ST MARY LAND & EXPLORATION CO, 424B4, 1997-02-24

ST MARY LAND & EXPLORATION CO
424B4, 1997-02-24
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>
FILED PURSUANT TO RULE 424b4
REGISTRATION STATEMENT 333-20587

[LOGO]

2,000,000 SHARES

ST. MARY LAND & EXPLORATION COMPANY
COMMON STOCK
---------------------

All of the shares of Common Stock, par value $0.01 per share ("Common
Stock"), of St. Mary Land & Exploration Company ("St. Mary" or the "Company")
offered hereby are being sold by the Company.

The Common Stock is traded on the Nasdaq National Market under the trading
symbol "MARY". The last reported sale price of the Common Stock on the Nasdaq
National Market on February 20, 1997, was $25 3/4 per share.

SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN FACTORS
THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON STOCK
OFFERED HEREBY.
---------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF
THIS PROSPECTUS. ANY REPRESENTATION TO THE
CONTRARY IS A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
UNDERWRITING DISCOUNT
PRICE TO PUBLIC (1) PROCEEDS TO COMPANY(2)
<S> <C> <C> <C>
Per Share........................... $25.00 $1.375 $23.625
Total(3)............................ $50,000,000 $2,750,000 $47,250,000
</TABLE>

(1) The Company has agreed to indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."

(2) Before deducting expenses of the offering payable by the Company estimated
at $300,000.

(3) The Company has granted the several Underwriters an option for 30 days to
purchase up to an additional 300,000 shares of Common Stock at the Price to
Public, less Underwriting Discount, solely to cover over-allotments, if any.
If such option is exercised in full, the total Price to Public, Underwriting
Discount and Proceeds to Company will be $57,500,000, $3,162,500 and
$54,337,500, respectively. See "Underwriting."

------------------------

The shares of Common Stock are offered by the several Underwriters, subject
to prior sale, when, as and if issued to and accepted by them, and subject to
certain other conditions. The Underwriters reserve the right to withdraw, cancel
or modify such offer and to reject orders in whole or in part. It is expected
that delivery of the shares of Common Stock will be made on or about February
26, 1997.

------------------------

MORGAN KEEGAN & COMPANY, INC.

A.G. EDWARDS & SONS, INC.

HANIFEN, IMHOFF INC.

THE DATE OF THIS PROSPECTUS IS FEBRUARY 21, 1997
<PAGE>
MAP OF U.S. DEPICTING AREAS OF ST. MARY'S OPERATIONS
SHOWING OUTLINES OF STATES AND COLORS
HIGHLIGHTING AREAS OF OPERATIONS

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE SECURITIES
OFFERED HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED IN THE OVER-THE-COUNTER MARKET OR
OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY ENGAGE IN PASSIVE
MARKET MAKING TRANSACTIONS IN THE COMMON STOCK OF THE COMPANY ON THE NASDAQ
NATIONAL MARKET IN ACCORDANCE WITH RULE 10b-6A UNDER THE SECURITIES EXCHANGE ACT
OF 1934. SEE "UNDERWRITING."

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<PAGE>
PROSPECTUS SUMMARY

THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE DETAILED
INFORMATION AND FINANCIAL STATEMENTS FOUND ELSEWHERE IN THIS PROSPECTUS AND THE
INFORMATION INCORPORATED HEREIN BY REFERENCE. UNLESS OTHERWISE INDICATED, ALL
INFORMATION IN THIS PROSPECTUS ASSUMES NO EXERCISE OF THE UNDERWRITERS'
OVER-ALLOTMENT OPTION. SEE "UNDERWRITING." AS USED IN THIS PROSPECTUS, THE TERMS
"ST. MARY" AND THE "COMPANY" REFER TO ST. MARY LAND & EXPLORATION COMPANY AND
ITS SUBSIDIARIES, UNLESS OTHERWISE STATED OR INDICATED BY THE CONTEXT. CERTAIN
TERMS USED HEREIN RELATING TO THE OIL AND GAS INDUSTRY ARE DEFINED IN THE
"GLOSSARY" INCLUDED ELSEWHERE IN THIS PROSPECTUS. INVESTORS SHOULD CAREFULLY
CONSIDER THE INFORMATION SET FORTH IN "RISK FACTORS."

THE COMPANY

St. Mary Land & Exploration 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 tri-state area of southern
Arkansas, northern Louisiana and eastern Texas ("ArkLaTex"); 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.

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.

3
<PAGE>

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.

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 seven 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.

CORE OPERATING AREAS

Continuing investment in technical staff, oil and gas leases, geological
studies, seismic data and advanced well completion techniques has generated
expanded exploration, development and acquisition opportunities for St. Mary in
each of its core operating areas.

MID-CONTINENT REGION. St. Mary has been active in the Mid-Continent region
since 1973 where its operations are managed by the Company's 25-person, Tulsa,
Oklahoma office. During 1996 the Company participated in 75 gross wells and
recompletions, including 17 Company-operated wells. The Mid-Continent region
accounted for 34% of the Company's estimated net proved reserve volumes as of
December 31, 1996 (92% proved developed and 94% gas). The Company's 1997
Mid-Continent capital budget of approximately $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. The Company
has arranged commitments for three drilling rigs in the Mid-Continent region
throughout 1997 and plans to drill as operator 25 to 30 gross wells in the area,
and to participate in an additional 30 gross wells. In addition, St. Mary has a
24.0% working interest in a large-target prospect in the Cotton Valley Reef play
of east Texas.

ARKLATEX REGION. St. Mary first acquired an interest in the ArkLaTex region
in 1992, and has since completed eight additional acquisitions of producing
properties and undertaken an active program of

4
<PAGE>
development and exploration in the area. St. Mary's existing lease position
totals 46,000 gross acres and the Company owns over 6,000 miles of proprietary
2-D seismic data in the region. The ArkLaTex region, which accounted for 27% of
the Company's estimated net proved reserve volumes as of December 31, 1996 (58%
proved developed and 87% gas), is managed by St. Mary's 12-person office in
Shreveport, Louisiana. In 1996 the Company made a significant discovery in its
Box Church Field in east Texas which added 26.4 Bcf of estimated net proved
reserves. The Company's 1997 capital budget provides $7.5 million for ongoing
development and exploration in the region, including a 12-well development
program in the Box Church Field.

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 in the region. The south Louisiana region accounted for 5% of the
Company's estimated net proved reserve volumes as of December 31, 1996 (100%
proved developed and 84% gas). St. Mary owns approximately 24,900 acres of fee
lands and associated oil and gas royalty interests on these lands which include
the Bayou Sale, Horseshoe Bayou and Belle Isle Fields. In granting new leases on
its fee lands the Company seeks to retain the right to participate as up to a
25% working interest owner in new wells. The completion and interpretation of
two 3-D seismic surveys by the Company's lessees and the completion of St.
Mary's own detailed geological and engineering studies have contributed to
renewed development and exploration activity on the Company's fee lands,
including additional drilling and recompletion work as well as exploration
interest in deeper, untested horizons. St. Mary's historical presence in south
Louisiana, its established network of industry relationships and its extensive
technical database have enabled the Company to assemble an inventory of
large-target prospects in this region, including two deep gas prospects which
are located on the Company's fee lands and are scheduled to be tested during
1997.

WILLISTON BASIN REGION. The Williston Basin region accounted for 20% of the
Company's estimated net proved reserve volumes as of December 31, 1996 (93%
proved developed and 90% oil). St. Mary's operations in this basin are conducted
through Panterra which owns interests in approximately 360 gross producing wells
located in 60 fields. Since 1991, the Company's investment in Panterra has
included participation in 11 Panterra-operated development and exploration wells
with a 100% success rate. The Company's successful exploration and development
efforts in this basin have resulted from the application of state-of-the-art 3-D
seismic imaging to delineate structural and stratigraphic features in existing
fields. In 1994, the Company conducted a 4.5 square mile 3-D seismic survey at
the North Bainville Field which led to the successful 1995 extension of the
field in the Red River formation. During 1996, St. Mary completed an additional
four wells at North Bainville and conducted an additional 21 square mile 3-D
seismic survey in the area. The Company has also begun to apply the experience
gained at North Bainville to other fields in the basin where Panterra holds
significant leasehold interests, including the Brush Lake and Nameless Fields
where Panterra completed separate 3-D seismic surveys in late 1995 and early
1996. The 1997 capital budget provides $6 million for ongoing development and
exploration in the basin.

PERMIAN BASIN REGION. The Permian Basin of New Mexico and west Texas is the
Company's newest area of concentration. Management believes this region provides
St. Mary with a solid base of long-lived oil reserves, promising longer-term
exploration and development prospects and 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 30,450 acre top lease in Ward and
Winkler Counties, Texas which the Company believes to hold significant
exploration potential in the virtually untested deeper formations on the lease.
St. Mary increased its holdings in the region during 1996 with the acquisition
of a 90% interest in the producing properties of Siete Oil and Gas Company for
$10.0 million. The Permian Basin region accounted for 12% of the Company's
estimated net proved reserve volumes as of December 31, 1996 (96% proved
developed and 81% oil).

5
<PAGE>
RECENT DEVELOPMENTS

RUSSIAN PARTNERSHIP INTEREST. 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 Partnership
Interest"). 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 the form of a retained production payment of approximately
$10.3 million plus interest at 10% per annum. See "Business and
Properties--Other Activities."

RISK FACTORS

See "Risk Factors" for a discussion of certain factors that should be
considered in connection with an investment in the Common Stock offered hereby.

THE OFFERING

<TABLE>
<S> <C>
Common Stock offered by the
Company......................... 2,000,000

Common Stock to be outstanding
after the offering.............. 10,762,814(1)

Use of Proceeds................... The net proceeds of the offering, together with
internally generated cash flows and borrowings under the
Company's credit facility with two commercial banks
("Credit Facility"), will be utilized to fund the
Company's exploration and development activities and
potential acquisitions and for general corporate
purposes. Pending utilization of the net proceeds, the
funds will be used to repay revolving bank loans and to
the extent that net proceeds are in excess of amounts
outstanding under the Credit Facility, the Company will
invest in short-term investments.

Nasdaq National Market Symbol..... "MARY"
</TABLE>

- ------------------------

(1) Excludes 97,495 shares of Common Stock issuable upon exercise of options
outstanding as of January 27, 1997 and 256,598 shares underlying options to
be issued in exchange for the Company's Stock Appreciation Rights ("SAR").
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations."

6
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE DATA)

The following table sets forth certain consolidated financial data for the
Company as of and for each of the periods indicated. The financial data for each
year in the three-year period ended December 31, 1995, are derived from the
audited financial statements of the Company. The financial data for the nine
month periods ended September 30, 1995 and 1996 are derived from the Company's
unaudited financial statements which, in the opinion of management of the
Company, have been prepared on the same basis as the annual consolidated
financial statements and include all adjustments (consisting of only normal
recurring adjustments) necessary for a fair presentation of the financial data
for such periods. 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 Prospectus. The results for the nine
months ended September 30, 1996 are not necessarily indicative of results for
the full year. Historical financial data are not necessarily predictive of the
Company's future results of operations and financial condition.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- ------------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- -------------
<S> <C> <C> <C> <C> <C>
(UNAUDITED)
INCOME STATEMENT DATA:
Operating revenues:
Oil and gas production................................ $ 38,208 $ 38,239 $ 36,569 $ 25,860 $ 39,689
Gas contract settlements and other.................... 424 6,546 2,081 1,580 490
--------- --------- --------- --------- -------------
Total operating revenues................................ 38,632 44,785 38,650 27,440 40,179
--------- --------- --------- --------- -------------
Operating expenses:
Oil and gas production................................ 9,341 10,496 10,646 7,676 9,262
Depletion, depreciation and amortization.............. 8,775 10,134 10,227 7,184 9,144
Impairment of proved properties (1)................... 3,498 4,219 2,676 1,673 --
Exploration........................................... 5,457 8,104 5,073 3,683 5,688
Abandonment and impairment of unproved properties..... 1,020 1,023 2,359 759 1,240
General and administrative (2)........................ 4,712 5,261 5,328 4,129 5,066
Other................................................. 1,297 841 731 470 64
--------- --------- --------- --------- -------------
Total operating expenses................................ 34,100 40,078 37,040 25,574 30,464
--------- --------- --------- --------- -------------
Income from operations.................................. 4,532 4,707 1,610 1,866 9,715
Non-operating expense................................... 62 525 896 514 1,180
Income tax expense (benefit)............................ 1,065 445 (723) (72) 2,773
--------- --------- --------- --------- -------------
Income from continuing operations....................... 3,405 3,737 1,437 1,424 5,762
Gain on sale of discontinued operations, net of income
taxes................................................. -- -- 306 306 159
Cumulative effect of change in accounting principle..... 300 -- -- -- --
--------- --------- --------- --------- -------------
Net income.............................................. $ 3,705 $ 3,737 $ 1,743 $ 1,730 $ 5,921
--------- --------- --------- --------- -------------
--------- --------- --------- --------- -------------
Net income per common share:
Income from continuing operations..................... $ 0.39 $ 0.43 $ 0.17 $ 0.17 $ 0.66
Gain on sale of discontinued operations............... -- -- 0.03 0.03 0.02
Cumulative effect of change in accounting principle... 0.03 -- -- -- --
--------- --------- --------- --------- -------------
Net income per share.................................... $ 0.42 $ 0.43 $ 0.20 $ 0.20 $ 0.68
--------- --------- --------- --------- -------------
--------- --------- --------- --------- -------------
Cash dividends per share................................ $ 0.16 $ 0.16 $ 0.16 $ 0.12 $ 0.12
Weighted average common shares outstanding.............. 8,763 8,763 8,760 8,760 8,759
</TABLE>

7
<PAGE>

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- ------------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- -------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
OTHER DATA:
EBITDA (3).............................................. $ 13,307 $ 14,841 $ 11,837 $ 9,050 $ 18,859
Net cash provided by operating activities............... 19,675 20,271 17,713 11,755 17,110
Capital and exploration expenditures (4)................ 22,787 30,934 32,419 23,591 36,680
</TABLE>

<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
--------------------------
ACTUAL AS ADJUSTED(5)
---------- --------------
<S> <C> <C>
(UNAUDITED)
BALANCE SHEET DATA:
Working capital....................................................................... $ 6,419 $ 28,019
Net property and equipment............................................................ 92,804 92,804
Total assets.......................................................................... 132,680 154,280
Long-term debt........................................................................ 36,324 10,974
Total stockholders' equity............................................................ 71,140 118,090
</TABLE>

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(1) 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 $1.0
million in the fourth quarter of 1995.

(2) Includes compensation expense recognized under the Company's SAR plan of
$222,191, $268,286 and $220,247 in 1993, 1994 and 1995, respectively, and
$242,538 and $604,000 during the nine months ended September 30, 1995 and
1996, respectively. In November 1996, the Company replaced the SAR plan with
a stock option plan, and accordingly SAR expense will be significantly lower
in 1997. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Accounting Matters."

(3) 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.

(4) Excludes certain international exploration costs. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Capital and Exploration
Expenditures."

(5) As adjusted to give effect to the sale of 2,000,000 shares of Common Stock
offered hereby and the application of the estimated net proceeds of
approximately $47.0 million. See "Use of Proceeds."

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<PAGE>
SUMMARY RESERVE DATA

The following table sets forth summary information with respect to the
Company's estimated net proved reserves as of December 31, 1994, 1995 and 1996,
as prepared by Ryder Scott Company ("Ryder Scott"), independent petroleum
engineers, and by the Company.

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------
1994 1995 1996
--------- ---------- ----------
<S> <C> <C> <C>
RESERVE DATA: (1)
Oil (MBbls).................................................................... 6,677 7,509 10,691
Gas (MMcf)..................................................................... 62,515 75,705 127,057
MBOE........................................................................... 17,096 20,127 31,867
PV-10 Value (in thousands)..................................................... $ 84,688 $ 120,192 $ 296,461
Proved developed reserves...................................................... 93% 89% 84%
Production replacement......................................................... 207% 203% 422%
Reserve Life (years)........................................................... 5.6 6.5 8.4
</TABLE>

- ------------------------

(1) For limitations on the accuracy and reliability of estimated net proved
reserves and future net revenue estimates, see "Risk Factors--Uncertainty of
Estimates of Net Proved Reserves." See also "Business and
Properties--Estimated Net Proved Reserves." Reserve data attributable to the
Company's Russian Partnership Interest have been excluded from this table.
Effective February 12, 1997, the Company sold its Russian Partnership
Interest. See "Business and Properties--Other Activities."

SUMMARY OPERATING DATA

Average net daily production:
Oil (Bbls)............................................... 2,319 2,567 2,852 2,798 3,156
Gas (Mcf)................................................ 30,539 34,458 33,973 32,824 41,053
BOE...................................................... 7,409 8,310 8,514 8,269 9,998

Average sales price:(2)
Oil (per Bbl)............................................ $ 16.18 $ 14.95 $ 16.37 $ 16.33 $ 18.26
Gas (per Mcf)............................................ $ 2.20 $ 1.93 $ 1.56 $ 1.49 $ 2.12

Additional per BOE data:
Lease operating expense.................................. $ 2.42 $ 2.54 $ 2.49 $ 2.51 $ 2.28
Production taxes......................................... $ 1.04 $ 0.92 $ 0.93 $ 0.89 $ 1.10
Depletion, depreciation and amortization................. $ 3.25 $ 3.34 $ 3.28 $ 3.18 $ 3.34
</TABLE>

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(1) Excludes operating data attributable to the Company's Russian Partnership
Interest.

(2) Includes the effects of the Company's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Overview."

9
<PAGE>
RISK FACTORS

IN ADDITION TO THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS, THE
FOLLOWING FACTORS RELATING TO THE COMPANY AND THIS OFFERING SHOULD BE CONSIDERED
CAREFULLY WHEN EVALUATING AN INVESTMENT IN THE SHARES OF COMMON STOCK OFFERED
HEREBY.

