... 10,326 1,743 3,737 3,405 15,617
Cumulative effect of change in accounting
principle.................................. - - - 300 -
------- ------- ------- ------- -------
Net income................................... $10,326 $1,743 $3,737 $3,705 $15,617
======= ======= ======= ======= =======
Net income per common share:
Income from continuing operations........... $1.16 $0.17 $0.43 $0.39 $2.10
Gain on sale of discontinued operations..... 0.02 0.03 - - 0.06
Cumulative effect of change in accounting
principle............................... - - - 0.03 -
------- ------- ------- ------- -------
Net income per share......................... $1.18 $0.20 $0.43 $0.42 $2.16
======= ======= ======= ======= =======
Cash dividends per share..................... $0.16 $0.16 $0.16 $0.16 $0.16
Weighted average common shares outstanding 8,759 8,760 8,763 8,763 7,233
-23-
Year Ended December 31,
----------------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
(In thousands, except per share data)
Other Data:
EBITDA (1)................................. $ 30,183 $11,837 $14,841 $13,307 $29,519
Net cash provided by operating activities.. 24,205 17,713 20,271 19,675 26,989
Capital and exploration expenditures....... 52,601 32,307 31,811 23,434 20,645
Balance Sheet Data (end of period):
Working capital............................ $ 13,926 $ 3,102 $ 9,444 $15,187 $17,913
Net property and equipment................. 101,510 71,645 59,655 51,381 46,998
Total assets............................... 144,271 96,126 89,392 81,797 75,896
Long-term debt............................. 43,589 19,602 11,130 7,400 5,000
Total stockholders' equity................. 75,160 66,282 66,034 63,635 61,362
- -----------
(1) EBITDA is defined as income before interest, income taxes, depreciation,
depletion and amortization. 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.
-24-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Overview
St. Mary was founded in 1908 and incorporated in Delaware in 1915. Since
1992 St. Mary has expanded its technical and operating staff and increased its
drilling, production and operating capabilities in its five core operating areas
in the United States.
The Company's activities in the Williston Basin are conducted through
Panterra Petroleum ("Panterra") in which the Company owns a 74% general
partnership interest. The Company proportionally consolidates its interest in
Panterra.
The Company has two principal equity investments, Summo Minerals, a
Canadian copper mining company, and, until recently, its Russian joint venture.
The Company accounts for its Russian joint venture and investment in Summo
Minerals under the equity method and includes its share of the income or loss
from these entities. Effective February 12, 1997, the Company sold its Russian
joint venture.
The Company receives significant royalty income from its Louisiana fee
lands. Revenues from the fee lands were $8.1, $5.5 and $6.3 million for the
years 1996, 1995 and 1994, respectively. Management expects the Company's
royalty income to increase significantly in 1997 with the completion of the St.
Mary Land & Exploration No. 2 well at South Horseshoe Bayou in February 1997.
This well is flowing in excess of 25 million cubic feet of gas per day. The
Company owns a 25% working interest and 22% royalty interest in this well for a
combined net revenue interest of approximately 40%. The south Louisiana reserves
tend to decline rapidly, therefore management anticipates lower revenue from the
Louisiana fee lands in future years unless further exploration and development
activity continues to offset the normal production decline of producing
properties. The Company has been notified of several geologic objectives the
lessees intend to test in 1997 based on 3-D seismic surveys.
The 1996 results of operations include several significant acquisitions
made during the past few years. The Company purchased an additional interest
from a Panterra partner at year-end 1994 increasing its ownership in Panterra to
74%. In December 1995, the Company acquired two different interests in the Box
Church Field located in Texas for $2.2 million and several additional interests
in 1996 for $580,000. The Company drilled and completed three wells in this
field in 1996 which proved the upside potential the Company had identified and
added 26.4 billion cubic feet of net gas reserves. The Company plans to drill an
additional 13 wells to develop this field in 1997 and 1998. The Company
purchased a 90% interest in the producing properties of Siete Oil & Gas
Corporation for $10.0 million in June 1996 and completed a series of follow-on
acquisitions of smaller interests in the Siete properties totaling $1.5 million.
These properties are located in the Permian Basin of New Mexico and west Texas.
In October 1996, the Company acquired additional interests from Sonat
Exploration Company in its Elk City Field located in Oklahoma for $6.1 million.
Several smaller acquisitions were also completed during 1996 totaling $2.8
million.
The Company entered into several long-term take-or-pay gas sales contracts
in the late 1970s and early 1980s at prices substantially above current market
prices. When the purchasers failed to take the volumes required by the contracts
and began paying lower market prices, the Company commenced legal proceedings
against the purchasers. The Company settled these claims out of court, receiving
lump-sum payments as compensation for all prior claims and remaining contract
values. The Company has no future obligation to deliver gas to these purchasers.
The Company settled the last remaining disputes in 1994 for $5.7 million. As a
result of the purchasers' failure to take the required gas, the Company was
underproduced approximately 1.6 and 1.9 BCF relative to other working interest
owners at December 31, 1996 and 1995, respectively. With all disputes now
settled, the Company is selling additional gas and beginning to reduce this
imbalance.
-25-
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 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 12% of
its estimated 1997 gas production at an average fixed NYMEX equivalent price of
$2.12 per MMBtu and approximately 14% of its estimated 1997 oil production at an
average fixed NYMEX price of $18.37 per Bbl. The Company has also purchased
options resulting in price collars and price floors on approximately 16% of the
Company's estimated 1997 oil production with price ceilings between $21 and $27
per Bbl and price floors between $18 and $21 per Bbl.
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 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.
-26-
Results of Operations
The following table sets forth selected operating data for the periods and upon
the basis indicated:
Year Ended December 31,
-------------------------------
1996 1995 1994
------- ------- -------
(In thousands, except BOE data)
Oil and gas production revenues:
Working interests.................................. $48,685 $31,055 $31,896
Louisiana royalties................................ 8,089 5,514 6,343
------- ------- -------
Total........................................... $56,774 $36,569 $38,239
======= ======= =======
Net Production:
Oil (MBbls)........................................ 1,186 1,044 937
Gas (MMcf)......................................... 15,563 12,434 12,577
------- ------- -------
MBOE............................................... 3,780 3,116 3,033
======= ======= =======
Average sales price(1):
Oil (per Bbl)...................................... $ 18.64 $ 16.37 $ 14.95
Gas (per Mcf)...................................... $ 2.23 $ 1.56 $ 1.93
Oil and gas production costs:
Lease operating expenses........................... $ 8,615 $ 7,747 $ 7,713
Production taxes................................... 4,282 2,899 2,783
------- ------- -------
Total........................................... $12,897 $10,646 $10,496
======= ======= =======
Additional per BOE data:
Sales price........................................ $ 15.02 $ 11.74 $ 12.61
Lease operating expenses........................... 2.28 2.49 2.54
Production taxes................................... 1.13 .93 .92
------- ------- -------
Gross operating margin.......................... $ 11.61 $ 8.32 $ 9.15
Depletion, depreciation and amortization........... 3.37 3.28 3.34
Impairment of proved properties.................... .11 .86 1.39
General and administrative......................... 2.01 1.71 1.73
- -----------
(1) Includes the effects of the Company's hedging activities.
Oil and Gas Production Revenues. Oil and gas production revenues increased
$20.2 million, or 55% to $56.8 million in 1996 compared to $36.6 million in
1995. Oil production volumes increased 14% while gas production volumes
increased 25% in 1996 compared to 1995. Average net daily production reached
10.3 MBOE in 1996 compared to 8.5 MBOE in 1995. This production increase
resulted from new properties acquired and drilled during 1995 and 1996. The
average realized oil price for 1996 increased 14% to $18.64 per Bbl, while
realized gas prices increased 43% to $2.23 per Mcf, from their respective 1995
levels. The Company hedged approximately 70% of its oil production for 1996 or
842 MBbls at an average NYMEX price of $18.92. The Company realized a $2.6
million decrease in oil revenue or $2.20 per Bbl for 1996 on these contracts
compared to a $131,000 decrease or $.13 per Bbl in 1995. The Company also hedged
23% of its 1996 gas production or 3,651,000 MMBtu at an average NYMEX price of
$2.00. The Company realized a $1.65 million decrease in gas revenues or $.11 per
Mcf for 1996 from these hedge contracts compared to a $121,000 increase or $.01
per Mcf in 1995.
-27-
Oil and gas production revenues declined $1.7 million, or 4% to $36.6
million in 1995 compared to $38.2 million in 1994 due primarily to lower gas
prices. Oil production volumes increased 11% while gas production volumes
declined 1% in 1995 compared to 1994. Average net daily production reached 8.5
MBOE in 1995 compared to 8.3 MBOE in 1994. This production increase resulted
from new properties acquired and drilled during 1995. The average realized oil
price for 1995 increased 9% to $16.37 per Bbl, while realized gas prices
declined 19% to $1.56 per Mcf, from their respective 1994 levels. The Company
hedged approximately 60% of its oil production for 1995 or 605 MBbls at an
average NYMEX price of $17.66. The Company realized a $131,000 decrease in oil
revenue or $.13 per Bbl for 1995 on these contracts compared to a $67,000
decrease or $.07 per Bbl in 1994. The Company also hedged 6% of its 1995 gas
production or 695,000 MMBtu at an average NYMEX price of $1.89. The Company
realized a $121,000 increase in gas revenues or $.01 per Mcf for 1995 from these
hedge contracts compared to a $51,000 increase in 1994.