This Prospectus, including the documents incorporated by reference, 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 (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements, other than statements of
historical facts, included in this Prospectus 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, including the risk factors
discussed below, 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. Prospective investors 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.

VOLATILITY OF OIL AND GAS PRICES AND MARKETS

The Company's revenues, cash flow, profitability and future rate of growth
are substantially dependent upon prevailing prices for oil and gas. The
Company's ability to maintain or increase its borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent on oil
and gas prices. Historically, oil and gas prices and markets have been volatile
and are likely to continue to be volatile in the future. Prices for oil and gas
are subject to wide fluctuations in response to relatively minor changes in
supply of and demand for oil and gas, market uncertainty and a variety of
additional factors that are beyond the control of the Company. These factors
include international political conditions, the domestic and foreign supply of
oil and gas, the level of consumer demand, weather conditions, domestic and
foreign governmental regulations, the price and availability of alternative
fuels and overall economic conditions. In addition, various factors, including
the availability and capacity of gas gathering systems and pipelines, the effect
of federal and state regulation of production and transportation, general
economic conditions, changes in supply due to drilling by other producers and
changes in demand may adversely affect the Company's ability to market its oil
and gas production. Any significant decline in the price of oil or gas would
adversely affect the Company's revenues, operating income, cash flows and
borrowing capacity and may require a reduction in the carrying value of the
Company's oil and gas properties and its planned level of capital expenditures.

REPLACEMENT OF RESERVES

The Company's future success depends upon its ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable.
Except to the extent that the Company conducts successful exploration or
development activities or acquires properties containing proved reserves, the
estimated net proved reserves of the Company will generally decline as reserves
are produced. There can be no assurance that the Company's planned development
and exploration projects and acquisition activities will result in significant
additional reserves or that the Company will have continuing success drilling
productive wells at

10
<PAGE>
economic Finding Costs. If prevailing oil and gas prices were to increase
significantly, the Company's Finding Costs to add new reserves could increase.
The drilling of oil and gas wells involves a high degree of risk, especially the
risk of dry holes or of wells that are not sufficiently productive to provide an
economic return on the capital expended to drill the wells. In addition, the
Company's drilling operations may be curtailed, delayed or cancelled as a result
of numerous factors, including title problems, weather conditions, compliance
with governmental requirements and shortages or delays in the delivery of
equipment and availability of drilling rigs. Certain of the Company's oil and
gas properties are operated by third parties and as a result the Company has
limited control over the nature and timing of exploration and development of
such properties or the manner in which operations are conducted on such
properties. A significant portion of the Company's cash flow is attributable to
royalty interests on its south Louisiana fee properties. Without continued
exploration on and development of the fee properties, which the Company has only
a limited ability to control, production and cash flow from these properties
will decline.

UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES

This Prospectus, including the documents incorporated by reference, includes
estimates of the Company's net proved oil and gas reserves and the future net
revenues from those reserves which have been prepared by the Company and its
independent petroleum engineers. There are numerous uncertainties inherent in
estimating quantities of proved oil and gas reserves, including many factors
beyond the control of the Company. Reserve engineering is a subjective process
of estimating the underground accumulations of oil and gas that cannot be
measured in an exact manner. The estimates in this Prospectus are based on
various assumptions required by the Securities and Exchange Commission (the
"Commission"), including constant oil and gas prices, operating expenses and
capital expenditures, and, therefore, are inherently imprecise indications of
future net revenues. Actual future production, revenues, taxes, operating
expenses, development expenditures and quantities of recoverable oil and gas
reserves may vary substantially from those assumed in the estimates. Any
significant variance in these assumptions could materially affect the estimated
quantity and value of reserves set forth in this Prospectus. In addition, the
Company's reserves may be subject to downward or upward revision based upon
production history, results of future development, availability of funds to
acquire additional reserves, prevailing oil and gas prices and other factors. In
addition, the calculation of the estimated present value of the future net
revenue using a 10% discount rate as required by the Commission is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with the Company's reserves or the
oil and gas industry in general. See "Business and Properties--Estimated Net
Proved Reserves."

It is also possible that reserve engineers may make different estimates of
reserves and future net revenues based on the same available data. In
calculating reserves on a BOE basis, gas was converted to oil at the ratio of
six Mcf of gas to one Bbl of oil. While this convention approximates the energy
equivalent of oil and gas on a Btu basis, it may not represent the relative
prices received by the Company on the sale of its oil and gas production.

The estimated future net revenues attributable to the Company's net proved
reserves are prepared in accordance with Commission guidelines, and are not
intended to reflect the fair market value of the Company's reserves. In
accordance with the rules of the Commission, the Company's reserve estimates are
prepared using period end prices received for oil and gas. For year end 1996,
these prices were materially higher than for year end 1995 and 1994. Future
reductions in prices below those prevailing at year end 1996 would result in the
estimated quantities and present values of the Company's reserves being reduced.

OPERATING HAZARDS AND UNINSURED RISKS

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

11
<PAGE>
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.

SUBSTANTIAL CAPITAL REQUIREMENTS

The Company makes, and will continue to make, substantial capital
expenditures for the development, exploration and acquisition and production of
oil and gas reserves. Historically, the Company has financed these expenditures
primarily with the proceeds of bank borrowings, the sale of Common Stock and
cash generated by operations. Management believes that the net proceeds of this
offering, bank borrowings and cash generated from operations will be sufficient
to fund its planned operations through 1997. If revenues or the Company's
borrowing base decrease as a result of lower oil and gas prices, operating
difficulties or declines in reserves, the Company may have limited ability to
fund the capital requirements to undertake or complete future development and
exploration programs. There can be no assurance that additional debt or equity
financing or cash generated by operations will be available to meet these
requirements. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Liquidity and Capital Resources."

ACQUISITION RISKS

The Company intends to continue acquiring oil and gas properties. See
"Business and Properties-- Business Strategy." Although the Company performs a
review of the acquired properties that it believes is consistent with industry
practices, such reviews are inherently incomplete. It generally is not feasible
to review in depth every individual property involved in each acquisition.
Ordinarily, the Company will focus its due diligence efforts on the higher
valued properties and will sample the remainder. However, even an in-depth
review of all properties and records may not necessarily reveal existing or
potential problems nor will it permit a buyer to become sufficiently familiar
with the properties to assess fully their deficiencies and capabilities.
Inspections may not be performed on every well, and structural or environmental
problems, such as ground water contamination, are not necessarily observable
even when an inspection is undertaken. The Company may be required to assume
preclosing liabilities, including environmental liabilities, and may acquire
interests in properties on an "as is" basis. There can be no assurance that the
Company's acquisitions will be successful.

RISKS OF FIXED PRICE SALES AND HEDGING CONTRACTS

The Company manages the risk associated with fluctuations in the price of
gas and oil, primarily through certain fixed price sales and hedging contracts.
The Company's price risk management strategy is intended to reduce the Company's
sensitivity to changes in market prices of oil and gas, but is subject to a
number of other risks. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Overview."

COMPETITION

The oil and gas industry is highly competitive. The Company competes in the
areas of property acquisitions and the development, production and marketing of
oil and gas with major oil companies, other independent oil and gas concerns and
individual producers and operators. Many of these competitors have substantially
greater financial and other resources than the Company. See "Business and
Properties-- Competition."

12
<PAGE>
GOVERNMENTAL REGULATION AND ENVIRONMENTAL RISKS

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.

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.

CONTINUING CONTROL BY EXISTING STOCKHOLDERS

The Chairman of the Board of Directors and members of his extended family
own approximately 41% of the outstanding Common Stock of the Company. While no
formal arrangements exist, these extended family members may be inclined to act
in concert with the Chairman on matters related to control of St. Mary,
including for example, the election of directors or relative to an unsolicited
bid to acquire the Company. While the percentage ownership of the extended
family of the Chairman will be reduced by approximately 9% after the offering,
the Chairman and his extended family may be able to control or influence matters
presented to the stockholders.

RISKS SPECIFIC TO THE COMPANY'S INVESTMENT IN OTHER ACTIVITIES

The Company has invested a total of approximately $5.9 million to acquire a
49.9% interest in Summo Minerals Corporation ("Summo Minerals"). Summo Minerals
is engaged in the business of development of certain copper projects, the
principal one being located in southeast Utah. If Summo Minerals is unable to
raise the capital needed to fund the development of its first project, the
Company currently expects to invest no more than approximately $1.0 to $2.0
million in Summo Minerals in 1997. There can be no

13
<PAGE>

assurance that the Company's investment in Summo Minerals will be successful or
that the Company will ever recover its investment. See "Business and
Properties--Other Activities."

USE OF PROCEEDS

The net proceeds from this offering are estimated to be $47.0 million ($54.0
million if the Underwriters' over-allotment option is exercised in full), after
deducting the underwriting discount and estimated offering expenses. The Company
intends to use such net proceeds, together with internally generated funds and
borrowings under the Credit Facility and Panterra's bank credit facility
("Panterra Credit Facility"), to fund its 1997 capital budget estimated to total
$65.0 million and for general corporate purposes.

The following table sets forth the estimated allocation of the Company's
1997 capital budget (in millions):

<TABLE>
<S> <C>
Ongoing Exploration and Development Projects:
Mid-Continent Region............................... $ 26.5
ArkLaTex Region.................................... 7.5
Williston Basin.................................... 6.0
Permian Basin...................................... 2.0
Other.............................................. 1.0
Large-Target Exploration Projects.................... 7.0
Acquisitions......................................... 15.0
---------
Total................................................ $ 65.0
---------
---------
</TABLE>

Pending use of funds, the Company will use the net proceeds of this offering
to repay borrowings under its Credit Facility. To the extent that net proceeds
are in excess of amounts outstanding under the Credit Facility, the Company will
invest in short-term investments. Amounts repaid under the revolving loan
provisions of the Credit Facility, which expire in June 1999, will be available
for re-borrowing (subject to borrowing base limitations and other restrictions)
until the Credit Facility expires, or until borrowings are converted, at the
option of the Company, into a term loan if earlier. As of January 27, 1997,
borrowings of $37.1 million were outstanding under the Credit Facility, with a
weighted average interest rate of 6.5%. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Credit Facility."

14
<PAGE>
CAPITALIZATION

The following table sets forth the capitalization of the Company as of
September 30, 1996 and as adjusted to reflect the sale of the 2,000,000 shares
of Common Stock offered by the Company hereby and the application of the
estimated net proceeds of $47.0 million therefrom as described under "Use of
Proceeds." This table should be read in conjunction with the Consolidated
Financial Statements and notes thereto included in this Prospectus.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
-----------------------
ACTUAL AS ADJUSTED
---------- -----------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents...................................................... $ 4,405 $ 26,005
---------- -----------
---------- -----------
Long-term debt:
Credit Facility(1)........................................................... 25,350 --
Panterra Credit Facility(2).................................................. 10,974 10,974
---------- -----------
Total long-term debt........................................................... 36,324 10,974

Stockholders' equity(3):
Common Stock, $.01 par value, 15,000,000 shares authorized; 8,759,214 shares
issued and outstanding; 10,759,214 shares as adjusted...................... 88 108
Additional paid-in capital................................................... 15,800 62,730
Retained earnings............................................................ 55,248 55,248
Unrealized gain on marketable equity securities--available for sale.......... 4 4
---------- -----------
Total stockholders' equity..................................................... 71,140 118,090
---------- -----------
Total capitalization........................................................... $ 107,464 $ 129,064
---------- -----------
---------- -----------
</TABLE>

- ------------------------

(1) As of January 27, 1997, the Credit Facility had an outstanding balance of
$37.1 million.

(2) The Company has a 74% general partnership interest in Panterra and
proportionately consolidates the outstanding balance of the Panterra
Facility. See Notes 1 and 5 to the Consolidated Financial Statements as of
December 31, 1995 and 1994, and for each of the three years in the period
ended December 31, 1995 included herein. As of January 27, 1997 the Panterra
Credit Facility had an outstanding balance of $13.1 million of which the
Company's pro rata share was $9.7 million.

(3) Excludes 97,495 shares of Common Stock issuable upon exercise of options
outstanding as of January 27, 1997 and 256,598 shares underlying options to
be issued in exchange for the Company's SAR. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."

15
<PAGE>
PRICE RANGE OF COMMON STOCK

The Company's Common Stock is traded on the Nasdaq National Market under the
symbol "MARY." The following table sets forth the high and low closing sale
prices for the periods presented:

<TABLE>
<CAPTION>
HIGH LOW
-------- --------
<S> <C> <C>
Year Ended December 31, 1995:
First Quarter......................... $ 14 $ 12 1/2
Second Quarter........................ 13 3/8 10 7/8
Third Quarter......................... 14 7/8 12 7/8
Fourth Quarter........................ 15 13 1/4
Year Ended December 31, 1996:
First Quarter......................... $ 16 5/8 $ 13 1/2
Second Quarter........................ 17 7/8 15 7/8
Third Quarter......................... 17 14 1/4
Fourth Quarter........................ 27 3/8 16 1/2
Year Ending December 31, 1997:
First Quarter (through February 20,
1997)............................... $ 30 $ 24 1/2
</TABLE>

On February 20, 1997, the closing sale price for the Common Stock as
reported on the Nasdaq National Market was $25 3/4 per share. As of January 1,
1997, the number of record holders of the Company's Common Stock was 154.
Management believes, after inquiry, that the number of beneficial owners of the
Company's Common Stock is in excess of 1,100.

DIVIDEND POLICY

The Company has paid cash dividends on its Common Stock for the past 57
consecutive years. For the last nine years, the Company has paid cash dividends
of $0.16 per share per year. The Company increased its quarterly dividend to
$0.05 per share effective with the quarterly dividend declared in January 1997
and payable in February 1997. The Company currently intends to continue to pay
comparable annual cash dividends on its outstanding shares of Common Stock on a
quarterly basis. The terms of the Company's Credit Facility contain restrictions
on the payment of cash dividends to holders of Common Stock. Accordingly, the
Company's ability to pay cash dividends will depend upon such restrictions and
the Company's results of operations, financial condition, capital requirements
and other factors deemed relevant by the Board of Directors.

16
<PAGE>
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, 1995, were derived from the Consolidated
Financial Statements of the Company which have been audited by Coopers & Lybrand
L.L.P., independent accountants. The financial data for the nine month periods
ended September 30, 1995 and 1996 are derived from the Company's unaudited
financial statements which, in the opinion of management of the Company, have
been prepared on the same basis as the annual consolidated financial statements
and include all adjustments (consisting of only normal recurring adjustments)
necessary for a fair presentation of the financial data for such periods. 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
Prospectus. The results for the nine months ended September 30, 1996 are not
necessarily indicative of results for the full year. Historical financial data
are not necessarily predictive of the Company's future results of operations and
financial condition.

<TABLE>
<CAPTION>
NINE
MONTHS
ENDED
SEPTEMBER
YEAR ENDED DECEMBER 31, 30,
----------------------------------------------------- ---------
1991 1992 1993 1994 1995
--------- --------- --------- --------- --------- 1995
---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
(IN THOUSANDS, EXCEPT PER SHARE DATA)
INCOME STATEMENT DATA:
Operating revenues:
Oil and gas production.................................. $ 27,015 $ 35,245 $ 38,208 $ 38,239 $ 36,569 $ 25,860
Gas contract settlements and other...................... 773 15,413 424 6,546 2,081 1,580
--------- --------- --------- --------- --------- ---------
Total operating revenues.................................. 27,788 50,658 38,632 44,785 38,650 27,440
--------- --------- --------- --------- --------- ---------
Operating expenses:
Oil and gas production.................................. 4,522 7,793 9,341 10,496 10,646 7,676
Depletion, depreciation and amortization................ 5,586 6,213 8,775 10,134 10,227 7,184
Impairment of proved properties(1)...................... 790 1,565 3,498 4,219 2,676 1,673
Exploration............................................. 4,133 3,615 5,457 8,104 5,073 3,683
Abandonment and impairment of unproved properties....... 2,434 1,264 1,020 1,023 2,359 759
General and administrative(2)........................... 3,187 4,544 4,712 5,261 5,328 4,129
Gas contract disputes and other......................... 750 1,332 638 493 152 184
Loss (income) in equity investees....................... -- 1,026 659 348 579 286
--------- --------- --------- --------- --------- ---------
Total operating expenses.................................. 21,402 27,352 34,100 40,078 37,040 25,574
--------- --------- --------- --------- --------- ---------
Income from operations.................................... 6,386 23,306 4,532 4,707 1,610 1,866
Non-operating expense..................................... 1,000 791 62 525 896 514
Income tax expense (benefit).............................. 1,874 7,328 1,065 445 (723) (72)
--------- --------- --------- --------- --------- ---------
Income from continuing operations......................... 3,512 15,187 3,405 3,737 1,437 1,424
Gain (loss) on sale of discontinued operations, net of
income taxes............................................. (312) 430 -- -- 306 306
Income before cumulative effect of change in accounting
principle................................................ 3,200 15,617 3,405 3,737 1,743 1,730
Cumulative effect of change in accounting principle....... -- -- 300 -- -- --
--------- --------- --------- --------- --------- ---------
Net income................................................ $ 3,200 $ 15,617 $ 3,705 $ 3,737 $ 1,743 $ 1,730
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Net income per common share:
Income from continuing operations....................... $ 0.49 $ 2.10 $ 0.39 $ 0.43 $ 0.17 $ 0.17
Gain (loss) on sale of discontinued operations.......... (0.04) 0.06 -- -- 0.03 0.03
Cumulative effect of change in accounting principle..... -- -- 0.03 -- -- --
--------- --------- --------- --------- --------- ---------
Net income per share...................................... $ 0.45 $ 2.16 $ 0.42 $ 0.43 $ 0.20 $ 0.20
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------

Cash dividends per share.................................. $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.12
Weighted average common shares outstanding................ 7,172 7,233 8,763 8,763 8,760 8,760

1996
---------

<S> <C>

INCOME STATEMENT DATA:
Operating revenues:
Oil and gas production.................................. $ 39,689
Gas contract settlements and other...................... 490
---------
Total operating revenues.................................. 40,179
---------
Operating expenses:
Oil and gas production.................................. 9,262
Depletion, depreciation and amortization................ 9,144
Impairment of proved properties(1)...................... --
Exploration............................................. 5,688
Abandonment and impairment of unproved properties....... 1,240
General and administrative(2)........................... 5,066
Gas contract disputes and other......................... 111
Loss (income) in equity investees....................... (47)
---------
Total operating expenses.................................. 30,464
---------
Income from operations.................................... 9,715
Non-operating expense..................................... 1,180
Income tax expense (benefit).............................. 2,773
---------
Income from continuing operations......................... 5,762
Gain (loss) on sale of discontinued operations, net of
income taxes............................................. 159
Income before cumulative effect of change in accounting
principle................................................ 5,921
Cumulative effect of change in accounting principle....... --
---------
Net income................................................ $ 5,921
---------
---------
Net income per common share:
Income from continuing operations....................... $ 0.66
Gain (loss) on sale of discontinued operations.......... 0.02
Cumulative effect of change in accounting principle..... --
---------
Net income per share...................................... $ 0.68
---------
---------
Cash dividends per share.................................. $ 0.12
Weighted average common shares outstanding................ 8,759
</TABLE>

17
<PAGE>

BALANCE SHEET DATA (END OF PERIOD):
Working capital.......................................... $ 5,709 $ 17,913 $ 15,187 $ 9,444 $ 3,102 $ 2,982
Net property and equipment............................... 39,306 46,998 51,381 59,655 71,645 70,279
Total assets............................................. 53,781 75,896 81,797 89,392 96,126 91,144
Long-term debt........................................... 15,775 5,000 7,400 11,130 19,602 14,766
Total stockholders' equity............................... 31,117 61,362 63,635 66,034 66,282 66,531

1996
----------

<S> <C>

OTHER DATA:
EBITDA(3)................................................ $ 18,859
Net cash provided by operating activities................ 17,110
Capital and exploration expenditures(4).................. 36,680
BALANCE SHEET DATA (END OF PERIOD):
Working capital.......................................... $ 6,419
Net property and equipment............................... 92,804
Total assets............................................. 132,680
Long-term debt........................................... 36,324
Total stockholders' equity............................... 71,140
</TABLE>

- ------------------------------

(1) In March 1995, the FASB issued 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 $1.0 million in the fourth
quarter of 1995.