Oil and Gas Production Costs. Oil and gas production costs consist of lease
operating expense and production taxes. Total production costs increased $2.3
million, or 21% in 1996 to $12.9 million compared with $10.6 million in 1995.
However, total oil and gas production costs per BOE declined slightly to $3.41
in 1996 compared to $3.42 per BOE in 1995. Oil and gas production costs
increased $150,000, or 1% in 1995 to $10.6 million compared with $10.5 million
in 1994. However, total oil and gas production costs per BOE declined slightly
to $3.42 in 1995 compared to $3.46 per BOE in 1994.
Depreciation, Depletion, Amortization and Impairment. Depreciation,
depletion and amortization expense ("DD&A") increased $2.5 million, or 24% to
$12.7 million in 1996 compared with $10.2 million in 1995. This increase
resulted from new properties acquired and drilled in 1996. DD&A expense per BOE
increased 3% to $3.37 in 1996 compared to $3.28 in 1995. Impairment of proved
oil and gas properties declined $2.3 million or 85% to $408,000 in 1996 compared
with $2.7 million in 1995 because of higher oil and gas prices and better
development drilling results. The 1995 impairment provision included effects of
the adoption of SFAS No. 121 as of October 1, 1995 which resulted in an
additional impairment charge for proved properties of $1.0 million in the fourth
quarter of 1995.
Depreciation, depletion and amortization expense increased slightly to
$10.2 million in 1995 compared with $10.1 million in 1994. However, DD&A expense
per BOE declined 2% to $3.28 in 1995 compared to $3.34 in 1994. Impairment of
proved oil and gas properties declined $1.5 million or 37% to $2.7 million in
1995 compared with $4.2 million in 1994 because high cost marginal wells in
newer fields and low year-end gas prices required further ceiling test
writedowns in 1994. The 1995 impairment provision included effects of the
adoption of SFAS No. 121 as of October 1, 1995 which resulted in an additional
impairment charge for proved properties of $1.0 million in the fourth quarter of
1995.
Abandonment and impairment of unproved properties declined $890,000 or 38%
to $1.5 million in 1996 compared to $2.4 million in 1995 due to the additional
impairments taken during 1995. Abandonment and impairment of unproved properties
increased $1.4 million or 131% to $2.4 million in 1995 compared to $1.0 million
in 1994. The Company recorded an impairment of $1.0 million of leasehold costs
in 1995 as a result of several unsuccessful prospects in its drilling program.
Exploration. Exploration expense increased $3.1 million or 61% to $8.2
million for 1996 compared with $5.1 million in 1995 as a result of higher
exploratory dry hole expense from increased drilling activity and a large 3-D
seismic survey conducted in 1996. Exploration expense decreased $3.0 million or
37% to $5.1 million in 1995 compared to $8.1 million in 1994 due to reduced 1995
geophysical activity and better exploratory drilling results in 1995 compared
with 1994.
General and Administrative. General and administrative expense increased
$2.3 million or 43% to $7.6 million for 1996 compared to $5.3 million in 1995
due to higher compensation costs, professional fees and a $1.3 million increase
in the expense associated with the Company's SAR plan. General and
administrative expenses were unchanged at $5.3 million for 1995 and 1994. Higher
compensation costs were offset by lower professional fees and travel costs.
-28-
Gas contract disputes and other consists of legal expenses in connection
with gas contract disputes and the Company's mining activities. This expense
declined $74,000 to $78,000 in 1996 compared with 1995 because insurance
proceeds were recovered on a previous settlement. This expense declined $341,000
to $152,000 in 1995 compared with 1994 because the mining activities are now
conducted through the Company's equity investee, Summo Minerals Corporation.
Equity in (Income) Loss of Russian Joint Venture. The Company accounts for
this investment under the equity method and includes its share of income or loss
from the venture. The equity in the (income) loss of the Russian joint venture
was $(1.7) million in 1996, $322,000 in 1995 and $328,000 in 1994. The large
increase in 1996 income was due to higher oil production and prices. As
discussed under Outlook, the Company sold this investment in February 1997.
Equity in Loss of Summo Minerals Corporation. The Company accounts for this
investment under the equity method and includes its share of Summo's income or
loss. The equity in the loss of Summo was $457,000 in 1996, $257,000 in 1995 and
$20,000 in 1994 because of higher general and administrative expenses associated
with the expansion of Summo's Denver office. The Company's ownership in Summo
was 49% in 1996, 51% in 1995 and 42% in 1994.
Non-Operating Income and Expense. Net interest and other nonoperating
expense increased $1.1 million to $2.0 million in 1996 compared to $896,000 in
1995 because of additional interest expense associated with higher debt levels.
Net interest and other nonoperating expense increased $371,000 to $896,000 in
1995 compared to $525,000 in 1994 because of the interest expense associated
with higher debt levels and the Company's increased Panterra ownership.
Income Taxes. Income tax expense was $5.3 million in 1996, resulting in an
effective 34% tax rate, compared to a net tax benefit of $723,000 for 1995 which
reflected the utilization of capital loss carryovers and Section 29 tax credits
and income tax expense of $445,000 for 1994. State tax expense was $700,000 in
1996, $396,000 in 1995 and $445,000 in 1994. The 1996 Louisiana taxes increased
significantly as a result of higher Louisiana net income.
Net Income. Net income for 1996 increased $8.6 million or 492% to $10.3
million compared to $1.7 million in 1995 with higher production volumes and
prices resulting in a $20.2 million increase in oil and gas production revenues.
This was partially offset by the associated higher production expenses and DD&A,
a $3.1 million increase in exploration expense and a $2.3 million increase in
general and administrative expenses. The Company also realized a $2.3 million
gain on sale of producing properties in 1996 compared to $1.3 million in 1995
and recorded $1.7 million equity income from its Russian joint venture in 1996
compared to an equity loss of $322,000 in 1995. Net income for 1995 declined
$2.0 million or 54% to $1.7 million compared to $3.7 million in 1994. Lower 1995
natural gas prices and associated revenue were partially offset by reduced
exploration expense and the Company's income tax benefit. The Company also
realized a $306,000 gain from the sale of discontinued real estate in 1995 with
no comparable activity in 1994.
Liquidity and Capital Resources
The Company's primary sources of liquidity are cash provided by operating
activities and borrowings under its credit facility and the Panterra credit
facility. The Company's principal cash needs are for the exploration and
development of oil and gas properties, acquisitions and payment of dividends to
stockholders. 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 37% to $24.2 million in 1996 compared to $17.7 million in 1995. An
$11.0 million increase in 1996 cash received from oil and gas operations was
partially offset by higher exploration expenses, interest expense and income
taxes. The Company's net cash provided by operating activities decreased 13% to
$17.7 million in 1995 compared to $20.3 million in 1994. A $3.2 million decline
in exploration costs for 1995 partially offset the last of the Company's gas
contract disputes settled in 1994 for $5.7 million.
-29-
In the first quarter of 1997, the Company made a cash payment of
approximately $1.6 million in satisfaction of liabilities previously accrued by
the Company under its SAR plan. The Company will not recognize any additional
expense in connection with this payment.
Net cash used in investing activities increased 37% to $45.2 million in
1996 compared with $33.0 million in 1995 primarily due to increased capital
expenditures and acquisition of oil and gas properties partially offset by $3.1
million in cash received as a result of the purchase of the remaining 35%
interest in St. Mary Operating Company and $3.1 million in proceeds from the
sale of oil and gas properties. Total capital expenditures, including
acquisitions of oil and gas properties, in 1996 increased $17.7 million to $48.5
million compared to $30.8 million in 1995 due to increased drilling activity and
$21.0 million of reserve acquisitions compared to $8.1 million spent in 1995.
Net cash used in investing activities increased 43% to $33.0 million in
1995 compared with $23.1 million in 1994 primarily due to increased capital
expenditures, acquisition of oil and gas properties and the investment in Summo
Minerals Corporation, partially offset by $2.3 million in proceeds from the sale
of oil and gas properties. Total capital expenditures, including acquisitions of
oil and gas properties, in 1995 increased to $30.8 million compared to $22
million in 1994 due to increased drilling activity and reserve acquisitions. The
Company invested $4.5 million in Summo Minerals Corporation during 1995
increasing its ownership to 51%.
Net cash provided by financing activities increased $15.6 million to $22.6
million in 1996 compared to $7.0 million in 1995. The Company borrowed funds in
1996 for the expanded capital expenditure programs and reserve acquisitions. Net
cash provided by financing activities was $7 million in 1995 compared to net
cash used by financing activities of $2 million in 1994. The Company borrowed
funds in 1995 for its capital expenditure programs and its mining investment
compared with debt repayment of $578,000 in 1994. The Company paid dividends of
$1.4 million in 1996, 1995 and 1994. The Company increased its quarterly
dividend 25% to $.05 per share effective with the quarterly dividend declared in
January 1997 and payable February 1997.
The Company had $3.3 million in cash and cash equivalents and working
capital of $13.9 million as of December 31, 1996 compared to $1.7 million of
cash and cash equivalents and working capital of $3.1 million at December 31,
1995. This increase resulted from the cash investments received as part of its
St. Mary Operating Company investment, increased oil and gas receivables and
classification of its Russian joint venture as a current asset held for sale.
Credit Facility. On April 1, 1996, the Company amended and restated its
credit facility with two banks to provide a $60.0 million collateralized
three-year revolving loan facility which thereafter converts at the Company's
option to a five-year term loan. The amount which may be borrowed from time to
time will depend upon the value of the Company's oil and gas properties and
other assets. The Company's borrowing base, which is redetermined annually, was
increased from $40 million to $60.0 million in February 1997 based on the
increase in the Company's estimated net proved reserves in 1996. Outstanding
revolving loan balances under the Company's credit facility, which were $33.9
million at December 31, 1996, 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 the banks'
prime rate or LIBOR plus 1/2% when the Company's debt to total capitalization is
less than 30%, up to a maximum of either the banks' prime rate plus 1/8% or
LIBOR plus 1-1/4% when the Company's debt to total capitalization ratio exceeds
50%. The credit facility is collateralized by a mortgage of substantially all of
the Company's domestic oil and gas properties. The credit facility provides for,
among other things, covenants limiting additional recourse indebtedness of the
Company, investments or disposition of assets by the Company and certain
restrictions on the payment of cash dividends to holders of the Company's stock.
-30-
Panterra, in which the Company has a 74% general partnership ownership
interest, has a separate credit facility with a $26.0 million borrowing base and
$13.1 million outstanding as of December 31, 1996. During February 1997,
Panterra agreed to amend the Panterra credit facility to extend the revolving
loan period to March 31, 1999 and the maturity of the credit facility to March
31, 2004. The Company intends to use the available credit under the Panterra
credit facility to fund a portion of its 1997 capital expenditures in the
Williston Basin.
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.
Capital and Exploration Expenditures
------------------------------------
Year Ended December 31,
-----------------------
(In thousands)
1996 1995 1994
------- ------- -------
Development......................... $16,709 $12,625 $ 5,946
Exploration:
Domestic.......................... 11,910 8,746 9,481
International..................... 84 (112) 877
Acquisitions:
Proved............................ 20,957 8,111 12,279
Unproved.......................... 2,941 2,937 3,228
------- ------- -------
Total........................... $52,601 $32,307 $31,811
======= ======= =======
Russian joint venture............... $ 3,881 $ 3,213 $ 1,551
======= ======= =======
The Company's total costs incurred in 1996 increased 63% to $52.6 million
compared to $32.3 million in 1995. Proved property acquisitions increased $12.8
million to $21.0 million in 1996 compared to $8.1 million in 1995. The Company
purchased a 90% interest in the producing properties of Siete Oil & Gas
Corporation for $10.0 million in June 1996 and completed a series of follow-on
acquisitions of smaller interests in the Siete properties which totaled $1.5
million. In October 1996, the Company acquired additional interests from Sonat
in its Elk City Field located in Oklahoma for $6.1 million. Several smaller
acquisitions were also completed during 1996 totaling $3.4 million. The Company
spent $31.6 million in 1996 for unproved property acquisitions and domestic
exploration and development compared to $24.3 million in 1995 as a result of the
Company's expanded drilling programs.
The Company's total costs incurred in 1995 increased 2% to $32.3 million
compared to $31.8 million in 1994. Proved property acquisitions declined $4.2
million to $8.1 million in 1995 compared to $12.3 million in 1994. The Company
completed several proved property acquisitions in the ArkLaTex area totalling
$5.9 million during 1995. In January 1995, the Company acquired a 21% interest
in a top lease on the 30,450 acre Ward Estes Field in Texas for $1.7 million.
Panterra, in which the Company has a 74% ownership, acquired properties from
Adex Resources in 1995 for $547,000. The Company spent $24.3 million in 1995 for
unproved property acquisitions and domestic exploration and development compared
to $18.7 million in 1994 as a result of the Company's expanded drilling
programs.
-31-
Outlook. The Company believes that its existing capital resources, cash
flow from operations and available borrowings are sufficient to meet its
anticipated capital and operating requirements for 1997. The Company closed a
follow-on common stock offering of 2.18 million shares in February 1997, raising
$51.3 million in net proceeds. The proceeds will be used to fund the Company's
exploration, development and acquisition programs, and pending such use will be
used to repay borrowings under its credit facility. As of March 21, 1997, the
Company has repaid all borrowings under its credit facility, and effective April
1, 1997, has reduced the commitment under this facility, until its next
redetermination, to $10 million. The Company has the right to increase this
commitment between redetermination periods.
For 1997, the Company anticipates spending approximately $65.0 million for
capital and exploration expenditures with $43.0 million allocated for domestic
exploration and development, $15.0 million allocated for domestic property
acquisitions and $7.0 million for large-target, high-risk domestic exploration
and development.
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 the success of its development and exploratory
activity which could lead to funding requirements for further development.
The Company, through subsidiaries, owned an 18% interest (the "Russian
joint venture") in a venture which is developing the Chernogorskoye oil field in
western Siberia. On December 16, 1996, the Company executed an Acquisition
Agreement to sell its Russian joint venture to Ural Petroleum Corporation
("UPC"). Closing of the transaction occurred on February 12, 1997. In accordance
with the terms of the Acquisition Agreement, the Company received cash
consideration of approximately $5.2 million before transaction costs,
approximately $1.7 million of UPC common stock and a receivable in a form
equivalent to a retained production payment of approximately $10.3 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 UPC to purchase the Company's receivable from the net
proceeds of an initial public offering of UPC common stock or alternatively, the
Company may elect to convert all or a portion of its receivable into UPC common
stock immediately prior to an initial public offering of UPC common stock.
On August 23, 1995, a class action law suit was filed against the Company
in Grady County, Oklahoma District Court. This suit was one of several class
actions filed against Oklahoma gas producers seeking payment of royalties on
amounts received in prior gas contract litigation settlements. The Oklahoma
Supreme Court ruled in another case, to which the Company was not a party, that
royalties were not payable on the proceeds of such settlements. Following this
ruling the suit against the Company was dismissed without prejudice on September
12, 1996 upon motion filed by counsel for the plaintiff class.
Accounting Matters
On October 1, 1995 , the Company adopted the provisions of SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," which addresses the impairment of proved oil and gas
properties. The SFAS No. 121 impairment test compares the expected undiscounted
future net revenues from each producing field 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" using the discounted future net revenues for the producing field.
The Company recorded an additional impairment charge for proved properties under
SFAS No. 121 of $1.0 million in the fourth quarter of 1995.
-32-
In November 1996, the Company adopted a stock option plan (the "Stock
Option Plan") which covers a maximum of 700,000 shares. Options granted under
the Stock Option Plan are to be exercisable at the market price of Company stock
on the date of grant and have a term of ten years but may not be exercised
during the initial five years. Options vest twenty-five percent on the date of
grant and an additional twenty-five percent upon the completion of each of the
following three years of employment with the Company. Options however will be
fully vested in the event of an employment termination due to death, disability
or normal retirement and options may terminate upon any termination of
employment for cause. In the event of any acquisition of the Company, the
options will also fully vest and upon completion of such acquisition,
unexercised options will terminate. The Company adopted SFAS No. 123,
"Accounting for Stock-Based Compensation," for the year ended December 31, 1996
through compliance with the disclosure requirements set forth in SFAS No. 123.
Effective November 21, 1996, the Company authorized the issuance of 256,598
options, exercisable at $20.50 per share, the fair market value on the date of
issuance, in connection with the termination of future awards under the
Company's SAR plan. On December 31, 1996, the Company granted options to
purchase 42,880 shares of the Company's common stock under the Stock Option
Plan, exercisable at $24.875 per share, the fair market value on the date of
issuance.
Effects of Inflation and Changing Prices
The Company's results of operations and cash flow are affected by changing
oil and gas prices (see Note 7). Within the United States inflation has had a
minimal effect on the Company. The Company cannot predict the extent of any such
effect. If oil and gas prices increase, there could be a corresponding increase
in the cost to the Company for drilling and related services as well as an
increase in revenues.
-33-
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 AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
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.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the
Company's Proxy Statement.
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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference from the
Company's Proxy Statement.
-34-
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 Accountants............................ F-1
Consolidated Balance Sheets.................................. F-2
Consolidated Statements of Income............................ F-3
Consolidated Statements of Stockholders' Equity.............. F-4
Consolidated Statements of Cash Flows........................ F-5
Notes to Consolidated Financial Statements................... F-7
All other schedules are omitted because the required information is not
applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.
(b) Reports on Form 8-K. One report on Form 8-K dated December 16, 1996 was
filed regarding the sale of the Company's Russian joint venture during the last
quarter of the period covered by this report.