(2) Includes compensation expense recognized under the Company's SAR plan of
$222,191, $268,286 and $220,247 in 1993, 1994 and 1995, respectively, and
$242,538 and $604,000 during the nine months ended September 30, 1995 and
1996, respectively. In November 1996, the Company replaced the SAR plan with
a stock option plan, and accordingly the SAR expense will be significantly
lower in 1997. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Accounting Matters."

18
<PAGE>
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 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 Partnership Interest.
The Company accounts for its Russian Partnership Interest 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 Partnership Interest.

The Company uses the successful efforts method to account for its investment
in oil and gas properties whereby costs of productive wells, developmental dry
holes and productive leases are capitalized and amortized using the
units-of-production method based on estimated net proved reserves. The costs of
development wells are capitalized, whether productive or nonproductive.
Exploratory drilling costs are initially capitalized but charged to expense if
and when the well is determined to be unsuccessful. Geological and geophysical
costs and the costs of carrying and retaining undeveloped properties are
expensed as incurred.

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. As of January 15, 1997, the Company had 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.

19
<PAGE>
RESULTS OF OPERATIONS

The following table sets forth selected operating data for the periods and
upon the basis indicated:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
OPERATING DATA(1):
Net Production:
Oil (MBbls)............................................. 846 937 1,044 764 865
Gas (MMcf).............................................. 11,147 12,577 12,434 8,961 11,249
MBOE.................................................... 2,704 3,033 3,116 2,258 2,739
Average sales price(2):
Oil (per Bbl)........................................... $ 16.18 $ 14.95 $ 16.37 $ 16.33 $ 18.26
Gas (per Mcf)........................................... $ 2.20 $ 1.93 $ 1.56 $ 1.49 $ 2.12
Additional per BOE data:
Lease operating expenses................................ $ 2.42 $ 2.54 $ 2.49 $ 2.51 $ 2.28
Production taxes........................................ $ 1.04 $ 0.92 $ 0.93 $ 0.89 $ 1.10
Depletion, depreciation and amortization................ $ 3.25 $ 3.34 $ 3.28 $ 3.18 $ 3.34
</TABLE>

- ------------------------

(1) Excludes operating data attributable to the Company's Russian Partnership
Interest.

(2) Includes the effects of the Company's hedging activities.

NINE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED WITH NINE MONTHS ENDED SEPTEMBER
30, 1995

REVENUES. Oil and gas production revenues increased $13.8 million, or 53%
to $39.7 million for the nine months ended September 30, 1996 compared with
$25.9 million in the 1995 period. Oil production volumes increased 13% while gas
production increased 26% for the first nine months of 1996 compared with the
1995 period. Average net daily production was 10.0 MBOE for the nine months
ended September 30, 1996 compared to 8.3 MBOE in the 1995 period. This
production increase resulted from new properties acquired and drilled during the
past year. The average oil price for the nine months ended September 30, 1996
increased 12% to $18.26 per Bbl, while gas prices increased 42% to $2.12 per
Mcf, from their respective 1995 levels. The Company hedged approximately 68% of
its 1996 oil production at an average NYMEX price of $19.17 per Bbl and 18% of
its 1996 gas production at an average $1.91 per MMBtu. During the nine months
ended September 30, 1996, the Company incurred total hedging losses of
$1,493,000, including oil hedge losses of $846,000, or $0.98 per Bbl, and gas
hedge losses of $647,000, or $0.06 per Mcf. Revenues for the 1995 period also
included a gain of $1.1 million on the sale of producing properties.

OIL AND GAS PRODUCTION COSTS. Oil and gas production costs consist of lease
operating expense and production taxes. Total production costs increased $1.6
million or 21% to $9.3 million for the nine months ended September 30, 1996
compared with the 1995 period. The lease operating expense per BOE was $2.28 for
the nine months ended September 30, 1996 compared with $2.51 for the first nine
months of 1995 primarily due to higher south Louisiana royalty production volume
in 1996 and lower 1995 sales volumes stemming from low gas prices.

DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT. Depreciation,
depletion and amortization expense ("DD&A") increased $2.0 million or 27% to
$9.1 million for the nine months ended September 30, 1996 compared with $7.2
million for the same period in 1995 due to increased production from new
drilling and reserve acquisitions. DD&A per BOE was $3.34 in 1996 compared to
$3.18 for the same period in 1995 because of the higher unit rate on reserve
acquisitions. There was no impairment of proved properties for the nine months
ended September 30, 1996 compared to $1.7 million for the same period in 1995
due to high cost marginal wells and low natural gas prices.

20
<PAGE>
Abandonment and impairment expenses for unproved properties was $1.2 million
for the nine months ended September 30, 1996 compared with $759,000 for the
respective 1995 period.

EXPLORATION. Exploration expense increased $2.0 million or 54% to $5.7
million for the nine months ended September 30, 1996 compared with $3.7 million
in the 1995 period as a result of higher exploratory dry hole expense from
increased drilling activity and a large 3-D seismic survey conducted in 1996.

GENERAL AND ADMINISTRATIVE. General and administrative expense increased
$937,000 or 23% to $5.1 million for the nine months ended September 30, 1996
compared to $4.1 million in the comparable period in 1995 due to higher
compensation costs, professional fees and a $361,000 increase in the expense
associated with the Company's SAR Plan. In the fourth quarter of 1996, the
Company expects to recognize an additional expense of approximately $1.0 million
associated with the SAR plan. On November 21, 1996, the Company terminated the
SAR plan and adopted in lieu thereof a stock option plan and, accordingly, SAR
expense will be substantially lower in 1997.

GAS CONTRACT DISPUTES AND OTHER. Costs related to gas contract disputes and
other, including legal expenses associated with gas contract disputes, declined
$73,000 or 40% to $111,000 for the nine months ended September 30, 1996 compared
to $184,000 for the 1995 period as the result of the settlement of all remaining
legal disputes related to gas contracts with purchasers in 1995.

LOSS (INCOME) IN EQUITY INVESTEES. The Company's share of net income from
the Russian Partnership Interest was $405,000 for the nine months ended
September 30, 1996 compared to a net loss of $94,000 for the comparable 1995
period because production and product prices increased significantly in 1996
from the 1995 levels. The Company's share of the net loss for Summo Minerals was
$358,000 for the nine months ended September 30, 1996 compared to a net loss of
$192,000 for the comparable 1995 period due to higher general and administrative
costs arising from Summo Minerals' addition of personnel in anticipation of
project financing and the commencement of mine development in 1997. See
"Business and Properties--Other Activities."

NON-OPERATING EXPENSE. Net interest expense increased $666,000 or 130% to
$1.2 million for the nine months ended September 30, 1996 compared to $514,000
for the same period in 1995 due to higher debt incurred for acquisitions and
increased drilling activity.

INCOME TAXES. The effective tax rate for the nine months ended September
30, 1996 increased to 32% compared to a 5% tax benefit in the 1995 period. The
effective tax rate in the 1995 period resulted from the use of capital loss
carryovers and Section 29 tax credits.

NET INCOME. Net income for the nine months ended September 30, 1996
increased $4.2 million or 242% to $5.9 million compared to $1.7 million in the
comparable 1995 period due to higher production volumes and prices resulting in
a $13.8 million increase in oil and gas production revenues, partially offset by
the associated higher production expenses and DD&A, a $2.0 million increase in
exploration expense and a $937,000 increase in general and administrative
expenses.

COMPARISON OF YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

REVENUES. 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 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 50% 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 $0.13 per Bbl for 1995 on these contracts compared to a $67,000 decrease or
$0.07 per Bbl in 1994. The Company also hedged 6% of its

21
<PAGE>

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 revenue was unchanged at $38.2 million in 1994 and 1993. Oil and gas
production volumes increased 11% and 13%, respectively, for the year ended
December 31, 1994 compared with the 1993 period. Average net daily production
reached 8.3 MBOE in 1994 compared to 7.4 MBOE in 1993. This production increase
resulted from new properties acquired and drilled during 1994 and 1993. However,
1994 average realized oil prices declined 8% to $14.95 per Bbl, while average
realized gas prices declined 12% to $1.93 per Mcf, from their respective 1993
levels. The Company's results in 1995 included a $1.3 million gain from the sale
of producing properties and $800,000 of other non-production revenue while
settlements of gas contracts and other non-production income added $6.5 million
to revenues in 1994.

OIL AND GAS PRODUCTION COSTS. 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. Oil and gas production costs
increased $1.2 million, or 12% to $10.5 million in 1994 compared with $9.3
million in 1993, due to additional operating costs on reserves purchased and new
wells drilled. However, total oil and gas production costs per BOE were $3.46 in
1994, unchanged from 1993.

DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT. DD&A 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 resulting in an additional
impairment charge for proved properties of $1.0 million in the fourth quarter of
1995. DD&A expense increased $1.3 million or 15% to $10.1 million in 1994
compared with $8.8 million in 1993 due to increased production from reserve
acquisitions and drilling activity. DD&A expense per BOE increased 3% to $3.34
in 1994 compared to $3.25 in 1993. Impairment of proved oil and gas properties
increased $721,000 or 21% to $4.2 million in 1994 compared with $3.5 million in
1993 because low year-end gas prices and several high cost marginal wells in
newer fields required ceiling test writedowns.

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. Abandonment and
impairment expenses for unproved properties were $1.0 million in 1994 and 1993.

EXPLORATION. 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.
Exploration expense increased $2.6 million or 47% to $8.1 million in 1994
compared to $5.5 million in 1993 because of geophysical costs on 3-D seismic
projects initiated in 1994 and higher exploratory dry hole costs associated with
the Company's increased drilling activity.

GENERAL AND ADMINISTRATIVE. 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. General and administrative
expenses increased $549,000 or 12% in 1994 to $5.3 million compared to $4.7
million in 1993, primarily due to compensation expense associated with the
Company's SARs, directors' and officers' insurance expense and additional
overhead due to the large number of properties added from acquisitions and
drilling in 1994 and 1993.

GAS CONTRACT DISPUTES AND OTHER. Legal expenses in connection with gas
contract disputes and the Company's mining activities declined $341,000 or 69%
to $152,000 in 1995 compared with $493,000 in 1994 because all of the Company's
mining activities are now conducted through the Company's equity investee,

22
<PAGE>
Summo Minerals. This expense declined $145,000 or 23% to $493,000 in 1994 from
$638,000 in 1993 because of lower legal expense due to the resolution of the
remaining gas contract disputes.

LOSS IN EQUITY INVESTEES. The equity in the net loss of the Russian
Partnership Interest was $322,000 in 1995, $328,000 in 1994 and $659,000 in
1993. The equity in the net loss of Summo Minerals increased to $257,000 for
1995 from $20,000 in 1994 due to Summo Minerals' higher general and
administrative expenses resulting from expansion of its Denver office in 1995.

NON-OPERATING EXPENSE. Net interest and other non-operating expense
increased $371,000 or 71% to $896,000 in 1995 compared to $525,000 in 1994
because of additional interest expense associated with higher debt levels and
the Company's increased ownership interest in Panterra. Net interest and other
non-operating expense increased $463,000 or 747% to $525,000 in 1994 compared to
$62,000 in 1993 due to a decline in interest income as a result of lower cash
investments and the acquisition of an additional ownership interest in Panterra.

INCOME TAXES. Income taxes provided a net tax benefit of $723,000 for 1995
with the utilization of capital loss carryovers and Section 29 tax credits
compared with income tax expense of $445,000 for 1994. The effective tax rate
for 1994 declined to 11% compared to 24% in 1993 due to higher Section 29 tax
credits in 1994. State tax expense was $396,000 in 1995, $445,000 in 1994 and
$587,000 in 1993, primarily due to lower Louisiana income taxes in 1995 and
1994. The Company also recognized a $300,000 tax benefit for the cumulative
effect of adopting SFAS No. 109, "Accounting for Income Taxes" as of January 1,
1993.

NET INCOME. 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.
Net income for 1994 was $3.7 million, unchanged from 1993.

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 $5.4 million or 46% to $17.1 million for the nine months ended
September 30, 1996 compared with $11.8 million in the 1995 period primarily due
to increased revenue from oil and gas sales. Net cash used in investing
activities increased $6.8 million or 29% to $30.1 million for the nine months
ended September 30, 1996 compared to $23.3 million in the 1995 period. Increased
capital expenditures from the Company's expanded drilling programs and oil and
gas property acquisitions accounted for the increase.

Net cash provided by financing activities was $15.7 million for the nine
months ended September 30, 1996 consisting of net debt proceeds for acquisitions
and drilling activities, partially offset by dividends compared with net cash
provided of $2.5 million in the 1995 period.

In the first quarter of 1997, the Company will make 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.

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 $3.0 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. The Company's net cash

23
<PAGE>

provided by operating activities increased 3% to $20.3 million in 1994 compared
to $19.7 million in 1993. Gas contract settlements received in 1994 were
partially offset by higher operating and exploration costs.

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, 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 $32.4 million compared to $30.9 million in
1994 due to increased drilling activity and reserve acquisitions. The Company
invested $4.5 million in Summo Minerals during 1995. Net cash used in investing
activities increased 13% to $23.1 million in 1994 compared with $20.5 million in
1993 primarily due to increased capital expenditures partially offset by a
decline in contributions to the Russian joint venture. Total capital
expenditures, including acquisitions of oil and gas properties, in 1994 were
$30.9 million compared to $22.8 million in 1993 due to increased drilling
activity and property acquisitions.

Net cash provided by financing activities was $7.0 million in 1995 compared
to net cash used by financing activities of $2.0 million in 1994. The Company
borrowed funds in 1995 for its capital expenditure programs and mining
investment compared with debt repayment of $578,000 in 1994. Net cash used by
financing activities was $2.0 million in 1994 compared to $4.9 million in 1993.
The Company used funds to repay debt in 1994 while it borrowed funds in 1993 to
finance a portion of the reserve acquisitions. The Company also received
proceeds from its common stock offering in 1993. The Company paid cash dividends
of $1.4 million in 1995, 1994 and 1993.

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
recently increased to $60.0 million 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 $25.4 million at September 30, 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 Common Stock.

Panterra, in which the Company has a 74% general partnership ownership
interest, has a separate credit facility with an $18.5 million borrowing base
and $11.0 million outstanding as of September 30, 1996. St. Mary guarantees its
pro rata share of the Panterra Credit Facility. The Panterra Credit Facility
expires on February 1, 2002. During February 1997, Panterra expects to amend the
Panterra Credit Facility to extend the revolving loan period and to provide for
a $26.0 million borrowing base. 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

24
<PAGE>
sets forth certain information regarding the costs incurred by the Company in
its oil and gas activities during the periods indicated.

<TABLE>
<CAPTION>
CAPITAL AND EXPLORATION EXPENDITURES(1)
-----------------------------------------------------
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Development................................................ $ 7,079 $ 5,946 $ 12,625 $ 7,998 $ 13,406
Exploration................................................ 9,013 9,481 8,746 6,142 7,269
Acquisitions:
Proved................................................... 4,848 12,279 8,111 5,711 13,567
Unproved................................................. 1,847 3,228 2,937 3,740 2,438
--------- --------- --------- --------- ---------
Total...................................................... $ 22,787 $ 30,934 $ 32,419 $ 23,591 $ 36,680
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>

- ------------------------

(1) Excludes certain international exploration costs.

The Company's total costs incurred for the nine months ended September 30,
1996 increased 55% to $36.7 million compared to $23.6 million for the comparable
1995 period. Proved property acquisitions increased $7.9 million to $13.6
million for the nine months ended September 30, 1996 compared to $5.7 million
for the 1995 period. The Company spent $23.1 million for domestic exploration
and development and unproved property acquisitions for the nine months ended
September 30, 1996 compared to $17.9 million for the 1995 period as a result of
increased drilling activity.

The Company's total costs incurred in 1995 increased 5% to $32.4 million
compared to $30.9 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
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.

The Company's total costs incurred in 1994 increased 36% to $30.9 million
compared to $22.8 million in 1993. Proved property acquisitions increased $7.5
million to $12.3 million in 1994 compared to $4.8 million in 1993. The Company
spent $18.7 million in 1994 for unproved property acquisitions and domestic
exploration and development compared to $17.9 million in 1993.

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. See "Use of Proceeds."

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.

ACCOUNTING MATTERS

The Company adopted SFAS No. 109, "Accounting for Income Taxes" as of
January 1, 1993 and recorded a $300,000 benefit in the results of operations for
the cumulative effect of a change in accounting principle.

25
<PAGE>
As of January 1, 1994, the Company adopted SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities," which provides for reporting
of certain debt and equity securities at fair value and the inclusion of
unrealized holding gains and losses in earnings or stockholders' equity.

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 of
$1.0 million in the fourth quarter of 1995.

In November 1996, the Company adopted a stock option plan which covers a
maximum of 700,000 shares. Options granted under the 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 will adopt
SFAS No. 123, "Accounting for Stock-Based Compensation," in its annual report on
Form 10-K 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.

EFFECTS OF INFLATION AND CHANGING PRICES

The Company's results of operations and cash flow are affected by changing
oil and gas prices. 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.

26
<PAGE>
BUSINESS AND PROPERTIES

GENERAL

St. Mary Land & Exploration 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.

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

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.

27
<PAGE>

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.

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 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.

PROPERTIES--PRINCIPAL AREAS OF 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.

<TABLE>
<CAPTION>
OIL GAS MBOE PV-10 VALUE
----------- --------- ---------------------- ----------------------------
(MBBLS) (MMCF) AMOUNT PERCENT (IN THOUSANDS) PERCENT
----------- --------- --------- ----------- --------------- -----------
<S> <C> <C> <C> <C> <C> <C>
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%
----------- --------- --------- ----- --------------- -----
----------- --------- --------- ----- --------------- -----
</TABLE>

- ------------------------

(1) Excludes amounts attributable to the Company's Russian Partnership Interest.
The Company has recently sold its Russian Partnership Interest. See "--Other
Activities."

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

28
<PAGE>

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.

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 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

29
<PAGE>

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.

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

30
<PAGE>
undertook an independent geological and engineering review of its fee properties
and developed a 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 which 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 plans to test multiple potential 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."

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

31
<PAGE>
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 and Gas
Company 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 MBBbls 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."

32
<PAGE>

SIETE PROPERTIES. In 1996 the Company completed the acquisition of a 90%
interest in the oil and gas properties of Siete Oil and Gas Company 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 were 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 $1.2 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. See "Risk Factors--Substantial Capital Requirements."

The following table summarizes the Company's active large-target exploration
projects. See
also "--Properties--Principal Areas of Operations."

<TABLE>
<CAPTION>
ST. MARY ST. MARY EXPECTED
WORKING ROYALTY DRILLING
PROJECT NAME OBJECTIVE LOCATION INTEREST(1) INTEREST(2) DATE(3)
- ----------------------- ------------------------ ----------------------- ------------- ------------- ------------
<S> <C> <C> <C> <C> <C>
South Horseshoe
Bayou................ Rob, Operc, 19,000' St. Mary Parish, LA 25.0% 22.0% early 1997

Mustang Sale........... Rob, 16,000' St. Mary Parish, LA -- 12.5% early 1997

Roanoke(4)............. Frio, Hackberry Jefferson Davis Parish, 33.3% -- early 1997
LA

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
</TABLE>

- ------------------------

(1) Working interests differ from net revenue interests due to royalty interest
burdens.

(2) Royalty interests are approximate and are subject to adjustment. St. Mary
has no capital at risk with respect to its royalty interests.

(3) Expected Drilling Date means the period during which the Company anticipates
the commencement of drilling and/or testing of an exploratory well.

33
<PAGE>
(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.

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. See "Risk Factors--Acquisition Risks."

ESTIMATED NET PROVED 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 text of the Ryder Scott report is attached
as Exhibit A to this Prospectus. 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.

34
<PAGE>
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.

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------
1994 1995 1996
--------- ---------- ----------
<S> <C> <C> <C>
RESERVE DATA: (1)
Oil (MBbls)................................................ 6,677 7,509 10,691
Gas (MMcf)................................................. 62,515 75,705 127,057
MBOE....................................................... 17,096 20,127 31,867
PV-10 Value (in thousands)................................. $ 84,688 $ 120,192 $ 296,461
Proved developed reserves.................................. 93% 89% 84%
Production replacement..................................... 207% 203% 422%
Reserve Life (years)....................................... 5.6 6.5 8.4
</TABLE>

- ------------------------

(1) For limitations on the accuracy and reliability of estimated net proved
reserves and future net revenue estimates, see "Risk Factors--Uncertainty of
Estimates of Reserves and Future Net Revenues." Reserve data attributable to
the Company's Russian Partnership Interest have been excluded from this
table. Effective February 12, 1997 the Company sold its Russian Partnership
Interest. See "--Other Activities."

PRODUCTION, PRICE AND COST HISTORY

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.

Average net daily production:
Oil (Bbls)..................................... 2,319 2,567 2,852 2,798 3,156
Gas (Mcf)...................................... 30,539 34,458 33,973 32,824 41,053
BOE............................................ 7,409 8,310 8,514 8,269 9,998

Average sales price: (2)
Oil (per Bbl).................................. $ 16.18 $ 14.95 $ 16.37 $ 16.33 $ 18.26
Gas (per Mcf).................................. $ 2.20 $ 1.93 $ 1.56 $ 1.49 $ 2.12

Additional per BOE data:
Lease operating expense........................ $ 2.42 $ 2.54 $ 2.49 $ 2.51 $ 2.28
Production taxes............................... $ 1.04 $ 0.92 $ 0.93 $ 0.89 $ 1.10
</TABLE>

- ------------------------

(1) Excludes operating data attributable to the Company's Russian Partnership
Interest.

(2) Includes the effects of the Company's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Overview."

35
<PAGE>
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.

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.

<TABLE>
<CAPTION>
GROSS NET
--------- ---
<S> <C> <C>
Oil.................................................. 529 136
Gas.................................................. 884 105
--------- ---
Total.............................................. 1,413 241
--------- ---
--------- ---
</TABLE>

DOMESTIC DRILLING ACTIVITY

The following table sets forth the wells in which the Company participated
during each of the three years indicated.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1994 1995 1996
---------------------- ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
Development:
Oil....................................... 4 1.07 6 1.52 17 3.91
Gas....................................... 30 4.91 38 7.75 74 13.29
Non-productive............................ 3 0.33 6 2.00 11 2.70
----- --------- ----- --------- ----- ---------
Total................................... 37 6.31 50 11.27 102 19.90
----- --------- ----- --------- ----- ---------
----- --------- ----- --------- ----- ---------
Exploratory:
Oil....................................... 1 0.25 5 1.56 -- --
Gas....................................... 14 2.26 8 0.74 5 1.25
Non-productive............................ 19 3.82 16 4.19 10 3.10
----- --------- ----- --------- ----- ---------
Total................................... 34 6.33 29 6.49 15 4.35
----- --------- ----- --------- ----- ---------
----- --------- ----- --------- ----- ---------
Farmout or non-consent.................. 7 -- 4 -- 9 --
----- --------- ----- --------- ----- ---------
----- --------- ----- --------- ----- ---------
Grand Total(1).............................. 78 12.64 83 17.76 126 24.25
----- --------- ----- --------- ----- ---------
----- --------- ----- --------- ----- ---------
</TABLE>

- ------------------------

(1) Does not include 6, 4 and 3 gross wells completed on the Company's fee lands
during 1994, 1995 and 1996, respectively.

All of the Company's drilling activities are conducted on a contract basis
with independent drilling contractors. The Company owns no drilling equipment.

36
<PAGE>
LEASEHOLD AND OTHER INTERESTS

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.

<TABLE>
<CAPTION>
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
(1) (2) TOTAL
-------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
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
--------- --------- --------- --------- --------- ---------
Grand Total...................................... 274,612 81,190 377,292 145,619 651,904 226,809
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
</TABLE>

- ------------------------

(1) Developed acreage is acreage assigned to producing wells for the spacing
unit of the producing formation. Developed acreage in certain of the
Company's properties that include multiple formations with different well
spacing requirements may be considered undeveloped for certain formations,
but have only been included as developed acreage in the presentation above.

(2) Undeveloped acreage is lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains
estimated net proved reserves.

OTHER ACTIVITIES

SUMMO MINERALS. Since 1994, St. Mary Minerals Inc. ("St. Mary Minerals"), a
wholly-owned subsidiary of the Company, has invested a total of approximately
$5.9 million and has acquired a total of 9,924,093 common shares of Summo
Minerals representing 49.9% of the issued and outstanding common shares and
3,536,090 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".

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 does not plan to participate in such financing. If Summo
Minerals is not successful in arranging such financing, the Company currently
expects to invest no more than approximately $1.0 to $2.0 million in

37
<PAGE>
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.

RUSSIAN PARTNERSHIP INTEREST. Until recently, Chelsea Corporation
("Chelsea"), a wholly-owned, second tier subsidiary of the Company, owned a 36%
interest (the "Russian Partnership Interest") in the Anderman/Smith
International - Chernogorskoye Partnership which owns a 50% interest 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 Partnership Interest 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 the form of 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 Partnership
Interest. Chelsea's retained production payment is collateralized by the Russian
Partnership Interest. Chelsea has the right, subject to certain conditions, to
require UPC to purchase Chelsea's retained production payment 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 retained production payment
into UPC common stock immediately prior to an initial public offering of UPC
common stock.

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.

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.

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.

38
<PAGE>
MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the names, ages and positions of the
executive officers and the members of the Board of Directors of the Company. All
directors are elected for a term of one year and serve until their successors
are elected and qualified.

<TABLE>
<CAPTION>
NAME AGE POSITION
- --------------------------------- --- ---------------------------------------------------------------
<S> <C> <C>
Thomas E. Congdon(1) 70 Chairman of the Board of Directors and Director

Mark A. Hellerstein(1) 44 President, Chief Executive Officer and Director

Ronald D. Boone 49 Executive Vice President, Chief Operating Officer and Director

Ralph H. Smith 54 Senior Vice President

David L. Henry 40 Vice President and Chief Financial Officer

Larry W. Bickle(2) 51 Director

David C. Dudley(1) 46 Director

Richard C. Kraus(2)(3) 50 Director

R. James Nicholson(3) 59 Director

Arend J. Sandbulte(1)(3) 63 Director

John M. Seidl(2) 58 Director
</TABLE>

- ------------------------

(1) Member of Executive Committee

(2) Member of Audit Committee

(3) Member of Compensation Committee

The Audit Committee's functions include recommending to the Board of
Directors the engagement of the Company's independent public accountants,
reviewing with such accountants the plans for and the results and scope of their
auditing engagement and certain other matters relating to their services
provided to the Company, including the independence of such accountants. The
Compensation Committee reviews on behalf of, and makes recommendations to, the
Board of Directors with respect to compensation of directors, executive officers
and key employees.

THOMAS E. CONGDON. Mr. Congdon has served the Company as an officer and
director since 1966, including service as its President and Chief Executive
Officer for more than 25 years. Mr. Congdon is also a director, officer or
general partner of a number of family corporations and partnerships which
produce scientific and statistical software, iron ore and agricultural products,
manage marketable securities and own and operate developed real estate. From
1980 to 1991, he was Chairman of the Board of Directors of CoCa Mines Inc.,
which was an affiliate of the Company during that time. From 1974 to 1994, he
was a director of Colorado National Bankshares Inc., a bank holding company.

MARK A. HELLERSTEIN. Mr. Hellerstein joined the Company in September 1991
and served as Executive Vice President and Chief Financial Officer until May
1992, at which time he was elected President and a director of the Company. Mr.
Hellerstein was elected Chief Executive Officer of the Company in May 1995. He
also has served as Chairman of the Board of Summo Minerals since 1995. From 1987
through August 1991 (excluding October 1989 to May 1990), he served as Vice
President--Finance, Chief Financial Officer and Secretary for CoCa Mines Inc.

RONALD D. BOONE. Mr. Boone has served the Company as Executive Vice
President since 1990, as Chief Operating Officer since 1992 and as a director of
the Company since 1996. From 1981 to 1990, he

39
<PAGE>
was employed in various capacities by Anderman/Smith Operating Company, an
affiliate of the Company during that period, most recently as Vice
President--Production and Engineering.

RALPH H. SMITH. Mr. Smith has served the Company as Senior Vice
President--Mid Continent since 1995. From 1982 to 1994, he was Executive Vice
President of Anderman/Smith Operating Company, an affiliate of the Company
during that period. In addition, he has been a director and President of R.H.
Smith International Corporation since 1989.

DAVID L. HENRY. Mr. Henry joined the Company in 1996 as Vice President and
Chief Financial Officer. From 1983 to 1996, he was employed in corporate finance
investment banking positions with Boettcher & Company, Inc., CharterWest Capital
Co. and most recently as Director--Corporate Finance for Hanifen, Imhoff Inc.

LARRY W. BICKLE. Mr. Bickle has served as a director of the Company since
1995. He currently is Chairman and Chief Executive Officer of TPC Corporation, a
public gas storage and transportation company he co-founded in 1984.

DAVID C. DUDLEY. Mr. Dudley has served as a director of the Company since
1986. Since 1983, he has served as Operating Manager of Dudley & Associates,
LLC., Denver, Colorado, a closely-held oil and gas exploration and production
firm. Since 1985, he has served as general partner of the New York investment
advisory firm Dudley & Company. In addition, since 1980 Mr. Dudley has served as
a general partner of Greenhouse Associates, a closely-held investment
partnership.

RICHARD C. KRAUS. Mr. Kraus has served as a director of the Company since
1994. Since 1981, he has been employed by Echo Bay Mines Ltd., a public company
engaged primarily in mining operations, and currently serves as its President
and Chief Executive Officer. In addition, he has been an Echo Bay director since
1992.

R. JAMES NICHOLSON. Mr. Nicholson has served as a director of the Company
since 1987. Since 1978, he has served as President of Nicholson Enterprises,
Inc., a land development company. Mr. Nicholson has also served as President of
Renaissance Homes, a residential home building company, since 1988. Since 1974,
he has served as a director of Lerch, Bates & Associates, Inc., a consulting
engineering firm. He was elected Chairman of the Republican National Committee
in January 1997.

AREND J. SANDBULTE. Mr. Sandbulte has served as a director of the Company
since 1989. From 1964 to 1996, he was employed by Minnesota Power & Light
Company, a publicly-held energy utility, most recently as its Chairman of the
Board, President and Chief Executive Officer, and continues as a director of
this utility, a position to which he was first elected in 1983.

JOHN M. SEIDL. Mr. Seidl has served as a director of the Company since
1994. He currently serves as President, Chief Executive Officer and director of
CellNet Data Systems. From 1989 to 1993, he served as an officer and director of
MAXXAM Inc. and Kaiser Aluminum Corporation and The Pacific Lumber Company,
subsidiaries of MAXXAM Inc., a public company.

There are no family relationships (first cousin or closer) among the
directors. There are no arrangements or understandings between any director and
any other person pursuant to which that director was elected.

40
<PAGE>
DESCRIPTION OF COMMON STOCK

The Company's authorized capital consists of 15,000,000 shares of Common
Stock, par value $.01 per share. Upon completion of this offering, the Company
will have 10,762,814 shares of Common Stock outstanding. Holders of Common Stock
are entitled to one vote for each share held in the election of directors and on
all other matters submitted to a vote of stockholders and do not have cumulative
voting rights. Holders of a majority of the shares of Common Stock entitled to
vote in any election of directors may elect all of the directors standing for
election.

Holders of Common Stock are entitled to receive ratably such dividends, if
any, as may be declared by the Board of Directors out of funds legally available
therefor. See "Dividend Policy." Upon the liquidation, dissolution or winding up
of the Company, the holders of Common Stock are entitled to receive ratably the
net assets of the Company available after payment of all debts and other
liabilities. Holders of Common Stock have no preemptive, subscription,
redemption or conversion rights. The outstanding shares of Common Stock are, and
the shares offered by the Company in this offering will be, when issued and paid
for, fully paid and non-assessable.

CERTAIN LIMITED LIABILITY AND INDEMNIFICATION PROVISIONS

As permitted by the provisions of the Delaware General Corporation Law, the
Certificate of Incorporation eliminates in certain circumstances the monetary
liability of directors of the Company for a breach of their fiduciary duty as
directors. These provisions do not eliminate the liability of a director (i) for
a breach of the director's duty of loyalty to the Company or its stockholders;
(ii) for acts or omissions by a director not in good faith or which involve
intentional misconduct or a knowing violation of law; (iii) for liability
arising under Section 174 of the Delaware General Corporation Law (relating to
the declaration of dividends and purchase or redemption of shares in violation
of the Delaware General Corporation Law); or (iv) for any transaction from which
the director derived an improper personal benefit. In addition, these provisions
do not eliminate the liability of a director for violations of federal
securities laws, nor do they limit the rights of the Company or its
stockholders, in appropriate circumstances, to seek equitable remedies such as
injunctive or other forms of non-monetary relief. Such remedies may not be
effective in all cases.

The Company's Certificate of Incorporation and Bylaws provide that the
Company shall indemnify all directors and officers of the Company to the full
extent permitted by the Delaware General Corporation Law. Under such provisions,
any director or officer, who in his capacity as such is made or threatened to be
made, a party to any suit or proceeding, may be indemnified if the Board
determines such director or officer acted in good faith and in a manner he
reasonably believed to be in or not opposed to the best interest of the Company.
The Certificate, Bylaws and the Delaware General Corporation Law further provide
that such indemnification is not exclusive of any other rights to which such
individuals may be entitled under the Certificate, the Bylaws, any agreement,
vote of stockholders or disinterested directors or otherwise.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Company's Common Stock is American
Securities Transfer and Trust, Incorporated, Denver, Colorado.