(c) Exhibits. The following exhibits are filed with or incorporated into
this report on Form 10-K:
Exhibit
Number Description
- ------ -----------
1.1* Form of Underwriting Agreement, as amended
1.2 Form of Underwriting Agreement incorporated by reference to Form S-3
(File No. 333-20587)
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
10.9* Non-qualified Supplemental Trust Agreement, 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
10.34** Summary Plan Description 401(k) Profit Sharing Plan
10.35** Summary Plan Description/Pension Plan dated December 30, 1994
10.41 Second Restated Partnership Agreement - Panterra Petroleum
10.42 Purchase and Sale Agreement between Siete Oil & Gas Corporation
and Registrant incorporated by reference from Exhibit 10.42 filed
on Form 8-K dated June 28, 1996, as amended by a Form 8-K/A dated
June 28, 1996
-35-
10.43 Acquisition Agreement regarding the sale of the Company's
Russian joint venture incorporated by reference from the
Exhibit 10.43 filed on Form 8-K dated December 16, 1996
10.44 Amended and Restated Credit Agreement between Registrant and
NationsBank of Texas, N.A. and Norwest Bank Colorado, National
Association, dated April 1, 1996, incorporated by reference from
Exhibit 10.1 filed on Form 8-K dated January 28, 1997
10.45 Amended and Restated Credit Agreement between Panterra Petroleum,
Registrant and First Interstate Bank, dated February 6, 1995,
incorporated by reference from Exhibit 10.2 filed on Form 8-K dated
January 28, 1997
10.46 Employment Agreement between Registrant and Ralph H. Smith,
effective October 1, 1995, incorporated by reference from Exhibit 99
filed on Form 8-K dated January 28, 1997
10.47 Stock Option Plan
10.48 Incentive Stock Option Plan
21.1* Subsidiaries of Registrant
23.2 Consent of Coopers & Lybrand L.L.P.
24.1* Power of Attorney (included on signature page)
27.1 Financial Data Schedule
* Incorporated by reference from Registrant's Registration Statement on
Form S-1 (File No. 33-53512)
** Incorporated by reference from Registrant's Annual Report on Form 10-K
for the years ended December 31, 1992 through 1995 (File No. 0-20872)
(d) Financial Statement Schedules. See Item 14(a) above.
-36-
REPORT OF INDEPENDENT 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 and Subsidiaries as of December 31, 1996 and 1995, and the
related consolidated statements of income, stockholders' equity, and cash flows
for each of the three years in the period 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 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996 in conformity with generally
accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for impairment of long-lived assets in 1995.
COOPERS & LYBRAND L.L.P.
Denver, Colorado
March 3, 1997, except for the second paragraph of Note 14, as to which the date
is March 21, 1997.
F-1
ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY DATA
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
ASSETS
December 31,
--------------------------
1996 1995
---------- ----------
Current assets:
Cash and cash equivalents $ 3,338 $ 1,723
Accounts receivable 21,443 8,068
Prepaid expenses 1,115 850
Refundable income taxes 57 176
Investment in Russian joint venture held for sale 6,151 -
---------- ----------
Total current assets 32,104 10,817
---------- ----------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 198,652 165,750
Unproved oil and gas properties, net of impairment
allowance of $2,330 in 1996 and $2,971 in 1995 14,581 11,752
Other 3,509 2,535
---------- ----------
216,742 180,037
Less accumulated depletion, depreciation, (115,232) (108,392)
amortization and impairment ---------- ----------
101,510 71,645
---------- ----------
Other assets:
Investment in Russian joint venture - 4,140
Investment in Summo Minerals Corporation 4,884 4,842
Restricted cash 2,918 -
Other assets 2,855 4,682
---------- ----------
10,657 13,664
---------- ----------
$ 144,271 $ 96,126
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 16,628 $ 7,715
Stock appreciation rights 1,550 -
---------- ----------
Total current liabilities 18,178 7,715
---------- ----------
Long-term liabilities:
Long-term debt 43,589 19,602
Deferred income taxes 5,790 1,228
Stock appreciation rights 1,195 1,178
Other noncurrent liabilities 359 121
---------- ----------
50,933 22,129
---------- ----------
Commitments and contingencies (Notes 1, 7, 8 and 9)
Stockholders' equity:
Common stock, $.01 par value: authorized - 15,000,000
shares; issued and outstanding - 8,759,214
shares in 1996 and 8,761,855 shares in 1995 88 88
Additional paid-in capital 15,801 15,835
Retained earnings 59,303 50,378
Unrealized gain (loss) on marketable equity
securities-available for sale (32) 15
Treasury stock - 2,572 shares, at cost - (34)
---------- ----------
Total stockholders' equity 75,160 66,282
---------- ----------
$ 144,271 $ 96,126
========== ==========
The accompanying notes are an integral part
of these consolidated financial statements.
F-2
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share amounts)
For the Years Ended December 31,
---------------------------------
1996 1995 1994
--------- --------- ---------
Operating revenues:
Oil and gas production $ 56,774 $ 36,569 $ 38,239
Gain on sale of proved properties 2,254 1,292 418
Gas contract settlements and other revenues 523 789 6,128
--------- --------- --------
Total operating revenues 59,551 38,650 44,785
--------- --------- ---------
Operating expenses:
Oil and gas production 12,897 10,646 10,496
Depletion, depreciation and amortization 12,732 10,227 10,134
Impairment of proved properties 408 2,676 4,219
Exploration 8,185 5,073 8,104
Abandonment and impairment of unproved properties 1,469 2,359 1,023
General and administrative 7,603 5,328 5,261
Gas contract disputes and other 78 152 493
(Income) loss in equity investees (1,272) 579 348
--------- --------- ---------
Total operating expenses 42,100 37,040 40,078
--------- --------- ---------
Income from operations 17,451 1,610 4,707
Nonoperating income and (expense):
Interest income 186 287 426
Interest expense (2,137) (1,183) (951)
--------- --------- ---------
Income from continuing operations before income taxes 15,500 714 4,182
Income tax expense (benefit) 5,333 (723) 445
--------- --------- ---------
Income from continuing operations 10,167 1,437 3,737
Gain on sale of discontinued operations, net
of taxes of $82 in 1996 and $158 in 1995 159 306 -
--------- --------- ---------
Net income $ 10,326 $ 1,743 $ 3,737
========= ========= =========
Net income per common share:
Income from continuing operations $ 1.16 $ .17 $ .43
Gain on sale of discontinued operations .02 .03 -
--------- --------- ---------
Net income per share $ 1.18 $ .20 $ .43
========= ========= =========
Weighted average common shares outstanding 8,759 8,760 8,763
========= ========= =========
The accompanying notes are an integral part
of these consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands, except share amounts)
Unrealized
Gain (Loss) On
Marketable
Equity
Common Stock Additional Securities
-------------------------- Paid-in Retained Available
Shares Amount Capital Earnings For Sale
----------- ---------- ---------- ---------- ----------
Balance, December 31, 1993 8,762,604 $ 88 $ 15,845 $ 47,702 $ -
Net income - - - 3,737 -
Cash dividends, $ .16 per share - - - (1,402) -
Adoption of SFAS No. 115 - - - - 589
Unrealized loss - - - - (525)
----------- ---------- ---------- ---------- ----------
Balance, December 31, 1994 8,762,604 88 15,845 50,037 64
Net income - - - 1,743 -
Cash dividends, $ .16 per share - - - (1,402) -
Unrealized loss - - - - (49)
Purchase and retirement
of common stock (749) - (10) - -
----------- ---------- ---------- ---------- ----------
Balance, December 31, 1995 8,761,855 88 15,835 50,378 15
Net income - - - 10,326 -
Cash dividends, $ .16 per share - - - (1,401) -
Unrealized loss - - - - (47)
Purchase and retirement
of common stock (69) - - - -
Retirement of treasury stock (2,572) - (34) - -
----------- ---------- ---------- ---------- ----------
Balance, December 31, 1996 8,759,214 $ 88 $ 15,801 $ 59,303 $ (32)
=========== ========== ========== ========== ==========
The accompanying notes are an integral part
of these consolidated financial statements.