UNDERWRITING

Subject to the terms and conditions of the Underwriting Agreement among the
Company and the Underwriters named below (the "Underwriting Agreement"), the
Company has agreed to sell to each of

41
<PAGE>

such Underwriters named below, and each of such Underwriters has severally
agreed to purchase from the Company, the respective number of shares of Common
Stock set forth opposite its name below.

<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
- --------------------------------------------------------------------------------- ----------
<S> <C>
Morgan Keegan & Company, Inc..................................................... 666,668
A.G. Edwards & Sons, Inc......................................................... 666,666
Hanifen, Imhoff Inc.............................................................. 666,666
----------
Total.......................................................................... 2,000,000
----------
----------
</TABLE>

Under the terms and conditions of the Underwriting Agreement, the
underwriters are committed to take and pay for all of the shares of Common Stock
offered hereby, if any are taken.

The Underwriters propose to offer the shares of Common Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus, and in part to certain securities dealers at such
price less a concession of $.80 per share. The Underwriters may allow, and such
dealers may allow, a concession not in excess of $.10 per share to certain
brokers and dealers. After the shares of Common Stock are released for sale to
the public, the offering price and other selling terms may from time to time be
varied by the Underwriters.

The Company has granted the Underwriters an option exercisable for 30 days
after the date of this Prospectus to purchase up to an aggregate of 300,000
additional shares of Common Stock solely to cover over-allotments, if any. If
the Underwriters exercise their over-allotment option, the Underwriters have
severally agreed, subject to certain conditions, to purchase approximately the
same percentage thereof that the number of shares of Common Stock to be
purchased by each of them, as shown in the table above, bears to the 2,000,000
shares of Common Stock.

The Company has agreed in the Underwriting Agreement not to offer, sell,
contract to sell, grant any option to purchase or otherwise dispose of any
shares of Common Stock or any securities convertible into or exercisable or
exchangeable for Common Stock, subject to certain limited exceptions, for a
period of 120 days after the date of this Prospectus without the prior written
consent of the Underwriters. In addition, the Company's directors and executive
officers have agreed not to sell, contract to sell, grant any option to purchase
or otherwise dispose of any shares of Common Stock or any securities convertible
into or exercisable or exchangeable for Common Stock, other than as gifts,
pledges and certain other transfers to persons who agree to the same
restrictions for a period of 120 days after the date of this Prospectus without
the prior written consent of the Underwriters.

In connection with this offering, certain Underwriters may engage in passive
market making transactions in the Common Stock on the Nasdaq National Market
immediately prior to the commencement of sales in this offering, in accordance
with Rule 10b-6A under the Exchange Act. Passive market making consists of,
among other things, displaying bids on the Nasdaq National Market limited by the
bid prices of independent market makers and purchases limited by such prices and
effected in response to order flow. Net purchases by a passive market maker on
each day are limited to a specified percentage of the passive market maker's
average daily trading volume in the Common Stock during a specified prior
period, and all passive market making activity must be discontinued when such
limit is reached. Passive market making may stabilize the market price of the
Common Stock at a level above that which might otherwise prevail and, if
commenced, may be discontinued at any time.

The Company has agreed to indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act or to contribute to
payments the Underwriters may be required to make in respect of such
liabilities.

42
<PAGE>
LEGAL MATTERS

Certain legal matters with respect to the Common Stock offered hereby have
been passed upon for the Company by Cohen Brame & Smith Professional
Corporation, Denver, Colorado. Certain legal matters will be passed upon for the
Underwriters by Butler & Binion, L.L.P., Houston, Texas.

EXPERTS

The consolidated balance sheets as of December 31, 1994 and 1995 and the
consolidated statements of income, stockholders' equity and cash flows for each
of the three years in the period ended December 31, 1995 included and
incorporated by reference in this Prospectus have been included and incorporated
herein in reliance on the report of Coopers & Lybrand L.L.P., independent
accountants, given on the authority of that firm as experts in accounting and
auditing.

The Statement of Revenues and Direct Operating Expenses of Certain Oil & Gas
Properties Acquired from Siete Oil & Gas Corporation for the year ended December
31, 1995 incorporated by reference in this Prospectus have been incorporated
herein in reliance on the report of Coopers & Lybrand L.L.P., independent
accountants, given on the authority of that firm as experts in accounting and
auditing.

Certain estimates of oil and gas reserves appearing herein were based upon
engineering reports prepared by the independent petroleum engineering firm of
Ryder Scott Company. Such estimates are included herein in reliance upon the
authority of such firm as experts in such matters.

AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Exchange Act
and in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information concerning the Company may be inspected and copied at the public
reference facilities maintained by the Commission at Room 1024, 450 Fifth
Street, N.W., Washington, D.C. 20549, and at the Commission's Regional Offices
at 500 West Madison Street, Suite 1400, Chicago, Illinois 60661 and at Seven
World Trade Center, Thirteenth Floor, New York, New York 10048. Copies of such
material can also be obtained upon written request addressed to the Commission,
Public Reference Section, 450 Fifth Street, N.W., Washington, D.C. 20549, at
prescribed rates. In addition, such material can be inspected at the offices of
the National Association of Securities Dealers, Inc., 1735 K Street, Washington,
D.C. 20006. Further, the Commission maintains a Website (http:\\www.sec.gov)
that contains reports, proxy and information statements and other information
filed by registrants electronically with the Commission through the Electronic
Data Gathering, Analysis, and Retrieval system.

The Company has filed with the Commission a registration statement on Form
S-3 (herein, together with all amendments and exhibits, referred to as the
"Registration Statement") under the Securities Act with respect to the Common
Stock offered hereby. This Prospectus, which constitutes a part of the
Registration Statement, does not contain all of the information set forth in the
Registration Statement, certain parts of which are omitted in accordance with
the rules and regulations of the Commission. For further information, reference
is hereby made to the Registration Statement which may be inspected and copied
in the manner and at the sources described above. With respect to each such
agreement, instrument, or other document filed as an exhibit to the Registration
Statement, reference is made to the exhibit for a more complete description of
the matter involved, and each such statement shall be deemed qualified in its
entirety by such reference.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents filed by the Company with the Commission pursuant to
the Exchange Act (file number 0-20872) are incorporated herein by reference,
except as superseded or modified herein:

(i) The Company's Annual Report on Form 10-K for the year ended December 31,
1995;

43
<PAGE>

(ii) The Company's Quarterly Reports on Form 10-Q for the quarterly period
ended March 31, 1996, as amended by Form 10-Q/A dated October 15, 1996;
June 30, 1996, as amended by Form 10-Q/A dated October 15, 1996 and
Form 10-Q/A-1 dated February 4, 1997; and September 30, 1996, as
amended by Form 10-Q/A dated November 15, 1996 and Form 10-Q/A-1 dated
February 4, 1997;

(iii) The Company's Current Report on Form 8-K dated June 28, 1996, as
amended by a Form 8-K/A dated June 28, 1996, regarding the acquisition
of an interest in certain of the assets of Siete Oil and Gas Company;

(iv) The Company's Current Report on Form 8-K dated December 16, 1996
regarding the sale of the Company's Russian Partnership Interest as
amended on Form 8-K/A filed February 19, 1997;

(v) The Company's Current Report on Form 8-K dated January 28, 1997
regarding certain exhibits;

(vi) The Company's Current Report on Form 8-K dated February 19, 1997
regarding the completion and testing of the Horseshoe Bayou discovery
well; and

(vii) The Company's Registration Statement on Form 8-A filed November 18,
1992.

All reports and other documents subsequently filed by the Company pursuant
to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this
Prospectus and prior to the termination of this offering shall be deemed to be
incorporated by reference herein and to be a part hereof from the date of filing
of such reports and documents. Any statement contained herein or in a document
incorporated or deemed to be incorporated herein by reference shall be deemed to
be modified or superseded for purposes of this Prospectus to the extent that a
statement contained in this prospectus or in any subsequently filed document
(which is deemed to be incorporated by reference herein) modifies or supersedes
such statement. Any such statement so modified or superseded shall not be
deemed, except as so modified or superseded, to constitute a part of this
Prospectus.

To the extent the information relating to the Company contained in this
Prospectus summarizes, is based upon or refers to, information and financial
statements contained in one or more of the documents incorporated by reference
herein, the information contained herein is qualified in its entirety by
reference to such document, and it should be read in conjunction therewith.

The Company will provide, without charge, to each person to whom a copy of
this Prospectus is delivered, on the written or oral request of such person, a
copy of any or all of the documents incorporated herein by reference (other than
exhibits thereto, unless such exhibits are specifically incorporated by
reference into the information that this Prospectus incorporates). Written or
telephone requests for such copies should be directed to the Company's principal
office: St. Mary Land & Exploration Company, 1776 Lincoln Street, Suite 1100,
Denver, Colorado 80203, (303) 861-8140.

44
<PAGE>
GLOSSARY

The terms defined in this section are used throughout this Prospectus.

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.

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.

45
<PAGE>

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.

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.

46
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
CONSOLIDATED INTERIM FINANCIAL STATEMENTS (UNAUDITED)

Consolidated Balance Sheets as of December 31, 1995 and September 30, 1996............................... F-2

Consolidated Statements of Income for the nine month periods ended September 30, 1995 and 1996........... F-3

Consolidated Statements of Cash Flows for the nine month periods ended September 30, 1995 and 1996....... F-4

Notes to Consolidated Financial Statements............................................................... F-6

CONSOLIDATED ANNUAL FINANCIAL STATEMENTS

Report of Independent Accountants........................................................................ F-8

Consolidated Balance Sheets as of December 31, 1994 and 1995............................................. F-9

Consolidated Statements of Income for each of the three years in the period ended December 31, 1995...... F-10

Consolidated Statements of Stockholders' Equity for each of the three years in the period ended December
31, 1995............................................................................................... F-11

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31,
1995................................................................................................... F-12

Notes to Consolidated Financial Statements............................................................... F-13
</TABLE>

F-1
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
<S> <C> <C>
(UNAUDITED)
Current assets:
Cash and cash equivalents......................................................... $ 1,723 $ 4,405
Accounts receivable............................................................... 8,068 20,707
Prepaid expenses.................................................................. 850 2,146
Refundable income taxes........................................................... 176 35
------------ -------------
Total current assets............................................................ 10,817 27,293
------------ -------------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties..................................................... 165,750 191,670
Unproved oil and gas properties, net.............................................. 11,752 15,306
Other............................................................................. 2,535 3,414
------------ -------------
180,037 210,390
Less accumulated depletion, depreciation, amortization and impairment............. (108,392) (117,586)
------------ -------------
71,645 92,804
------------ -------------
Other assets:
Investment in Russian joint venture............................................... 4,140 4,788
Investment in Summo Minerals Corporation.......................................... 4,842 4,483
Other assets...................................................................... 4,682 3,312
------------ -------------
13,664 12,583
------------ -------------
$ 96,126 $ 132,680
------------ -------------
------------ -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.................................................................. $ 7,715 $ 19,691
Stock appreciation rights......................................................... -- 1,183
------------ -------------
Total current liabilities....................................................... 7,715 20,874
Long-term liabilities:
Long-term debt.................................................................... 19,602 36,324
Deferred income taxes............................................................. 1,228 3,427
Stock appreciation rights......................................................... 1,178 599
Other noncurrent liabilities...................................................... 121 316
------------ -------------
22,129 40,666
------------ -------------
Commitments and contingencies (Note 4)
Stockholders' equity:
Common stock, $.01 par value; authorized--15,000,000 shares; issued and
outstanding--8,761,855 shares in 1995 and 8,759,214 shares in 1996.............. 88 88
Additional paid-in capital........................................................ 15,835 15,800
Retained earnings................................................................. 50,378 55,248
Unrealized gain on marketable equity securities--available for sale............... 15 4
Treasury stock--2,572 shares, at cost............................................. (34) --
------------ -------------
Total stockholders' equity...................................................... 66,282 71,140
------------ -------------
$ 96,126 $ 132,680
------------ -------------
------------ -------------
</TABLE>

The accompanying notes are an integral part
of these consolidated financial statements.

F-2
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
1995 1996
--------- ---------
<S> <C> <C>
Operating revenues:
Oil and gas production.................................................................... $ 25,860 $ 39,689
Gain on sale of proved properties......................................................... 1,052 --
Gas contract settlements and other revenues............................................... 528 490
--------- ---------
Total operating revenues................................................................ 27,440 40,179
--------- ---------
Operating expenses:
Oil and gas production.................................................................... 7,676 9,262
Depletion, depreciation and amortization.................................................. 7,184 9,144
Impairment of proved properties........................................................... 1,673 --
Exploration............................................................................... 3,683 5,688
Abandonment and impairment of unproved properties......................................... 759 1,240
General and administrative................................................................ 4,129 5,066
Gas contract disputes and other........................................................... 184 111
Loss (income) in equity investees......................................................... 286 (47)
--------- ---------
Total operating expenses................................................................ 25,574 30,464
--------- ---------

Income from operations...................................................................... 1,866 9,715

Nonoperating income and (expense):
Interest income........................................................................... 230 227
Interest expense.......................................................................... (744) (1,407)
--------- ---------

Income from continuing operations before income taxes....................................... 1,352 8,535
Income tax (benefit) expense................................................................ (72) 2,773
--------- ---------

Income from continuing operations........................................................... 1,424 5,762
Gain on sale of discontinued operations, net of income taxes................................ 306 159
--------- ---------

Net income.................................................................................. $ 1,730 $ 5,921
--------- ---------
--------- ---------

Net income per common share:
Income from continuing operations......................................................... $ .17 $ .66
Gain on sale of discontinued operations................................................... .03 .02
--------- ---------
Net income per share........................................................................ $ .20 $ .68
--------- ---------
--------- ---------

Weighted average common shares outstanding.................................................. 8,760 8,759
--------- ---------
--------- ---------
</TABLE>

The accompanying notes are an integral part
of these consolidated financial statements.

F-3
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE NINE MONTHS
ENDED SEPTEMBER 30,
----------------------
1995 1996
---------- ----------
<S> <C> <C>
Cash flows from operating activities:
Cash received from oil and gas operations............................................... $ 24,206 $ 32,034
Cash paid for oil and gas operations, including general and administrative expenses..... (9,323) (9,868)
Exploration expenses.................................................................... (2,764) (4,035)
Interest and other receipts............................................................. 393 381
Interest paid........................................................................... (479) (1,300)
Income taxes paid....................................................................... (278) (102)
---------- ----------
Net cash provided by operating activities............................................. 11,755 17,110
---------- ----------

Cash flows from investing activities:
Proceeds from sale of oil and gas properties............................................ 2,227 146
Capital expenditures, including dry hole costs.......................................... (14,609) (20,017)
Acquisition of oil and gas properties................................................... (9,005) (13,557)
Investment in St. Mary Operating Company................................................ -- 3,059
Investment in Summo Minerals Corporation................................................ (2,042) --
Other................................................................................... 167 271
---------- ----------
Net cash used by investing activities................................................. (23,262) (30,098)
---------- ----------

Cash flows from financing activities:
Proceeds from long-term debt............................................................ 5,380 23,650
Repayment of long-term debt............................................................. (1,745) (6,928)
Dividends paid.......................................................................... (1,051) (1,051)
Purchase of treasury and common stock................................................... (44) (1)
---------- ----------
Net cash provided by financing activities............................................. 2,540 15,670
---------- ----------

Net (decrease) increase in cash and cash equivalents...................................... (8,967) 2,682
Cash and cash equivalents at beginning of period.......................................... 9,976 1,723
---------- ----------

Cash and cash equivalents at end of period................................................ $ 1,009 $ 4,405
---------- ----------
---------- ----------
</TABLE>

The accompanying notes are an integral part
of these consolidated financial statements.

F-4
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(IN THOUSANDS)

(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE NINE MONTHS
ENDED SEPTEMBER 30,
--------------------
<S> <C> <C>
1995 1996
--------- ---------
Reconciliation of net income to net cash provided by operating activities:
Net income................................................................................ $ 1,730 $ 5,921
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization................................................ 7,184 9,144
Impairment of proved properties......................................................... 1,673 --
Loss (income) in equity investees....................................................... 286 (47)
Gain on sale of oil and gas properties.................................................. (1,052) --
Dry hole costs.......................................................................... 940 1,956
Abandonment and impairment of unproved properties....................................... 759 1,240
Deferred income taxes................................................................... 42 2,271
Other................................................................................... (417) 455
--------- ---------
11,145 20,940
Changes in assets and liabilities:
Accounts receivable..................................................................... 466 (8,619)
Refundable income taxes................................................................. (437) 141
Accounts payable and accrued expenses................................................... 581 4,720
Deferred income taxes................................................................... -- (72)
--------- ---------
Net cash provided by operating activities........................................... $ 11,755 $ 17,110
--------- ---------
--------- ---------
Supplemental schedule of noncash investing and financing activities:
</TABLE>

In March 1996, the Company acquired an additional 35% shareholder interest
in St. Mary Operating Company for $234,000 and assumed net liabilities of
$339,000.

The accompanying notes are an integral part
of these consolidated financial statements.

F-5
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 -- BASIS OF PRESENTATION

The accompanying unaudited condensed consolidated financial statements have
been prepared in accordance with generally accepted accounting principles for
interim financial information. They do not include all information and notes
required by generally accepted accounting principles for complete financial
statements. However, except as disclosed herein, there has been no material
change in the information disclosed in the Notes to Consolidated Financial
Statements of St. Mary Land & Exploration Company and Subsidiaries (the Company)
for the year ended December 31, 1995 included elsewhere herein. In the opinion
of Management, all adjustments (consisting of normal recurring accruals)
considered necessary for a fair presentation have been included. Operating
results for the periods presented are not necessarily indicative of the results
that may be expected for the full year.

The accounting policies followed by the Company are set forth in Note 1 of
the Notes to Consolidated Financial Statements of the Company for the year ended
December 31, 1995. It is suggested that these financial statements be read in
conjunction with the Consolidated Financial Statements and accompanying Notes to
Consolidated Financial Statements.

NOTE 2 -- INVESTMENTS

In March 1996, the Company completed its purchase of the Anderman Group
stock of St. Mary Operating Company ("SMOC") at book value. The purchase
increased the Company's ownership in SMOC from 65% to 100%.

The Company accounts for its investment in the Russian joint venture using
the equity method of accounting. For the nine months ended September 30, 1996,
the Company has recorded $405,000 as its equity in income from the Russian joint
venture.

The Company accounts for its investment in Summo Minerals Corporation
("Summo") using the equity method of accounting. For the nine months ended
September 30, 1996, the Company has recorded $358,000 as its equity in the
losses of Summo.

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 "Siete Acquisition"). The assets purchased consist primarily of oil
and gas producing properties in the Permian Basin of west Texas and southeast
New Mexico.

The following is pro forma revenue, income from continuing operations and
per share data assuming the Siete Acquisition was effective as of January 1 for
the periods indicated.

<TABLE>
<CAPTION>
PRO FORMA FOR THE
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
<S> <C> <C>
(IN THOUSANDS,
EXCEPT PER SHARE
AMOUNTS)

<CAPTION>
(UNAUDITED)
1995 1996
--------- ---------
<S> <C> <C>
Total operating revenues................................................ $ 30,036 $ 41,817
--------- ---------
--------- ---------
Income from continuing operations....................................... $ 2,005 $ 6,156
--------- ---------
--------- ---------
Income per common share from continuing operations...................... $ .23 $ .70
--------- ---------
--------- ---------
</TABLE>

NOTE 3 -- 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

F-6
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)

NOTE 3 -- CREDIT FACILITY (CONTINUED)

the value of the Company's oil and gas properties and other assets. The
Company's borrowing base, which is redetermined annually, is currently $40
million and is expected to increase for 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 $25.4 million at
September 30, 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 Common Stock.

NOTE 4 -- CONTINGENCIES

On August 23, 1995, a class action law suit was filed against the Company in
the 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. This suit was
dismissed without prejudice on September 12, 1996 upon motion filed by counsel
for the plaintiff class.

NOTE 5 -- INCOME TAXES

Federal income tax expense for the nine month periods ended September 30,
1995 and 1996 differs from the amount that would be provided by applying the
statutory U.S. Federal income tax rate to income before income taxes primarily
due to Section 29 tax credits and percentage depletion. In 1995 the Company also
utilized capital loss carryovers.

NOTE 6 -- SUBSEQUENT EVENTS

In November 1996, the Company adopted a stock option plan which covers a
maximum of 700,000 shares. Options granted under the 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. 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 conjunction
with the termination of future awards under the Company's SAR plan. The Company
will adopt SFAS No. 123, "Accounting for Stock-Based Compensation," in its
annual report on Form 10-K for the year ended December 31, 1996 through
compliance with the disclosure requirements set forth in SFAS No. 123.

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 Partnership Interest"). Upon the closing, which the Company
expects to occur in the first quarter of 1997, the Company will receive cash
consideration of approximately $5.2 million, approximately $1.7 million of
common stock in Ural Petroleum Corporation and a receivable in the form of a
retained production payment of approximately $10.3 million plus interest at 10%
per annum.

F-7
<PAGE>
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, 1994 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, 1995.
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, 1994 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, 1995 in conformity with generally
accepted accounting principles.

As discussed in Notes 1, 3 and 4 to the consolidated financial statements,
the Company changed its method of accounting for income taxes in 1993, its
method of accounting for certain investments in debt and equity securities in
1994, and its method of accounting for impairment of long-lived assets in 1995.

/s/ COOPERS & LYBRAND L.L.P.

Denver, Colorado
March 8, 1996

F-8
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
<S> <C> <C>
1994 1995
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents............................................................. $ 9,976 $ 1,723
Accounts receivable................................................................... 8,388 8,068
Prepaid expenses...................................................................... 165 850
Refundable income taxes............................................................... 376 176
----------- -----------
Total current assets.............................................................. 18,905 10,817
----------- -----------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties......................................................... 150,350 165,750
Unproved oil and gas properties, net of impairment allowance of $1,581 in 1994 and
$2,245 in 1995...................................................................... 8,358 11,752
Other................................................................................. 2,242 2,535
----------- -----------
160,950 180,037
Less accumulated depletion, depreciation, amortization and impairment................. (101,295) (108,392)
----------- -----------
59,655 71,645
----------- -----------
Other assets:
Investment in Russian joint venture................................................... 4,158 4,140
Investment in Summo Minerals Corporation.............................................. 2,514 4,842
Other assets.......................................................................... 4,160 4,682
----------- -----------
10,832 13,664
----------- -----------
$ 89,392 $ 96,126
----------- -----------
----------- -----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable...................................................................... $ 9,461 $ 7,715
----------- -----------
Long-term liabilities:
Long-term debt........................................................................ 11,130 19,602
Deferred income taxes................................................................. 1,758 1,228
Stock appreciation rights............................................................. 958 1,178
Other noncurrent liabilities.......................................................... 51 121
----------- -----------
13,897 22,129
----------- -----------
Commitments and contingencies (Notes 1, 7, 8, 9, 10 and 11)
Stockholders' equity:
Common stock, $.01 par value; authorized -- 15,000,000 shares; issued and outstanding
-- 8,762,604 shares in 1994 and 8,761,855 shares in 1995............................ 88 88
Additional paid-in capital............................................................ 15,845 15,835
Retained earnings..................................................................... 50,037 50,378
Unrealized gain on marketable equity securities -- available for sale................. 64 15
Treasury stock -- 2,572 shares, at cost............................................... -- (34)
----------- -----------
Total stockholders' equity........................................................ 66,034 66,282
----------- -----------
$ 89,392 $ 96,126
----------- -----------
----------- -----------
</TABLE>

The accompanying notes are an integral part
of these consolidated financial statements.

F-9
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDING DECEMBER
31,
-------------------------------
<S> <C> <C> <C>
1993 1994 1995
--------- --------- ---------
Operating revenues:
Oil and gas production......................................................... $ 38,208 $ 38,239 $ 36,569
Gain on sale of proved properties.............................................. -- 418 1,292
Gas contract settlements and other revenues.................................... 424 6,128 789
--------- --------- ---------
Total operating revenues................................................... 38,632 44,785 38,650
--------- --------- ---------
Operating expenses:
Oil and gas production......................................................... 9,341 10,496 10,646
Depletion, depreciation and amortization....................................... 8,775 10,134 10,227
Impairment of proved properties................................................ 3,498 4,219 2,676
Exploration.................................................................... 5,457 8,104 5,073
Abandonment and impairment of unproved properties.............................. 1,020 1,023 2,359
General and administrative..................................................... 4,712 5,261 5,328
Gas contract disputes and other................................................ 638 493 152
Loss in equity investees....................................................... 659 348 579
--------- --------- ---------
Total operating expenses................................................... 34,100 40,078 37,040
--------- --------- ---------
Income from operations........................................................... 4,532 4,707 1,610
Nonoperating income and (expense):
Interest income................................................................ 668 426 287
Interest expense............................................................... (730) (951) (1,183)
--------- --------- ---------
Income from continuing operations before income taxes............................ 4,470 4,182 714
Income tax expense (benefit)..................................................... 1,065 445 (723)
--------- --------- ---------
Income from continuing operations................................................ 3,405 3,737 1,437
Gain on sale of discontinued operations, net of income taxes..................... -- -- 306
--------- --------- ---------
Income before cumulative effect of change in accounting principle................ 3,405 3,737 1,743
Cumulative effect of change in accounting principle.............................. 300 -- --
--------- --------- ---------
Net income....................................................................... $ 3,705 $ 3,737 $ 1,743
--------- --------- ---------
--------- --------- ---------
Net income per common share:
Income from continuing operations.............................................. $ .39 $ .43 $ .17
Gain on sale of discontinued operations........................................ -- -- .03
Cumulative effect of change in accounting principle............................ .03 -- --
--------- --------- ---------
Net income per share............................................................. $ .42 $ .43 $ .20
--------- --------- ---------
--------- --------- ---------
Weighted average common shares outstanding....................................... 8,763 8,763 8,760
--------- --------- ---------
--------- --------- ---------
</TABLE>

The accompanying notes are an integral part
of these consolidated financial statements.

F-10
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
UNREALIZED GAIN
(LOSS) ON
MARKETABLE
EQUITY
COMMON STOCK ADDITIONAL SECURITIES
----------------------- PAID-IN RETAINED AVAILABLE FOR
SHARES AMOUNT CAPITAL EARNINGS SALE
---------- ----------- ----------- --------- ---------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1992.......................... 8,765,048 $ 88 $ 15,875 $ 45,399 $ --
Net income.......................................... -- -- -- 3,705 --
Cash dividends, $.16 per share...................... -- -- -- (1,402) --
Purchase and retirement of common stock............. (2,444) -- (30) -- --
---------- --- ----------- --------- -----
Balance, December 31, 1993.......................... 8,762,604 88 15,845 47,702 --
Adoption of SFAS No. 115............................ -- -- -- -- 589
Unrealized loss..................................... -- -- -- -- (525)
Net income.......................................... -- -- -- 3,737 --
Cash dividends, $.16 per share...................... -- -- -- (1,402) --
---------- --- ----------- --------- -----
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 gain..................................... -- -- -- -- (49)
Purchase and retirement of common stock and other... (749) -- (10) -- --
---------- --- ----------- --------- -----
Balance, December 31, 1995.......................... 8,761,855 $ 88 $ 15,835 $ 50,378 $ 15
---------- --- ----------- --------- -----
---------- --- ----------- --------- -----
</TABLE>

The accompanying notes are an integral part

of these consolidated financial statements.

F-11
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER
31,
-------------------------------
1993 1994 1995
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:

Cash received from oil and gas operations........................................... $ 35,800 $ 41,346 $ 33,663
Cash paid for oil and gas operations, including general and administrative
expenses.......................................................................... (11,246) (13,175) (13,051)
Exploration expenses................................................................ (4,406) (6,860) (3,672)
Interest and other receipts......................................................... 1,341 686 1,356
Interest paid....................................................................... (598) (767) (795)
Income taxes refunded (paid)........................................................ (1,216) (959) 212
--------- --------- ---------
Net cash provided by operating activities....................................... 19,675 20,271 17,713
--------- --------- ---------
Cash flows from investing activities:

Proceeds from sale of oil and gas properties........................................ 642 221 2,337
Capital expenditures, including dry hole costs...................................... (13,492) (16,950) (22,657)
Acquisition of oil and gas properties............................................... (4,848) (5,066) (8,111)
Investment in Russian joint venture................................................. (2,546) (631) (297)
Investment in Summo Minerals Corporation............................................ (305) (219) (4,528)
Other............................................................................... 10 (499) 264
--------- --------- ---------
Net cash used by investing activities........................................... (20,539) (23,144) (32,992)
--------- --------- ---------
Cash flows from financing activities:

Proceeds from long-term debt........................................................ 5,720 -- 19,513
Repayment of long-term debt......................................................... (2,462) (578) (11,041)
Proceeds from issuance of common stock.............................................. 3,222 -- --
Costs and fees related to public offering........................................... (151) -- --
Dividends paid...................................................................... (1,402) (1,402) (1,402)
Other............................................................................... (30) -- (44)
--------- --------- ---------
Net cash provided (used) by financing activities................................ 4,897 (1,980) 7,026
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents.................................. 4,033 (4,853) (8,253)
Cash and cash equivalents at beginning of period...................................... 10,796 14,829 9,976
--------- --------- ---------
Cash and cash equivalents at end of period............................................ $ 14,829 $ 9,976 $ 1,723
--------- --------- ---------
--------- --------- ---------
Reconciliation of net income to net cash provided by operating activities:

Net income.......................................................................... $ 3,705 $ 3,737 $ 1,743
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization.......................................... 8,775 10,134 10,227
Impairment of proved properties................................................... 3,498 4,219 2,676
Loss in equity investees.......................................................... 659 348 579
Gain on sale of oil and gas properties............................................ (43) (390) (1,535)
Dry hole costs.................................................................... 1,201 2,407 1,529
Abandonment and impairment of unproved properties................................. 1,020 1,023 2,359
Deferred income taxes............................................................. 1 (835) (1,038)
Cumulative effect of change in accounting principle............................... (300) -- --
Other............................................................................. 406 105 (407)
--------- --------- ---------
18,922 20,748 16,133
Changes in assets and liabilities:

Accounts receivable................................................................. 282 (450) 166
Refundable income taxes............................................................. 1,095 448 200
Accounts payable and accrued expenses............................................... 605 (402) 706
Deferred income taxes............................................................... (1,229) (73) 508
--------- --------- ---------
Net cash provided by operating activities....................................... $ 19,675 $ 20,271 $ 17,713
--------- --------- ---------
--------- --------- ---------
Supplemental schedule of noncash investing and financing activities:

In July 1993, the Company sold one of its real estate assets for the assumption of the existing $492,000 mortgage.
In January 1994, the Company acquired an additional 10.28% general partnership interest in Panterra Petroleum for
approximately $1.3 million in cash and 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 buy out 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.
</TABLE>

The accompanying notes are an integral part
of these consolidated financial statements.

F-12
<PAGE>
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 a Delaware
corporation engaged in oil and gas exploration, development and production in
the United States and various foreign countries, including Russia, Canada and
Trinidad and Tobago.

Through September 1994, the majority of the Company's domestic operations
and its international operations were managed by various individuals (the
"Anderman Group") through Anderman/Smith Operating Company, now known as St.
Mary Operating Company ("SMOC"). In October 1994, the Company assumed management
of the domestic oil and gas administrative activities of SMOC and 79 employees
of SMOC became employees of the Company. During 1995, the Company and the
Anderman Group terminated their domestic joint participation and management
program and agreed to the sale of all of the Anderman Group stock of SMOC to the
Company at book value in 1996.

In addition, the Company withdrew from all international partnerships
managed by the Anderman Group with the exception of the partnerships with
interests in Russia, Canada and Trinidad and Tobago. While these remaining
international activities continue to be managed by the Anderman Group, the
Company does not intend to participate in any new international ventures managed
by the Anderman Group.

RECLASSIFICATIONS:

Certain amounts in the 1993 and 1994 consolidated financial statements have
been reclassified to correspond to the 1995 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. 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 and do not present
unanticipated credit concerns.

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-13
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)

The Company has accounts with separate banks in Denver, Colorado, Dallas,
Texas and Shreveport, Louisiana. At December 31, 1994 and 1995, the Company had
$8,511,000 and $386,000 respectively, invested in money market funds consisting
of U.S. Treasury obligations.

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. 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,"
which is determined using discounted future net revenues from the producing
field.

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 $3,498,000, $4,219,000 and
$1,673,000 in 1993, 1994 and 1995, 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 a
recovery of costs.

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

F-14
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
estimated useful lives of the assets from 3 to 15 years. Gains and losses on
dispositions are included in operations.

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 (using the lower of (i) prices in effect at the time
of production, (ii) current market price or (iii) contract price, and taking
into consideration the financial stability of the other owners) 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 $896,000 and
$868,000 at December 31, 1994 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
$16,000 and $10,000 on these contracts for the years ended December 31, 1994 and
1995, respectively.

The Company also uses interest rate cap and swap agreements as a hedge
against future interest rate increases on its long-term debt. Gains or losses on
these arrangements are treated as adjustments to interest expense. Premiums paid
on these agreements are amortized into expense over the lives of the agreements.

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.

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.

F-15
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
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 dilutive for any
periods presented.

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 (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
<S> <C> <C>
1994 1995
--------- ---------
Accrued oil and gas sales:
Due from third parties................................................... $ 4,066 $ 4,827
Due from St. Mary Operating Company...................................... 2,277 1,958
Due from joint interest owners........................................... 2,045 1,283
--------- ---------
$ 8,388 $ 8,068
--------- ---------
--------- ---------
</TABLE>

3. MARKETABLE EQUITY SECURITIES:

As of December 31, 1994 and 1995, the Company owned 5,598,003 (42% 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 $2,524,000 and $5,108,000, and warrants to acquire an additional
2,295,000 and 5,495,000 shares, respectively. Exercise prices for the warrants
range from $.77 to $1.01, using the exchange rate in effect on December 31, 1995
($.73). Summo completed its initial public offering effective October 31, 1994
at $.44 per share. The market value of this investment was $5,945,000 at
December 31, 1994 and $7,945,000 at December 31, 1995. The Company's investment
in Summo is accounted for using the equity method of accounting because the
Company's ownership is expected to drop below 50% due to a secondary offering
during 1996. For the years ending December 31, 1994 and 1995, the Company
reported equity in losses from Summo of $20,000 and $257,000, respectively.

As of December 31, 1994 and 1995, the Company owned 88,017 and 67,017 shares
of Arauco Resources Corporation ("Arauco"), an international mining company with
a total cost of $37,000 and $28,000, and a market value net of tax of $53,000
and $18,000, respectively.

Effective October 4, 1994, the Company exchanged 1,034,179 shares of Arauco
for 324,042 shares and warrants to purchase an additional 324,040 shares of
Santa Elina Gold Corporation ("Santa Elina"), an international mining company.
No gain or loss was recognized on the exchange. In January 1995, Santa Elina
completed its initial public offering at $1.50 per share. As of December 31,
1994 and 1995, the

F-16
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

3. MARKETABLE EQUITY SECURITIES: (CONTINUED)

Company owned 324,042 and 296,042 shares of Santa Elina with a total cost of
$437,000 and $400,000, and a market value net of tax of $485,000 and $425,000,
respectively.