F-4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
---------------------------------
1996 1995 1994
--------- --------- ---------
Cash flows from operating activities:
Cash received from oil and gas operations $ 44,643 $ 33,663 $ 41,346
Cash paid for oil and gas operations,
including general and administrative expenses (13,387) (13,051) (13,175)
Exploration expenses (4,843) (3,672) (6,860)
Interest and other receipts 50 1,356 686
Interest paid (1,953) (795) (767)
Income taxes refunded (paid) (305) 212 (959)
--------- --------- ---------
Net cash provided by operating activities 24,205 17,713 20,271
--------- --------- ---------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 3,082 2,337 221
Capital expenditures, including dry hole costs (27,504) (22,657) (16,950)
Acquisition of oil and gas properties (20,957) (8,111) (5,066)
Purchase of interest in St. Mary Operating Company 3,059 - -
Investment in Russian joint venture (209) (297) (631)
Investment in Summo Minerals Corporation - (4,528) (219)
Restricted cash (2,918) - -
Other 272 264 (499)
--------- --------- ---------
Net cash used by investing activitie (45,175) (32,992) (23,144)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from long-term debt 42,996 19,513 -
Repayment of long-term debt (19,009) (11,041) (578)
Dividends paid (1,401) (1,402) (1,402)
Other (1) (44) -
--------- --------- ---------
Net cash provided (used) by financing activities 22,585 7,026 (1,980)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 1,615 (8,253) (4,853)
Cash and cash equivalents at beginning of period 1,723 9,976 14,829
--------- --------- ---------
Cash and cash equivalents at end of period $ 3,338 $ 1,723 $ 9,976
========= ========= =========
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 (Continued)
(In thousands)
For the Years Ended December 31,
--------------------------------------
1996 1995 1994
---------- ---------- ----------
Reconciliation of net income to net cash
provided by operating activities:
Net income $ 10,326 $ 1,743 $ 3,737
Adjustments to reconcile net income to net
cash provided by operating activities:
Depletion, depreciation and amortization 12,732 10,227 10,134
Impairment of proved properties 408 2,676 4,219
(Income) loss in equity investees (1,272) 579 348
Gain on sale of proved properties (2,254) (1,292) (418)
Dry hole costs 3,048 1,286 2,435
Abandonment and impairment of unproved properties 1,469 2,359 1,023
Deferred income taxes 4,634 (1,038) (835)
Other 17 (407) 105
---------- ---------- ----------
29,108 16,133 20,748
Changes in assets and liabilities, net of effect of
purchase of interest in St. Mary Operating Company:
Accounts receivable (9,288) 166 (450)
Refundable income taxes 119 200 448
Accounts payable and accrued expenses 4,338 706 (402)
Deferred income taxes (72) 508 (73)
---------- ---------- ----------
Net cash provided by operating activities $ 24,205 $ 17,713 $ 20,271
========== ========== ==========
Supplemental schedule of noncash investing and financing activities:
In January 1994, the Company acquired an additional 10.28% general partnership interest in Panterra Petroleum for
approximatley $1.3 million in cash and the assumption of $1.9 million in bank debt.
In December 1994, the Company acquired an additional 14.9% general partnership interest in Panterra Petroleum by
participating in the buyout of Wesco Resources, another general partner. This interest was acquired for $3.3 million
and the assumption of $2.2 million in bank debt.
In May 1995, the Company sold a portion of its remaining real estate assets for $975,000 and carried back a note
from the buyer for $731,000.
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.
The accompanying notes are an integral part
of these consolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 crude oil and natural gas in the United States, Russia, Canada and
Trinidad and Tobago. The Company'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. During 1996, the Company
agreed to, and in February 1997, completed the sale of its interest in the
Russian joint venture.
Reclassifications:
Certain amounts in the 1995 and 1994 consolidated financial statements have
been reclassified to correspond to the 1996 presentation.
Basis of Presentation:
The consolidated financial statements include the accounts of the Company
and its subsidiaries, all of which are wholly owned. All significant
intercompany accounts and transactions have been eliminated.
The Company accounts for its investment in the Russian joint venture and
Summo Minerals Corporation under the equity method of accounting. 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 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 joint venture
participants. 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.
F-7
The Company has accounts with separate banks in Denver, Colorado, Dallas,
Texas and Shreveport, Louisiana. At December 31, 1996 and 1995, the Company had
$1,864,000 and $386,000, 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.
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 property-by-property basis, are considered to be not
realizable. Depletion, depreciation and amortization ("DD&A") of capitalized
costs of proved oil and gas properties is provided on a property-by-property
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.
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," which addresses the impairment of proved oil and gas properties. The
Company adopted SFAS No. 121 as of October 1, 1995 and recorded an additional
impairment charge for proved properties of $1,003,000 in the fourth quarter of
1995. During 1996 the Company recorded impairment charges for proved properties
of $408,000. The SFAS No. 121 impairment test compares the expected undiscounted
future net revenues on a property-by-property 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.
Prior to the adoption of SFAS No. 121, the net capitalized costs of proved
oil and gas properties were limited to the aggregate undiscounted, after-tax,
future net revenues determined on a property-by-property basis (the "ceiling
test"). If the net capitalized costs exceeded the ceiling, the excess was
recorded as a charge to operations. The Company recorded impairment charges for
proved properties under this ceiling test method of $1,673,000 and $4,219,000 in
1995 and 1994 respectively, due to price declines and downward reserve
revisions.
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.
F-8
Other Property and Equipment:
Other property and equipment is recorded at cost. Costs of renewal and
improvement which substantially extend the useful lives of the assets are
capitalized. Maintenance and repairs are expensed when incurred. Depreciation
and amortization 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 which
cannot be balanced in the future due to insufficient remaining reserves. The
related receivable totaling $850,000 and $868,000 at December 31, 1996 and 1995,
respectively, is included in other assets 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 13).
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 deferred until recognized as an adjustment to
revenues when the related oil and gas is sold. Cash flows from such transactions
are included in oil and gas operations. The Company realized net losses of
$4,253,000, $11,000 and $16,000 on these contracts for the years ended December
31, 1996, 1995 and 1994 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 or interest rates. However, the Company
only enters into hedging contracts with large financial institutions and does
not anticipate nonperformance.
As of December 31, 1995, the Company adopted SFAS No. 107, "Disclosures
about Fair Value of Financial Instruments," requiring disclosure of fair value
information of financial instruments, whether or not recognized in the balance
sheet, for which it is practicable to estimate fair value. In cases where quoted
market prices are not available, fair values are based on estimates using
present value or other valuation techniques. Disclosures about fair value are
not required for certain financial instruments and all nonfinancial instruments.
F-9
Income Taxes:
Deferred income taxes are provided on the difference between the tax basis
of an asset or liability and its reported 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.
Net Income Per Share:
Net income per share of common stock is calculated by dividing net income
by the weighted average of common shares and common equivalent shares, if
dilutive, outstanding during each year. Common equivalent shares were not
materially dilutive for any periods presented.
In March 1997, the FASB issued SFAS No. 128, "Earnings Per Share," which
requires a dual presentation of basic and diluted earnings per share. The
Company plans to adopt SFAS No. 128 in 1997. Management believes the adoption of
this standard will not have a material impact on earnings per share of the
Company.
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.
2. Accounts Receivable:
Accounts receivable are composed of the following:
December 31,
------------------------
1996 1995
-------- --------
(in thousands)
Accrued oil and gas sales:
Due from third parties $ 14,309 $ 4,827
Due from St. Mary Operating Company - 1,958
Due from joint interest owners 7,134 1,283
-------- --------
$ 21,443 $ 8,068
======== ========
3. Investment in Summo Minerals Corporation:
As of December 31, 1996 and 1995, the Company owned 9,644,093 (49% of total
shares outstanding) and 9,028,003 (51% of total shares outstanding) shares of
Summo Minerals Corporation ("Summo"), an international mining company, with a
total cost of $5,608,000 and $5,108,000, and warrants to acquire an additional
6,261,000 and 5,495,000 shares, respectively. Exercise prices for the warrants
range from $.80 to $1.01, using the Canadian exchange rate in effect on December
31, 1996 ($.73). Summo completed its initial public offering effective October
31, 1994 at $.44 per share. The market value of this investment was $8,444,000
at December 31, 1996 and $7,945,000 at December 31, 1995. For the years ending
December 31, 1996 and 1995, the Company reported equity in losses from Summo of
$457,000 and $257,000, respectively.
F-10
4. Income Taxes:
The provision for income taxes consists of the following:
For the Years Ended
December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
(In thousands)
Current taxes:
Federal $ 81 $ 77 $ 835
State 700 396 445
Deferred taxes 4,634 (1,038) (835)
-------- -------- --------
Total income tax expense (benefit) $ 5,415 $ (565) $ 445
======== ======== ========
Continuing operations $ 5,333 $ (723) $ 445
Discontinued operations 82 158 -
-------- -------- --------
Total income tax expense (benefit) $ 5,415 $ (565) $ 445
======== ======== ========
The above taxes from continuing operations are net of alternative fuel
credits (Section 29) of $551,000 in 1996, $624,000 in 1995 and $1,333,000 in
1994.
The components of the net deferred tax liability are as follows
(in thousands):
December 31,
--------------------
1996 1995
-------- --------
Deferred tax assets
Non-current
Other, primarily employee benefits $(2,152) $(1,458)
State tax net operating loss carryforward (1,600) (1,402)
Alternative minimum tax credit carryforward (691) (565)
-------- --------
Total deferred tax assets (4,443) (3,425)
Valuation allowance 898 1,402
-------- --------
Net deferred tax assets (3,545) (2,023)
Deferred tax liabilities
Non-current
Oil and gas properties 8,787 2,886
Other 548 365
-------- --------
Net deferred tax liability $ 5,790 $ 1,228
======== ========
F-11
At December 31, 1996, the Company had state net operating loss
carryforwards of approximately $26.8 million which expire between 1997 and 2011
and alternative minimum tax credit carryforwards of $691,000 which may be
carried forward indefinitely. The Company's valuation allowance relates 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. The net change in valuation allowance in 1996 results from utilization
of Oklahoma net operating loss carryforwards and the current year calculation of
deferred state income tax for Oklahoma. The net change in valuation allowance in
1995 is primarily a result of the recognition of a capital loss carryover. The
net change in valuation allowance in 1994 is primarily a result of state net
operating loss carryforwards and Federal capital loss carryforwards expected to
expire before they can be utilized.
Federal income tax expense (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 reasons:
For the Years Ended
December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
(In thousands)
Federal statutory taxes $5,270 $ 242 $1,422
Increase (reduction) in taxes resulting from:
State taxes (net of Federal benefit) 1,212 261 294
Statutory depletion (173) (173) (174)
Alternative fuel credits (Section 29) (551) (624) (1,333)
Change in valuation allowance (504) (412) 225
Other 79 (17) 11
-------- -------- --------
Income tax expense (benefit) $ 5,333 $ (723) $ 445
======== ======== ========
5. Long-term Debt and Notes Payable:
In April 1996, the Company amended and restated its long-term revolving
credit facility dated March 1, 1993 and extended its maturity to June 30, 1999.
Borrowings under this agreement are limited to the lesser of $60,000,000 or the
current borrowing base, as determined by the bank annually. The borrowing base
at December 31, 1996 was $40,000,000 and was increased to $60,000,000 in
February 1997 based on year-end reserve values. The agreement has a three year
term, at the end of which borrowings can be converted to a five year amortizing
loan. The Company can elect to allocate up to 50% of available borrowings to a
short term tranche due in 364 days. Borrowings under this agreement are
collateralized by a mortgage of substantially all of the Company's producing oil
and gas properties. In addition, the Company must comply with certain other
covenants, including maintenance of stockholders' equity at a specified level,
limitations on additional indebtedness and payment of dividends. As of December
31, 1996 and 1995, $33,875,000 and $8,300,000, respectively, was outstanding
under this credit facility.
F-12
Through March 31, 1995, interest on borrowings was computed at the bank's
prime rate or LIBOR plus 1.5%. Effective April 1, 1995, interest on borrowings,
based on debt to capitalization ratios, and commitment fees on the unused
portion of borrowings are calculated as follows:
Debt to Capitalization Ratio Revolving Loan Term Loan
---------------------------- -------------- ---------
Interest rates:
Less than 30% Prime rate or Prime rate or
LIBOR +.5% LIBOR +.75%
Greater than 30%, less than 40% Prime rate or Prime rate or
LIBOR +.75% LIBOR +1.0%
Greater than 40%, less than 50% Prime rate or Prime rate or
LIBOR + 1.0% LIBOR +1.25%
Greater than 50% Prime rate +.125% Prime rate +.125%
or LIBOR +1.25% or LIBOR +1.5%
Commitment Fees on Unused Portion Short Term Tranche Long Term Tranche
--------------------------------- ------------------ -----------------
Less than 50% of .125% .25%
available borrowing
Greater than 50% of .375% .50%
available borrowings
At December 31, 1996 and 1995, the Company's debt to capitalization ratio
as defined was 37.5% and 24%, respectively. At December 31, 1996, interest on
borrowings is computed at the bank's prime rate or LIBOR plus .75% (8.25% or
6.31%, respectively). At December 31, 1995, interest on borrowings was computed
at the bank's prime rate or LIBOR plus .5% (8.5% or 6.16%, respectively).
In February 1995, Panterra entered into a credit agreement with a bank
replacing a previous credit agreement due April 30, 1998. The new credit
agreement as modified on February 21, 1997 includes a two year revolving period
converting to a five year amortizing loan on March 31, 1999. Borrowings under
this agreement are limited to the lesser of $40,000,000 or the current borrowing
base, as determined by the bank semiannually. The borrowing base at December 31,
1996 and 1995 was $26,000,000 and $18,500,000, respectively. During the
revolving period, interest on borrowings, based on debt to partners' capital
ratios, and commitment fees on the unused portion of the borrowings are
calculated as follows:
Debt to Partners' Capital Ratio Interest rates Commitment Fees
------------------------------- -------------- ---------------
Less than 50% Prime rate or .25%
LIBOR +1.0%
Greater than 50%, less than 100% Prime rate or .25%
LIBOR +1.25%
Greater than 100%, less than 150% Prime rate + .125% .375%
or LIBOR + 1.5%
Greater than 150% Prime rate +.25% .50%
or LIBOR +1.75%
At December 31, 1996, Panterra's debt to partners' capital ratio as defined
was 76% and interest on borrowings is computed at the bank's prime rate or LIBOR
plus 1.25% (8.25% or 7.05%, respectively). Interest on borrowings at December
31, 1995 was payable at the bank's prime rate or LIBOR plus 1.5% (8.5% or 7.16%,
respectively). During the amortization period, interest is payable at the bank's
prime rate plus .25% or LIBOR plus 1.75%. Principal payments during the
revolving period are not required if the loan amount is less than the current
borrowing base. During the amortization period, monthly principal payments are
payable at rates decreasing from 2.0% to 1.4% of the outstanding balance through
March 2004 at which time the remaining principal balance is due.
F-13
The new Panterra credit agreement is collateralized by all of Panterra's
oil and gas properties and contains covenants which, among other things,
restrict the acquisition of assets and the incurrence of additional debt and
require that certain minimum financial ratios be maintained. As of December 31,
1996 and 1995, $13,100,000 and $15,150,000, respectively, was outstanding under
this credit facility. The Company's proportionate share of the liability under
Panterra's bank note payable is 74%.
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:
Year Ending
December 31, (In thousands)
------------ --------------
1997 $ -
1998 -
1999 5,165
2000 8,339
2001 7,920
Thereafter 22,165
-------
$43,589
=======
6. Gas Contract Settlements:
During 1994, the Company settled the final two gas contract disputes with
pipeline companies, recognizing income of $5,741,000.
7. Commitments and Contingencies:
The Company leases office space under operating leases which were amended
and extended through May 31, 2002. The annual minimum lease payments approximate
$523,000. The Company has noncancelable annual leases with affiliates of
approximately $75,000. Rent expense, net of sublease income, was $426,000,
$131,000 and $166,000 in 1996, 1995 and 1994, respectively.
F-14
The Company has the following commodity contracts in place as of December
31, 1996 to hedge or otherwise reduce the impact of oil and gas price
fluctuations:
Product Volumes/month Fixed Price Duration
----------- ------------- ----------- ------------
Natural Gas 15,000 MMBTU $2.065 1/97 - 3/97
Natural Gas 107,000 MMBTU $2.305 1/97 - 3/97
Natural Gas 200,000 MMBTU $2.665 1/97 - 3/97
Natural Gas 24,000 MMBTU $1.87 1/97 - 5/97
Natural Gas 35,000 MMBTU $1.73 1/97 - 10/97
Natural Gas 39,000 MMBTU $2.015 1/97 - 10/97
Natural Gas 24,000 MMBTU $1.825 1/97 - 12/97
Natural Gas 15,000 MMBTU $1.94 1/97 - 2/98
Natural Gas 22,500 MMBTU $1.9025 1/97 - 6/98
Oil 10,000 BBLS $18.40 1/97
Oil 12,100 BBLS $18.36 1/97
Oil 5,000 BBLS $18.30 1/97
Oil 3,200 BBLS $17.95 1/97 - 2/97
Oil 1,200 BBLS $18.44 1/97 - 2/97
Oil 1,000 BBLS $16.95 1/97 - 4/97
Oil 1,125 BBLS $16.98 1/97 - 10/97
Oil 1,000 BBLS $21.35 2/97 - 12/97
Oil 1,300 BBLS $21.05 2/97 - 1/98
Oil 10,000 BBLS $17.95 2/97 - 6/98
The fair value of the Company's commodity hedging contracts based on year
end futures pricing would require the Company to pay approximately $2,585,000,
if these contracts were terminated on December 31, 1996.
At December 31, 1996, Panterra held various hedge contracts covering
280,000 BBLS of future production. These contracts expire at various dates
through May 1997, with floor prices ranging from $18.00 / BBL to $27.00 / BBL.
If the open hedging contracts were liquidated at December 31, 1996, the Company
would recognize a loss of approximately $211,000.
On August 23, 1995, a class action law suit was filed against the Company
in Grady County, Oklahoma District Court. This suit was one of several class
actions filed against Oklahoma gas producers seeking payment of royalties on
amounts received in prior gas contract litigation settlements. Following the
issuance of a decision by the Oklahoma Supreme Court in another case, to which
the Company was not a party, holding that royalties were not payable on the
proceeds of such settlements, this suit was dismissed without prejudice on
September 12, 1996 upon motion filed by counsel for the plaintiff class.
8. 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 will be based on performance adjusted
salaries. 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%. The
Company records compensation expense once it recovers its investment, and net
profits attributable to the properties are payable to the employees. During
1996, the Company recorded compensation expense of $119,000 relating to net
profits attributable to these properties.