The Company adopted SFAS No. 115 in 1994 and classifies the investments in
Arauco and Santa Elina as marketable equity securities available for sale.
Accordingly, unrealized gains and losses for these investments are recorded in
stockholders' equity. The combined net unrealized gain for these investments was
$64,000 at December 31, 1994 and $15,000 at December 31, 1995. During 1995, the
Company realized proceeds from the sale of Arauco and Santa Elina shares of
$25,000 and $44,000, respectively. The Company used the average cost method and
realized a gain of $16,000 on the sale of 21,000 shares of Arauco and $6,000 on
the sale of 28,000 shares of Santa Elina.

4. INCOME TAXES:

The provision for income taxes consists of the following:

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER
31,
-------------------------------
<S> <C> <C> <C>
1993 1994 1995
--------- --------- ---------

<CAPTION>
(IN THOUSANDS)
<S> <C> <C> <C>
Current taxes:
Federal........................................................ $ 477 $ 835 $ 77
State.......................................................... 587 445 396
Deferred taxes................................................... 1 (835) (1,038)
--------- --------- ---------
Total income tax expense (benefit)......................... $ 1,065 $ 445 $ (565)
--------- --------- ---------
--------- --------- ---------
Continuing operations............................................ $ 1,065 $ 445 $ (723)
Discontinued operations.......................................... -- -- 158
--------- --------- ---------
Total income tax expense (benefit)......................... $ 1,065 $ 445 $ (565)
--------- --------- ---------
--------- --------- ---------
</TABLE>

The above taxes are net of alternative fuel credits (Section 29) of $735,000
in 1993, $1,333,000 in 1994 and $624,000 in 1995.

Effective January 1, 1993, the Company adopted the liability method of
accounting for income taxes under SFAS No. 109, "Accounting for Income Taxes."
Prior to 1993, income taxes were calculated in accordance with Accounting
Principles Board Opinion No. 11. The adoption of SFAS No. 109 resulted in a one
time benefit of $300,000 which is reflected as a cumulative effect of a change
in accounting principle. Other than the cumulative effect adjustment, the
adoption of SFAS No. 109 did not have a material effect on 1993 results of
operations.

F-17
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

4. INCOME TAXES: (CONTINUED)

The components of the net deferred tax liability as of December 31, 1994 and
1995 under SFAS No. 109 were as follows (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
<S> <C> <C>
1994 1995
--------- ---------
Deferred tax assets
Non-current
Other assets......................................................... $ (1,756) $ (1,458)
State tax net operating loss carryforward............................ (1,594) (1,402)
Alternative minimum tax credit carryforward.......................... (545) (565)
Federal capital loss carryforward.................................... (292) --
--------- ---------
Total deferred tax assets............................................ (4,187) (3,425)
Valuation allowance.................................................. 1,814 1,402
--------- ---------
Net deferred tax assets.......................................... (2,373) (2,023)
Deferred tax liabilities
Non-current
Oil and gas properties............................................... 3,824 2,886
Net other assets..................................................... 307 365
--------- ---------
Net deferred tax liability....................................... $ 1,758 $ 1,228
--------- ---------
--------- ---------
</TABLE>

At December 31, 1995, the Company had state net operating loss carryforwards
of approximately $23.5 million which expire between 1996 and 2007 and
alternative minimum tax credit carryforwards of $565,000 which may be carried
forward indefinitely. The Company's 1995 valuation allowance relates to its
state net operating loss carryforwards since the Company has historically
recognized net operating losses in the states with carryforwards and anticipates
carryforwards from prior years will expire before they can be utilized. The net
change in valuation allowance in 1995 is primarily a result of the recognition
of a capital loss carryover.

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 and the cumulative effect of change in accounting principle for the
following reasons:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER
31,
-------------------------------
<S> <C> <C> <C>
1993 1994 1995
--------- --------- ---------

<CAPTION>
(IN THOUSANDS)
<S> <C> <C> <C>
Federal statutory taxes.......................................... $ 1,520 $ 1,422 $ 242
Increase (reduction) in taxes resulting from:
State taxes (net of Federal benefit)........................... 387 294 261
Statutory depletion............................................ (187) (174) (173)
Alternative fuel credits (Section 29).......................... (735) (1,333) (624)
Change in valuation allowance.................................. -- 225 (412)
Other.......................................................... 80 11 (17)
--------- --------- ---------
Income tax expense (benefit)..................................... $ 1,065 $ 445 $ (723)
--------- --------- ---------
--------- --------- ---------
</TABLE>

F-18
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

5. LONG-TERM DEBT AND NOTES PAYABLE:

In April 1995, the Company amended its long-term revolving credit facility
dated March 1, 1993 and extended its maturity to February 28, 1998. Borrowings
under this new agreement are limited to the lesser of $30,000,000 or the current
borrowing base, as determined by the bank semi-annually. The borrowing base at
December 31, 1994 and 1995 was $25,000,000 and $30,000,000, respectively. 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 will be collateralized by approximately 75% of the value of the
Company's producing oil and gas properties. In addition, the Company must comply
with certain other covenants, including maintenance of stockholders' equity of
not less than $27 million, limitations on additional indebtedness and payment of
dividends. In 1995, at the Company's request the loan commitment was reduced to
$10,000,000. However, the Company has the option of increasing the commitment to
the maximum allowed. As of December 31, 1995, $8,300,000 was outstanding under
this credit facility.

Through March 31, 1995, interest on borrowings was computed at the bank's
prime rate or LIBOR plus 1.5% (6.0% or 4.9% and 8.5% or 8.0% respectively, at
December 31, 1993 and 1994). 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:

<TABLE>
<CAPTION>
DEBT TO CAPITALIZATION RATIO REVOLVING LOAN TERM LOAN
- ------------------------------------- ------------------------------------- -------------------------------------
<S> <C> <C>
Interest rates:
Less than 30% Prime rate or LIBOR +.5% Prime rate or LIBOR +.75%
Greater than 30%, less than 40% Prime rate or LIBOR +.75% Prime rate or LIBOR +1.0%
Greater than 40%, less than 50% Prime rate or LIBOR + 1.0% Prime rate or LIBOR +1.25%
Greater than 50% Prime rate +.125% or Prime rate +.125% or
LIBOR +1.25% LIBOR +1.5%

COMMITMENT FEES ON UNUSED PORTION SHORT TERM TRANCHE LONG TERM TRANCHE
- ------------------------------------- ------------------------------------- -------------------------------------
<S> <C> <C>
Less than 50% of available borrowings .125% .25%
Greater than 50% of available
borrowings .375% .50%
</TABLE>

At December 31, 1995, the Company's debt to capitalization ratio as defined
was 24% and interest on borrowings is computed at the bank's prime rate or LIBOR
plus .5% (8.5% or 6.16% at December 31, 1995).

In November 1991, the Company entered into a three year interest rate cap
agreement which limited the maximum LIBOR interest rate on a principal amount of
$3,000,000 to 9%. The interest rate cap agreement expired in 1994.

In connection with the acquisition of its 50% general partnership interest
in Panterra, the Company assumed 50% of a bank note payable which was restated
in April 1993. The note, which was due April 30, 1998, was payable in monthly
installments of $350,000, excluding interest. Prior to its restatement, the
agreement provided for borrowings at the bank's prime rate plus 2% or LIBOR plus
3%. The restated agreement provided for borrowings at the lower of the bank's
prime rate plus 1% or LIBOR plus 2.25% (7.0% or 5.63% and 9.5% or 8.75%
respectively, at December 31, 1993 and 1994). The note was collateralized by
substantially all of Panterra's oil and gas properties and cash accounts.

F-19
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

5. LONG-TERM DEBT AND NOTES PAYABLE: (CONTINUED)
On February 6, 1995, Panterra entered into a credit agreement with a bank
whereby funds were advanced to pay in full the restated note due April 30, 1998.
The new credit agreement includes a two year revolving period converting to a
five year amortizing loan on February 6, 1997. During the revolving period,
interest is payable at the bank's prime rate or LIBOR plus 1.5% (8.5% or 7.16%,
at December 31, 1995). 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
commitment amount which will not exceed $20,000,000. During the amortization
period, monthly principal payments are payable at rates decreasing from 2.0% to
1.4% of the outstanding balance through February 2002, at which time the
remaining principal balance is due.

The new Panterra credit agreement is collateralized by all of Panterra's oil
and gas properties and contains restrictive covenants relating to acquisition of
assets, new debt agreements and the maintenance of certain minimum financial
statement ratios by Panterra. The Company's proportionate share of the liability
under Panterra's bank note payable is 74%.

Panterra had entered into an interest rate swap agreement which expired in
July 1994. Under this agreement Panterra paid interest on the $5,000,000 of
notional principal at a fixed rate of 7.98% and received interest on the
notional principal at a floating rate equal to LIBOR. Panterra also entered into
an interest rate cap agreement which limited the interest rate to 9% on a
principal amount of $5,000,000 from July 1992 through July 1993. There were no
outstanding swap agreements at December 31, 1994 or 1995.

The carrying value of long-term debt approximates fair value because the
debt is variable rate and reprices in the short term.

The Company's liability for estimated annual principal payments for the next
five years under both notes payable are as follows:

<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, (IN THOUSANDS)
- ----------------------------------------------------------
<S> <C>
1996...................................................... $ --
1997...................................................... 2,252
1998...................................................... 2,991
1999...................................................... 2,954
2000...................................................... 2,662
Thereafter.............................................. 8,743
-------
$ 19,602
-------
-------
</TABLE>

6. GAS CONTRACT SETTLEMENTS:

During 1993 and 1994, the Company settled several gas contract disputes with
pipeline companies, recognizing income of $235,000 and $5,741,000 respectively.
The Company settled the final two gas contract disputes during 1994.

7. COMMITMENTS AND CONTINGENCIES:

The Company leases office space under operating leases which expire in 1997.
The annual minimum lease payments approximate $398,000. The Company has
noncancelable annual leases with affiliates of

F-20
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

7. COMMITMENTS AND CONTINGENCIES: (CONTINUED)

approximately $239,000. Rent expense, net of sublease income, was $195,000,
$166,000 and $131,000 in 1993, 1994 and 1995, respectively.

Pursuant to a purchase and sale agreement between Panterra and Chevron
U.S.A., Inc. ("Chevron"), Panterra was obligated to pay Chevron an annual
production payment each March 1 through December 31, 1995 if crude oil prices
reached certain specified minimum levels, which escalated from $22.00 to $26.64
from 1991 to 1995. No payments were made under this agreement in 1993, 1994 or
1995.

The Company has the following commodity contracts to hedge or otherwise
reduce the impact of oil and gas price fluctuations in place as of December 31,
1995:

<TABLE>
<CAPTION>
PRODUCT VOLUMES/MONTH FIXED PRICE DURATION
- ---------------------- ---------------------- ---------------------- ----------------------
<S> <C> <C> <C>
Natural Gas 22,500 MMBtu $1.90 1/96 - 6/98
Natural Gas 15,000 MMBtu $1.94 3/96 - 2/98
Natural Gas 24,000 MMBtu $1.83 1/96 - 12/97
Natural Gas 15,000 MMBtu $2.065 1/96 - 5/97
Natural Gas 133,500 MMBtu $1.73 1/96 - 3/96
Natural Gas 96,000 MMBtu $1.96 1/96 - 3/96
Natural Gas 23,000 MMBtu $1.63 1/96 - 2/96
Oil 1,125 Bbls $16.98 1/96 - 9/97
Oil 1,000 Bbls $16.95 1/96 - 4/97
Oil 3,200 Bbls $17.95 1/96 - 1/97
Oil 1,200 Bbls $18.44 2/96 - 1/97
Oil 22,100 Bbls $18.36 - 18.40 1/96 - 12/96
Oil 1,667 Bbls $18.61 1/96 - 6/96
Oil 2,500 Bbls $17.80 1/96
Oil 37,500 Bbls $18.50 - 19.10 1/96 - 3/96
</TABLE>

The fair value of the Company's commodity hedging contracts based on year
end futures pricing would require the Company to pay approximately $415,000, if
these contracts were terminated on December 31, 1995.

During 1993, St. Mary Operating Company, which operates a number of wells in
which the Company has a working interest, was named with others as a defendant
in four Mississippi state court lawsuits in which property owners were seeking
damages for alleged contamination of four well sites. The plaintiffs sought $10
million in compensatory damages and $20 million in punitive damages, an amount
which exceeded the net worth of SMOC. During 1994, one suit was settled for an
amount which was not material, a large portion of which was covered by
insurance, and SMOC was dismissed as a defendant in a second suit. In early
1996, one of the remaining suits was settled for an amount which is not
material, and minor details regarding the settlement of the other remaining suit
are currently being negotiated. Whether insurance will cover the latter
settlements is uncertain at present.

During 1995, the Company and other unrelated parties were named as
defendants in a class action suit filed in Oklahoma seeking payment of royalties
on amounts received in prior gas contract settlements. While the Company's
leases state that royalties are paid only on oil and gas produced and sold, the
end result of any litigation seeking royalty payments on amounts received in oil
and gas settlements cannot be known in advance, and it is possible that a
judgment adverse to the Company could result even though gas

F-21
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

7. COMMITMENTS AND CONTINGENCIES: (CONTINUED)
was not produced and sold. Management believes its position is legally correct
and plans a vigorous defense of this suit. In the event of adverse judgment,
however, management believes the maximum exposure of the Company in this
litigation, exclusive of interest, if any, would be approximately $4.5 million.
The Company has no material exposure to claims for such payments outside of
Oklahoma.

The Company is also aware that, in two appellate proceedings in which the
Company is not involved, the Oklahoma Supreme Court has been asked to address
issues regarding the entitlement of lessors to royalty payments on amounts
received by oil and gas working interest owners as a result of gas contract
claims. While the Company believes that royalties are not owed until oil and gas
is produced and sold, the decision of the Oklahoma Supreme Court cannot be known
in advance and it is possible that the ruling will establish a right of royalty
owners to payment. Such a ruling could adversely affect the Company's position
in the royalty litigation described above.

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 will record compensation expense once it recovers its investment and net
profits attributable to the properties are payable to the employees.

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 1993 the Company awarded 35,684 shares with a
value of $11.50 per share effective January 1, 1993. In 1994 the Company awarded
38,938 shares with a value of $11.63 per share effective January 1, 1994 and in
1995 the Company awarded 34,917 shares with a value of $13.25 per share
effective January 1, 1995. Compensation expense recognized under the SAR plan
was $222,191, $268,286 and $220,247 in 1993, 1994 and 1995, respectively.

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. The exact
sale price depends upon the period of time the stock has been held by the
participant. At December 31, 1995, there were 33,559 shares issued and
outstanding under the Plan. The Company's stock price was $14.00 at December 31,
1995.

In 1990 and 1991, the Company granted certain officers options to acquire
54,612 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.

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

F-22
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

8. COMPENSATION PLANS: (CONTINUED)

income and also may make additional contributions at its discretion.
Contributions to the 401(k) Plan amounted to $64,000, $93,000 and $183,000 for
the years ended December 31, 1993, 1994 and 1995, respectively.

In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." This standard establishes a fair value method of accounting for
stock-based compensation plans either through recognition or disclosure. The
Company will adopt this standard in 1996 through compliance with the disclosure
requirements set forth in SFAS No. 123. It is not believed the adoption of this
standard will have a material impact on the financial position or results of
operations of the Company.

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, 1995, 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:

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost--benefits earned during the year......................... $ 105 $ 129 $ 79
Interest cost on projected benefit obligations........................ 28 45 51
Actual (return) loss on plan assets................................... (63) 27 (133)
Net amortization (deferral)........................................... 36 (94) 61
--------- --------- ---------
Net pension expense................................................... $ 106 $ 107 $ 58
--------- --------- ---------
--------- --------- ---------
</TABLE>

F-23
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

9. PENSION PLANS: (CONTINUED)
A reconciliation of the funded status of the plans to accrued pension
liability is as follows:

<TABLE>
<CAPTION>
SUPPLEMENTAL PLAN
PRIMARY PLAN
DECEMBER 31, DECEMBER 31,
-------------------- --------------------
1994 1995 1994 1995
--------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Actuarial present value of benefits based on service to
date and present pay levels:
Vested................................................................. $ 396 $ 263 $ -- $ 140
Nonvested.............................................................. 67 63 1 --
--------- --------- --- ---------
Accumulated benefit obligation......................................... 463 326 1 140
Additional amounts related to pay increases............................ 261 219 10 127
--------- --------- --- ---------
Projected benefit obligation........................................... 724 545 11 267
Plan assets at fair value.............................................. 712 810 -- --
--------- --------- --- ---------
Projected benefit obligation (in excess of) or less than
plan assets.......................................................... (12) 265 (11) (267)
Unrecognized (gain) loss............................................... 15 (261) 6 192
Unrecognized net asset................................................. (28) (17) -- --
--------- --------- --- ---------
Accrued pension liability included in the consolidated
balance sheets....................................................... $ (25) $ (13) $ (5) $ (75)
--------- --------- --- ---------
--------- --------- --- ---------
</TABLE>

Actuarial assumptions for December 31, 1994 and 1995 are as follows:

<TABLE>
<CAPTION>
1994 1995
--------- ---------
<S> <C> <C>
Discount rate...................................................... 8.50% 7.50%
Average salary growth rate......................................... 6.00% 5.00%
Return on plan assets.............................................. 8.00% 8.00%
</TABLE>

10. RELATED PARTY TRANSACTIONS:

A majority of the Company's oil and gas operations, other than Louisiana
royalties, including acquisition of unproved properties, are administered by
SMOC. Operations were conducted under a domestic agreement with SMOC and 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. The
Company's agreement with the Anderman Group involves its payment of 75% of
acquisition costs and of costs directly associated with the acquisition,
including geological costs which may be required by the foreign license
agreement. The Company's resulting ownership interest in the foreign projects
prior to the

F-24
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

10. RELATED PARTY TRANSACTIONS: (CONTINUED)

involvement of unrelated third parties is 45% and the interest of the Anderman
Group is 55%. Administrative and operational services were provided for these
projects by SMOC of which the Company pays 65%. In certain circumstances, the
Company agreed to fund, through non-recourse loans to individuals in the
Anderman Group, up to 5% of the total project development costs of the Company
and the Anderman Group. At December 31, 1994 and 1995, the amounts of these
loans was approximately $555,000 and $622,000, respectively. In addition,
certain employees of SMOC and outside consultants received net profits interests
of up to 1.5% of the Company's interests in certain international projects.
During 1995, the Company recorded a charge to operations of $252,000 resulting
from its withdrawal from the international partnerships.