F-15
In March 1992, the Company adopted a stock appreciation rights ("SAR") plan
for officers and directors and awarded 90,962 shares with a value of $4.26 per
share effective January 1, 1992. This SAR vests over a four-year period, with
payment occurring five years after the date of grant. The SAR plan replaced the
restricted stock bonus plan. In 1996 the Company awarded 61,873 shares with a
value of $14.00 per share effective January 1, 1996. In 1995 the Company awarded
34,917 shares with a value of $13.25 per share effective January 1, 1995. In
1994 the Company awarded 38,938 shares with a value of $11.63 per share
effective January 1, 1994 and in 1993 the Company awarded 35,684 shares with a
value of $11.50 per share effective January 1, 1993. Compensation expense
recognized under the SAR plan was $1,567,000, $220,247 and $268,286 in 1996,
1995 and 1994, respectively. In November 1996, the Company terminated future
awards under the Company's SAR plan and capped the value of the shares under the
SAR plan at the then fair market value of the Company's common stock of $20.50
per share, in connection with the adoption of a new stock option plan. The
resulting liability of $2,745,000 is classified as current and long-term in the
consolidated balance sheets, based on expected payment dates.
Through September 1992, the Company had a restricted stock bonus plan
("Plan") covering officers and key employees. The Plan provided for the granting
of stock and cash not to exceed 100% of the participant's then annual salary.
The Plan provided that any portion or all of the stock could be purchased by the
Company in the case of termination of employment for any reason. A participant
has the option at any time to sell shares acquired under the Plan to the Company
at a price related to its fair market value as defined in the Plan. At December
31, 1996, there were 33,520 shares issued and outstanding under the Plan. The
Company's stock price was $24.875 at December 31, 1996.
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 income. The
Company matches each employee's contributions up to 6% of the employee's income
and also may make additional contributions at its discretion. Contributions to
the 401(k) Plan amounted to $199,000, $183,000 and $93,000 for the years ended
December 31, 1996, 1995 and 1994, respectively.
During 1996 the Company established the St. Mary Land & Exploration Company
Stock Option Plan (the "Stock Option Plan"). The Stock Option Plan grants
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 Stock Option Plan. During 1996 options to purchase 256,598, in connection
with the termination of future awards under the Company's SAR plan, and 42,880
shares of the Company's common stock were granted under the Stock Option Plan at
exercise prices of $20.50 and $24.875, respectively, which were equal to the
respective market prices of the stock on the grant dates. 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 were exercised
during the year ended December 31, 1996.
Also, 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 date of grant.
F-16
A summary of the status of the Company's Stock Option Plan including the
1990 and 1991 options as of December 31, 1996, and changes during the year then
ended is as follows:
Weighted
Average
Shares Exercise Price
------- --------------
Outstanding at beginning of year 54,614 $ 3.30
Granted 299,478 21.13
Exercised - -
Forfeited - -
------- -------
Outstanding at end of year 354,092 $ 18.38
======= =======
Options exercisable at year end 145,576
=======
Options available for future grant 400,522
=======
Weighted average fair value of options
granted during the year $ 8.06
=======
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." This Statement establishes a fair value method of accounting for
stock-based compensation plans either through recognition or disclosure. The
Company has elected to continue following Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees" (APB No. 25) and has elected
to adopt SFAS No. 123 through compliance with the disclosure requirements set
forth in the Statement. Because the exercise price of the Company's 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
these options was estimated at the date of grant using the Black-Scholes option
pricing model with the following weighted-average assumptions for 1996:
risk-free interest rate(s) of 6.2%; dividend yield of .76%; volatility factor of
the expected market price of the Company's common stock of 37.88%; and
weighted-average 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 which 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.
F-17
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 options 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:
Pro Forma for the Year
Ended December 31, 1996
-----------------------
(in thousands, except
per share amounts)
Net Income applicable to As reported $ 10,326
common stock Pro forma $ 9,607
Primary earnings per share As reported $ 1.18
Pro forma $ 1.10
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.
9. Pension Plans:
The Company's employees participate in a noncontributory pension plan
covering substantially all employees who meet age and service requirements (the
"Primary Plan"). Benefits provided under this pension plan are based primarily
on each employee's career earnings. As of December 31, 1996, plan assets were
invested primarily in diversified stock and bond funds.
In addition, the Company has a supplemental noncontributory pension plan
covering certain management employees (the "Supplemental Plan"). Benefits are
based mainly on each participant's years of service, final average compensation
and estimated benefits received from certain other plans.
The components of net pension expense are as follows:
For the Years Ended
December 31,
--------------------------
1996 1995 1994
------ ------ ------
(In thousands)
Service cost - benefits earned during the year $ 131 $ 79 $ 129
Interest cost on projected benefit obligations 80 51 45
Actual (return) loss on plan assets (67) (133) 27
Net amortization (deferral) 6 61 (94)
------ ------ ------
Net pension expense $ 150 $ 58 $ 107
====== ====== ======
F-18
A reconciliation of the funded status of the plans to accrued pension
liability is as follows:
Primary Plan Supplemental Plan
December 31, December 31,
----------------- -----------------
1996 1995 1996 1995
------ ------ ------ ------
(In thousands)
Actuarial present value of benefits based
on service date and present pay levels:
Vested $ 497 $ 263 $ 202 $ 140
Nonvested 154 63 23 -
------ ------ ------ ------
Accumulated benefit obligation 651 326 225 140
Additional amounts related to pay increases 281 219 172 127
------ ------ ------ ------
Projected benefit obligation 932 545 398 267
Plan assets at fair value 874 810 - -
------ ------ ------ ------
Projected benefit obligation (in excess of)
or less than plan assets (58) 265 (398) (267)
Unrecognized (gain) loss - (261) 224 192
Unrecognized net asset (7) (17) - -
------ ------ ------ ------
Accrued pension liability included
in the consolidated balance sheets $ (65) $ (13) $(174) $ (75)
====== ====== ====== ======
Actuarial assumptions for December 31, 1996 and 1995 are as follows:
1996 1995
---- ----
Discount rate 7.50% 7.50%
Average salary growth rate 5.00% 5.00%
Return on plan assets 8.00% 8.00%
10. Related Party Transactions:
Through October 1994, a majority of the Company's oil and gas operations,
other than Louisiana royalties, including acquisition of unproved properties,
were administered by SMOC. Operations were conducted under a domestic agreement
with SMOC and various individuals (the "Anderman Group") which was effective
January 1, 1992, amended July 1, 1993 and terminated on December 31, 1995.
Through the termination date the Company paid 70% of all costs for lease
acquisitions, geophysical surveys, drilling and production and owned 68% of all
resulting properties, production and reserves. Through December 31, 1995, the
Company also paid 65% of all overhead costs of SMOC incurred for exploration and
production activities, and through September 1995, quarterly fees of $125,000 to
the Anderman Group.
Effective April 1, 1995, the Company gave notice that it would not
participate in any new international ventures managed by the Anderman Group, and
on November 30, 1995, withdrew from all international partnerships with the
exception of those with interests in Russia, Canada and Trinidad and Tobago.
During 1995, the Company recorded a charge to operations of $252,000 resulting
from its withdrawal from the international partnerships.
F-19
Billings from SMOC, which represent charges for lease operating,
exploration, development and general and administrative expenses, amounted to
$11,451,000 and $14,008,000 for the years ended December 31, 1995 and 1994,
respectively. As of December 31, 1995, accounts payable included $746,000 owed
to SMOC.
11. Investment in Russian Joint Venture:
In September 1991, the Company, through an affiliate of the Anderman Group,
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 Ural Petroleum Corporation ("UPC"). Closing of the transaction
occurred on February 12, 1997. In accordance with the terms of the Acquisition
Agreement, the Company received cash consideration of approximately $5.2 million
before transaction costs, approximately $1.7 million of UPC common stock and a
receivable in a form equivalent to a retained production payment of
approximately $10.3 million 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 UPC to purchase
the Company's receivable from the net proceeds of an initial public offering of
UPC common stock or alternatively, the Company may elect to convert all or a
portion of its receivable into UPC common stock immediately prior to an initial
public offering of UPC common stock. As of December 31, 1996 the Company's
investment in the Russian joint venture is classified in the financial
statements as held for sale.
Summarized financial information of the Russian joint venture is shown
below:
For the Years Ended
December 31,
---------------------------------
1996 1995 1994
--------- --------- ---------
(Unaudited, in thousands)
Income Statement:
Oil and gas revenues $ 60,367 $ 29,479 $ 15,035
Operating expenses 44,752 22,547 12,707
Interest and other expenses 9,199 8,966 5,831
--------- --------- ---------
Net income (loss) $ 6,416 $ (2,034) $ (3,503)
========= ========= =========
Balance Sheet:
Current assets $ 10,088 $ 10,105 $ 12,974
Non-current assets 67,855 49,300 35,034
Current liabilities 6,595 10,569 11,700
Non-current liabilities 66,223 50,614 48,007
Shareholders' equity (deficit) 5,125 (1,778) (11,699)
F-20
12. 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 statements of income.