Billings from SMOC, which represent charges for lease operating,
exploration, development and general and administrative expenses, amounted to
$10,071,000, $14,008,000 and $11,451,000 for the years ended December 31, 1993,
1994 and 1995, respectively. As of December 31, 1994 and 1995, accounts payable
included $525,000 and $746,000, respectively, owed to SMOC.

SMOC is also responsible for collecting revenues from purchasers for a
number of the Company's wells. During 1993, 1994 and 1995 approximately 29%, 32%
and 33%, respectively, of the Company's oil and gas sales were collected by
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.

Financing commitments have been obtained for the joint venture which are
non-recourse to the Company. The joint venture has received $32.5 million from
loan advances through December 31, 1995. The joint venture received additional
funding of $10 million in February 1996, and anticipates the committed balance
of $10 million to be funded later in 1996. The Company expects all of the
capital requirements for 1996 to be funded from cash flow and non-recourse bank
financing. Through December 31, 1995 the Company had expended $7.5 million on
the Russian project of which $4.1 million has been capitalized. The Company's
impairment policy with respect to this investment is consistent with its policy
for proved oil and gas properties using future net revenues after debt service.
At December 31, 1995, the undiscounted future net revenues attributable to the
Company's share of the Russian joint venture's proved reserves was $36.6 million
(after debt repayment). The present value of estimated future net cash flows
before income taxes discounted at 10% was $20.4 million in accordance with
Securities and Exchange Commission guidelines and may not be indicative of
market value.

F-25
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

11. INVESTMENT IN RUSSIAN JOINT VENTURE: (CONTINUED)
Summarized combined financial information of the Russian joint venture is
shown below:

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------
1993 1994 1995
---------- ----------- -----------
(UNAUDITED, IN THOUSANDS)
<S> <C> <C> <C>
Income Statement:
Oil and gas revenues....................... $ 1,643 $ 15,035 $ 29,479
Operating expenses......................... 6,236 12,707 22,547
Interest and other expenses................ 1,642 5,831 8,966
---------- ----------- -----------
Net income (loss)........................ $ (6,235) $ (3,503) $ (2,034)
---------- ----------- -----------
---------- ----------- -----------
Balance Sheet:
Current assets............................. $ 3,982 $ 12,974 $ 10,105
Non-current assets......................... 26,851 35,034 49,300
Current liabilities........................ 4,904 11,700 10,569
Non-current liabilities.................... 32,170 48,007 50,614
Shareholders' deficit...................... (6,241) (11,699) (1,778)
</TABLE>

12. DISPOSAL OF REAL ESTATE SEGMENT:

Effective June 30, 1992, the Company made the decision to sell its remaining
real estate projects. Accordingly, the Company's real estate activities have
been presented as discontinued operations in the statements of income.

For 1992, the discontinued real estate segment had revenues of $1,298,000,
costs and expenses of $647,000 and a provision for income taxes of $221,000
resulting in income from discontinued operations of $430,000.

The Company recorded a gain on the sale of discontinued operations of
$306,000, net of income taxes of $158,000 in 1995. The Company had no income or
loss from discontinued operations in 1993 and 1994.

The Company's remaining real estate assets consist of land held for sale
with a carrying cost of $1,806,000 and $1,311,000 as of December 31, 1994 and
1995, respectively, which is less than the estimated net realizable values.

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES:

MAJOR CUSTOMERS:

There were no sales to individual customers constituting 10% or more of
total revenues during 1993, 1994 and 1995.

F-26
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES: (CONTINUED)
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES:

Costs incurred in oil and gas property acquisition, exploration and
development activities, whether capitalized or expensed, are summarized as
follows:

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
------------------------------------
1993 1994 1995
---------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Unproved property acquisitions............... $ 1,847 $ 3,228 $ 2,937
Proved property acquisitions................. 4,848 12,279 8,111
Exploration costs:
Domestic................................... 9,013 9,481 8,746
International.............................. 647 877 (112)
Development costs............................ 7,079 5,946 12,625
---------- ----------- -----------
Total.................................... $ 23,434 $ 31,811 $ 32,307
---------- ----------- -----------
---------- ----------- -----------
Russian joint venture, equity method......... $ 1,872 $ 1,551 $ 3,213
---------- ----------- -----------
---------- ----------- -----------
</TABLE>

OIL AND GAS RESERVE QUANTITIES (UNAUDITED):

The reserve information as of December 31, 1993, 1994 and 1995 was prepared
by the Company and Ryder Scott Company. The Company emphasizes that reserve
estimates are inherently imprecise and that estimates of new discoveries are
more imprecise than those of proved producing oil and gas properties.
Accordingly, these estimates are expected to change as future information
becomes available.

Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods.

F-27
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES: (CONTINUED)
Presented below is a summary of the changes in estimated domestic reserves
of the Company, and its share of the Russian joint venture reserves:

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------------------------------------------
1993 1994 1995
---------------------- ------------------------ ----------------------
GAS OIL OR GAS OIL OR GAS
OIL OR --------- CONDENSATE --------- CONDENSATE ---------
CONDENSATE ------------- -----------
----------- (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
(MBBL)
<S> <C> <C> <C> <C> <C> <C>
Total proved U.S. reserves:
Developed and undeveloped:
Beginning of year........................ 4,594 51,663 4,590 56,535 6,677 62,515
Revisions of previous estimates.......... (428) 5,927 446 5,064 39 515
Discoveries and extensions............... 566 9,262 658 10,274 894 16,069
Purchase of minerals in place............ 756 1,200 2,062 3,262 1,095 9,274
Sale of reserves......................... (52) (370) (142) (43) (152) (234)
Production............................... (846) (11,147) (937) (12,577) (1,044) (12,434)
----------- --------- ----- --------- ----------- ---------
End of year (a)........................ 4,590 56,535 6,677 62,515 7,509 75,705
----------- --------- ----- --------- ----------- ---------
----------- --------- ----- --------- ----------- ---------
Proved developed U.S. reserves:
Beginning of year........................ 4,296 48,466 4,160 54,420 6,050 58,661
----------- --------- ----- --------- ----------- ---------
----------- --------- ----- --------- ----------- ---------
End of year.............................. 4,160 54,420 6,050 58,661 6,829 66,230
----------- --------- ----- --------- ----------- ---------
----------- --------- ----- --------- ----------- ---------
Russian joint venture reserves, end of
year................................. 10,921 -- 9,915 -- 7,247 2,536
----------- --------- ----- --------- ----------- ---------
----------- --------- ----- --------- ----------- ---------
</TABLE>

(a) At December 31, 1993, 1994 and 1995, includes approximately 2,800, 2,500 and
1,895 MMcf, respectively representing the Company's underproduced gas
balancing position.

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-28
<PAGE>
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES: (CONTINUED)
The following summary sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in SFAS No. 69:

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------
1993 1994 1995
---------- ---------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows..................................... $ 190,257 $ 202,454 $ 292,149
Future production and development costs................. (54,956) (73,204) (105,520)
Future income taxes..................................... (38,499) (28,977) (49,383)
---------- ---------- -----------
Future net cash flows................................... 96,802 100,273 137,246
10% annual discount..................................... (32,311) (39,407) (49,547)
---------- ---------- -----------
Standardized measure of discounted future net cash
flows................................................. $ 64,491 $ 60,866 $ 87,699
---------- ---------- -----------
---------- ---------- -----------
Russian joint venture standardized measure of discounted
future net cash flows................................. $ 5,431 $ 25,242 $ 15,077
---------- ---------- -----------
---------- ---------- -----------
</TABLE>

The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
----------------------------------
1993 1994 1995
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year............................. $ 62,202 $ 64,491 $ 60,866
Sales of oil and gas produced, net of production costs.............. (28,867) (27,743) (25,923)
Net changes in prices and production costs.......................... (1,993) (16,196) 23,432
Extensions, discoveries and other, net of production costs.......... 15,066 12,507 23,863
Purchase of minerals in place....................................... 6,133 11,114 10,287
Development costs incurred during the year.......................... 1,041 1,655 2,189
Changes in estimated future development costs....................... (493) (1,227) (1,801)
Revisions of previous quantity estimates............................ 3,901 6,941 856
Accretion of discount............................................... 8,962 9,052 8,469
Sales of reserves in place.......................................... -- -- (1,365)
Net change in income taxes.......................................... 1,237 6,771 (12,817)
Other............................................................... (2,698) (6,499) (357)
---------- ---------- ----------
Standardized measure, end of year................................. $ 64,491 $ 60,866 $ 87,699
---------- ---------- ----------
---------- ---------- ----------
</TABLE>

F-29
<PAGE>
EXHIBIT A

January 13, 1997

St. Mary Land & Exploration Company
1776 Lincoln Street, Suite 1100
Denver, Colorado 80203

Attention: Douglas W. York

At your request we have prepared an estimate of the reserves and future
production and income attributable to certain leasehold and royalty interests of
St. Mary Land & Exploration Company as of December 31, 1996. Ryder Scott Company
Petroleum Engineers (Ryder Scott) has evaluated approximately 496 properties
which account for approximately 81.5 percent of the future net income discounted
at ten percent as of December 31, 1996. We have been assured that the income
data have been estimated using the Securities and Exchange Commission (SEC)
guidelines for future cost and price parameters. The results of this study are
summarized below:

The estimated reserve quantities and future income quantities presented in
this report are related to hydrocarbon prices. December 31, 1996 hydrocarbon
prices were used in the preparation of this report as required by SEC
guidelines; however, actual future prices may vary significantly due to seasonal
price variations. Therefore, quantities of reserves actually recovered and
quantities of income actually received may differ significantly from the
estimated quantities presented in this report.

SEC PARAMETERS
ESTIMATED NET RESERVE AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
ST. MARY LAND & EXPLORATION COMPANY
AS OF DECEMBER 31, 1996

<TABLE>
<CAPTION>
NET OIL TOTAL PROVED FUTURE NET INCOME
M BARRELS NET GAS MMCF DISCOUNTED AT 10%
----------- ------------ ------------------------
<S> <C> <C> <C>
Evaluated by Ryder Scott at 12-31-96.......................... 8,085.3 93,441 $ 241,646,047
Evaluated by St. Mary......................................... 2,605.4 33,616 $ 54,815,193
Total Proved Reserves......................................... 10,690.7 127,057 $ 296,461,240
</TABLE>

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes have been represented to Ryder Scott Company as sales gas expressed in
millions of cubic feet (MMCF) at the official temperature and pressure bases of
the areas where the gas reserves are located.

The deductions are comprised of the production taxes, normal direct costs of
operating the wells, ad valorem taxes, recompletion costs, development costs and
St. Mary Land & Exploration Company's estimate of revenue from their current gas
balancing position. The future net income is before the deduction of state and
federal income taxes and general corporate overhead, and has not been adjusted
for outstanding loans which may exist nor does it include any adjustments for
cash on hand or undistributed income.

The discounted future net income shown above is based on a discount rate of
10 percent per annum compounded annually.

A-1
<PAGE>
RESERVES INCLUDED IN THIS REPORT

The proved reserves, as evaluated by Ryder Scott Company, included herein
conform to the definition as set forth in the Securities and Exchange
Commission's Regulation S-X Part 210.4-10(a) as clarified by subsequent
Commission Staff Accounting Bulletins. Our definitions of proved reserves are
attached.

RESERVE ESTIMATES

In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion.

The reserve estimates by the performance method utilized extrapolations of
various historical data in those cases where such data were definitive in our
opinion. Reserves were estimated by the volumetric method in those cases where
there was inadequate historical performance data to establish a definitive trend
or where the use of production performance data as a basis for the reserve
estimates was considered to be inappropriate and the volumetric data were
adequate for a reasonable estimate.

The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.

FUTURE PRODUCTION RATES

Initial production rates are based on the current producing rates for those
reservoirs now on production. Test data and other related information were used
to estimate the anticipated initial production rates for those wells or
locations which are not currently producing. If no production decline trend has
been established, future production rates were held constant, or adjusted for
the effects of curtailment where appropriate, until a decline in ability to
produce was anticipated. The future anticipated decline was then applied to
depletion of the reserves. If a decline trend has been established, this trend
was used as the basis for estimating future production rates. For reserves not
yet on production, sales were projected to commence at an anticipated date of
delivery which was furnished by St. Mary Land & Exploration Company.

In general, we estimate that gas production rates will continue to be the
same as the average rate for the latest available 12 month of actual production
until such time that the well or wells are incapable of producing at this rate.
Our general policy on estimates of future gas production rates is adjusted when
necessary to reflect actual gas market conditions in specific cases.

The future production rates from reservoirs now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.

HYDROCARBON PRICES

St. Mary Land & Exploration Company furnished us with hydrocarbon prices in
effect at December 31, 1996, a West Texas Intermediate crude oil price of $25.08
per barrel and Gulf Coast spot gas price of $3.736 per MMBTU. Product prices
which are actually used for each property reflect adjustment from the above
stated prices for gravity, quality, local conditions and/or distance from
market. These prices were held constant to depletion of the properties. In
accordance with Securities and Exchange Commission guidelines, changes in
hydrocarbon prices subsequent to December 31, 1996 were not considered in this
report.

A-2
<PAGE>
COSTS

Operating costs for the leases and wells in this report were furnished by
St. Mary Land & Exploration Company. When applicable, the operating costs
include a portion of general and administrative costs allocated directly to the
leases and wells under the terms of operating agreements. Development costs were
furnished to us by St. Mary Land & Exploration Company and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. The current operating and development costs were held constant
throughout the life of the properties. Ryder Scott has accepted the operating
and development cost data supplied by St. Mary Land & Exploration Company's
request, this study does not consider the salvage value of the lease equipment
or the abandonment cost since both have been assumed to be relatively
insignificant and tend to offset each other. No deduction was made for indirect
costs such as general administration and overhead expenses, loan repayments,
interest expenses and exploration and development prepayments which are not
charged directly to the leases or wells.

GENERAL

Ryder Scott Company performed the reserve analyses and projections of future
production for these interests. However, at the request of St. Mary Land &
Exploration Company, the economic analyses were performed by St. Mary Land &
Exploration Company on Munro Garrett International's economic program "Advanced
Reserves and Information Evaluation System (ARIES)." Ryder Scott has confirmed
that the values used for scheduling the individual wells' production were
correct. We performed such tests and procedures as we considered necessary under
the circumstances to render the conclusions set forth herein. It is our opinion
that the data presented for the properties we have evaluated fairly reflect the
estimated net reserves and future income based on the prices and costs provided
by St. Mary Land & Exploration Company.

While it may reasonably be anticipated that the prices received by St. Mary
Land & Exploration Company for the sale of its production may be higher or lower
than the prices used in this evaluation as described above, and the operating
costs relating to such production may also increase or decrease from existing
levels, such possible changes in prices and costs were, in accordance with rules
adopted by the SEC, omitted from consideration in making this evaluation.

The reserve estimates presented herein are based upon a detailed study of
the properties in which St. Mary Land & Exploration Company owns an interest;
however, we have not made any field examination of the properties. St. Mary Land
& Exploration Company has provided Ryder Scott with an ARIES database with
production data and well test data where available. Ryder Scott has accepted
this data as accurate and not verified or updated the data provided and have
based our reserve estimates on this data as provided. It should be noted that
additional historical data, both production and well test data, is available on
certain properties through public sources of information. No consideration was
given in this report to potential environmental liabilities which may exist nor
were any costs included for potential liability to restore and clean up damages,
if any, caused by past operating practices. St. Mary Land & Exploration Company
has informed us that they have furnished us all of the production information,
accounts, records, geological and engineering data and reports and other data
required for this investigation. The ownership interests, prices, product
classifications relating to prices, gas balancing information and other factual
data furnished to Ryder Scott by St. Mary Land & Exploration Company in
connection with this investigation were accepted without independent
verification. The estimates presented in this report are based on data available
through December 31, 1996.

Neither Ryder Scott Company nor any of its employees has any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future income for
the subject properties.

A-3
<PAGE>
This report was prepared for the exclusive use of St. Mary Land &
Exploration Company. The data, work papers and maps used in the preparation of
this report are available for examination by authorized parties in our offices.
Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Gary Krieger, P.E.
Vice President

GK:ph
(SEAL)
COLORADO REGISTERED PROFESSIONAL ENGINEER
Gary Grant Krieger, No. 28782

A-4
<PAGE>
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NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS IN CONNECTION WITH THIS OFFERING
OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS. ANY INFORMATION OR REPRESENTATION
NOT HEREIN CONTAINED, IF GIVEN OR MADE, MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL
OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITY OTHER THAN THE SECURITIES
OFFERED BY THIS PROSPECTUS, NOR DOES IT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY THE SECURITIES BY ANY PERSON IN ANY JURISDICTION
WHERE SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON
MAKING SUCH OFFER IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. THE DELIVERY OF THIS PROSPECTUS
SHALL NOT, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN
NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF.

------------------------

TABLE OF CONTENTS

Prospectus Summary........................... 3

Risk Factors................................. 10

Use of Proceeds.............................. 14

Capitalization............................... 15

Price Range of Common Stock.................. 16

Dividend Policy.............................. 16

Selected Consolidated Financial Data......... 17

Management's Discussion and Analysis of
Financial Condition and Results of
Operations................................. 19

Business and Properties...................... 27

Management................................... 39

Description of Common Stock.................. 41

Underwriting................................. 41

Legal Matters................................ 43

Experts...................................... 43

Available Information........................ 43

Incorporation of Certain Documents by
Reference.................................. 43

Glossary..................................... 45

Index to Consolidated Financial Statements... F-1

Summary Reserve Report of Ryder Scott
Company.................................... Exhibit A
</TABLE>

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