The Company's remaining real estate assets consist of land held for sale with a
carrying cost of $1,386,000 and $1,311,000 as of December 31, 1996 and 1995,
respectively, which is less than the estimated net realizable values.
13. Disclosures About Oil and Gas Producing Activities:
Major Customers:
During 1996, sales to an individual customer constituted 17.3% of total
revenues. There were no sales to individual customers constituting 10% or more
of total revenues during 1995 and 1994.
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:
For the Years Ended
December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
(In thousands)
Development costs $16,709 $12,625 $ 5,946
Exploration costs:
Domestic 11,910 8,746 9,481
International 84 (112) 877
Acquisitions
Proved 20,957 8,111 12,279
Unproved 2,941 2,937 3,228
-------- -------- --------
Total $52,601 $32,307 $31,811
======== ======== ========
Russian joint venture,
equity method (a) $ 3,881 $ 3,213 $ 1,551
======== ======== ========
- -----------
(a) In February 1997, the Company sold its interest in the Russian
joint venture (see note 11).
In June 1996, the Company completed the purchase of a 90% interest in
certain of the assets of Siete Oil & Gas Corporation for approximately $10.0
million. The assets purchased consist primarily of oil and gas producing
properties in the Permian Basin of west Texas and southeast New Mexico.
The accompanying unaudited pro forma consolidated operating revenues,
income from continuing operations and income per common share from continuing
operations for the years ended December 31, 1996 and 1995 are presented to
illustrate the effect of the properties purchased from Siete Oil & Gas
Corporation on the Company's results of operations as if the transaction had
occurred as of January 1, 1995.
F-21
The resulting pro-forma information is not necessarily indicative of the
results of operations of the Company as they may be in the future or as they
might have been had the transaction actually occurred as of January 1, 1995.
Pro Forma for the
Years Ended December 31,
------------------------
1996 1995
-------- --------
(Unaudited)
(in thousands, except per
share amounts)
Total operating revenues $ 61,189 $ 42,015
======== ========
Income from continuing operations $ 10,561 $ 2,142
======== ========
Income per common share from
continuing operations $ 1.20 $ .25
======== ========
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 1996, 1995, 1994 and 1993 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.
F-22
Presented below is a summary of the changes in estimated domestic reserves
of the Company and its share of the Russian joint venture reserves:
For the Years Ended December 31,
---------------------------------------------------------------
1996 1995 1994
------------------- ------------------- -------------------
Oil or Oil or Oil or
Condensate Gas Condensate Gas Condensate Gas
-------- -------- -------- -------- -------- --------
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
Total proved U.S. reserves:
Developed and undeveloped:
Beginning of year 7,509 75,705 6,677 62,515 4,590 56,535
Revisions of previous estimates 706 6,706 39 515 446 5,064
Discoveries and extensions 1,343 44,018 894 16,069 658 10,274
Purchase of minerals in place 2,625 16,894 1,095 9,274 2,062 3,262
Sale of reserves (306) (703) (152) (234) (142) (43)
Production (1,186) (15,563) (1,044) (12,434) (937) (12,577)
-------- -------- -------- -------- -------- --------
End of year (a) 10,691 127,057 7,509 75,705 6,677 62,515
======== ========= ======== ======== ======== ========
Proved developed U.S. reserves:
Beginning of year 6,829 66,230 6,050 58,661 4,160 54,420
======== ========= ======== ======== ======== ========
End of year 10,015 100,027 6,829 66,230 6,050 58,661
======== ========= ======== ======== ======== ========
Russian joint venture reserves:
End of year (b) 7,146 2,444 7,247 2,536 9,915 -
======== ========= ======== ======== ======== ========
- -----------
(a) At December 31, 1996, 1995 and 1994, includes approximately 1,622, 1,895
and 2,500 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 11).
Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
SFAS No. 69 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 year-end prices and costs to the estimated quantities of
oil and gas to be produced. 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 Financial Accounting Standards Board and, as such, do not
necessarily reflect the Company's expectations of actual revenues to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process, as discussed previously, are equally
applicable to the standardized measure computations since these estimates are
the basis for the valuation process.
F-23
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:
As of December 31,
--------------------------------------
1996 1995 1994
---------- ---------- ----------
(In thousands)
Future cash inflows $ 691,945 $ 292,149 $ 202,454
Future production and
development costs (196,677) (105,520) (73,204)
Future income taxes (155,805) (49,383) (28,977)
---------- ---------- ----------
Future net cash flows 339,463 137,246 100,273
10% annual discount (136,233) (49,547) (39,407)
---------- ---------- ----------
Standardized measure of
discounted future net cash flows $ 203,230 $ 87,699 $ 60,866
========== ========== ==========
Russian joint venture standardized
measure of discounted future net
cash flows (a) $ 23,681 $ 15,077 $ 25,242
========== ========== ==========
- -----------
(a) In February 1997, the Company sold its interest in the Russian joint
venture (see note 11).
F-24
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
For the Years Ended
December 31,
------------------------------------
1996 1995 1994
---------- ---------- ----------
(In thousands)
Standardized measure,
beginning of year $ 87,699 $ 60,866 $ 64,491
Sales of oil and gas produced,
net of production costs (43,877) (25,923) (27,743)
Net changes in prices and
production costs 71,882 23,432 (16,196)
Extensions, discoveries and other,
net of production costs 90,974 23,863 12,507
Purchase of minerals in place 26,241 10,287 11,114
Development costs incurred
during the year 6,833 2,189 1,655
Changes in estimated future
development costs (1,166) (1,801) (1,227)
Revisions of previous quantity estimates 19,350 856 6,941
Accretion of discount 12,019 8,469 9,052
Sales of reserves in place (1,224) (1,365) -
Net change in income taxes (61,459) (12,817) 6,771
Other (4,041) (357) (6,499)
---------- ---------- ----------
Standardized measure, end of year (a) $ 203,230 $ 87,699 $ 60,866
========== ========== ==========
- -----------
(a) The standardized measure was based on a year-end gas price of $3.74 per
MMBTU and a year-end oil price of $25.08 per BBL. Using these prices the
present value of future net revenues discounted at 10% before tax is $296
million. Using more conservative pricing of $2.25 per MMBTU for gas and
$21.00 per BBL for oil, the present value of future net revenues discounted
at 10% before tax would be $170 million.
14. Subsequent Event:
On January 28, 1997, the Company filed a Form S-3 Registration Statement
with the Securities and Exchange Commission, as a new financing, to register the
sale by the Company of 2,000,000 shares of common stock and up to an additional
300,000 shares to cover the underwriters' over-allotment option. On February 26,
1997 the Company closed the sale of the 2,000,000 shares of common stock at
$25.00 per share.
On March 12, 1997, the Company closed the sale of an additional 180,000
shares pursuant to the underwriters' exercise of the over-allotment option.
These transactions resulted in aggregate net proceeds of $51.3 million. The
proceeds will be used to fund the Company's exploration, development and
acquisition programs, and pending such use will be used to repay borrowings
under its credit facility. As of March 21, 1997, the Company has repaid all
borrowings under its credit facility, and effective April 1, 1997, has reduced
its commitment under this facility, until its next redetermination, to $10
million. The Company has the right to increase its commitment between
redetermination periods.
F-25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
-----------------------------------
(Registrant)
Date: March 27, 1997 By: /s/ THOMAS E. CONGDON
---------------------
Thomas E. Congdon, Chairman of the Board
GENERAL POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Thomas E. Congdon and Mark A. Hellerstein, and
each of them, his true and lawful attorney-in-fact and agents with full power of
substitution and resubstitution, for him and in his name, place and stead, in
any and all capacities, to sign any amendments to this report on Form 10-K, and
to file the same, with exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, hereby ratifying and
confirming all that each of said attorneys-in-fact, or his substitute or
substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
/s/ THOMAS E. CONGDON Chairman of the Board of March 27, 1997
------------------- Directors and Director
Thomas E. Congdon
/s/ MARK A. HELLERSTEIN President, Chief Executive March 27, 1997
------------------- Officer, and Director
Mark A. Hellerstein
/s/ RONALD D. BOONE Executive Vice President, March 27, 1997
------------------- Chief Operating Officer
Ronald D. Boone and Director
Signature Title Date
- --------- ----- ----
/s/ DAVID L. HENRY Vice President-Finance March 27, 1997
------------------- and Chief Financial
David L. Henry Officer
/s/ RICHARD C. NORRIS Vice President, Treasurer March 27, 1997
------------------- and Chief Accounting
Richard C. Norris Officer
/s/ LARRY W. BICKLE Director March 27, 1997
-------------------
Larry W. Bickle
/s/ DAVID C. DUDLEY Director March 27, 1997
-------------------
David C. Dudley
/s/ RICHARD C. KRAUS Director March 27, 1997
-------------------
Richard C. Kraus
/s/ R. JAMES NICHOLSON Director March 27, 1997
-------------------
R. James Nicholson
/s/ AREND J. SANDBULTE Director March 27, 1997
-------------------
Arend J. Sandbulte
/s/ JOHN M. SEIDL Director March 27, 1997
-------------------
John M. Seidl