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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ x ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 2002
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
Commission file number 001-31539
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 41-0518430
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1776 Lincoln Street, Suite 700, Denver, Colorado 80203
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(Address of principal executive offices) (Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b)of the Act:
Title of each class Name of each exchange
on which registered
Common Stock, $.01 par value New York Stock Exchange
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Securities registered pursuant to Section 12(g)of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ x ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12-6-2 of the Act). Yes [ x ] No [ ]
The aggregate market value of 27,152,051 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
common stock on June 28, 2002, the last business day of the registrant's most
recently completed second fiscal quarter, of $24.06 per share as reported on the
Nasdaq National Market System, on which St. Mary's common stock was traded at
the time, was $653,278,347. Shares of common stock held by each director and
executive officer and by each person who owns 10% or more of the outstanding
common stock or who is otherwise believed by the Company to be in a control
position have been excluded. This determination of affiliate status is not
necessarily a conclusive determination for other purposes.
As of March 3, 2003, the registrant had 31,433,900 shares of common
stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Items 10, 11, 12 and 13 of Part III is incorporated
by reference from portions of the registrant's definitive proxy statement
relating to its 2003 annual meeting of stockholders to be filed within 120 days
from December 31, 2002.
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TABLE OF CONTENTS
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ITEM PAGE
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PART I
ITEM 1. BUSINESS.............................................................1
Background.......................................................1
Business Strategy................................................2
Significant Developments Since December 31, 2001.................3
Major Customers..................................................4
Employees and Office Space.......................................5
Title to Properties..............................................5
Competition......................................................5
Government Regulations...........................................5
Risk Factors....................................................10
Cautionary Statement about Forward-Looking Statements...........20
Available Information...........................................21
Glossary........................................................21
ITEM 2. PROPERTIES..........................................................23
Operations......................................................23
Acquisitions....................................................28
Reserves........................................................28
Production......................................................29
Productive Wells................................................30
Drilling Activity...............................................30
Acreage.........................................................31
ITEM 3. LEGAL PROCEEDINGS...................................................32
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................32
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT................................33
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS.........................................34
ITEM 6. SELECTED FINANCIAL DATA.............................................36
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TABLE OF CONTENTS
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(Continued)
ITEM PAGE
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................38
Overview........................................................38
Critical Accounting Policies and Estimates......................38
Results of Operations...........................................41
Liquidity and Capital Resources.................................46
Accounting Matters..............................................53
Effects of Inflation and Changing Prices........................54
Environmental...................................................55
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.........................................................55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................56
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.................................56
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................56
ITEM 11. EXECUTIVE COMPENSATION..............................................57
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS......................57
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................57
ITEM 14. CONTROLS AND PROCEDURES.............................................57
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K.................................................58
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PART I
When we use the terms "St. Mary," "we," "us" or "our," we are referring to St.
Mary Land & Exploration Company and its subsidiaries, unless the context
otherwise requires. We have included technical terms important to an
understanding of our business under "Glossary". Throughout this document we make
statements that are classified as "forward-looking". Please refer to the
"Cautionary Statement about Forward-Looking Statements" section of this document
for an explanation of these types of assertions.
ITEM 1. BUSINESS
Background
St. Mary Land & Exploration Company is an independent energy
company engaged in the exploration, development, acquisition and production of
natural gas and crude oil. St. Mary was founded in 1908 and incorporated in
Delaware in 1915. Our operations are focused in the following five core
operating areas in the United States:
o the Mid-Continent region in Oklahoma and northern Texas;
o the ArkLaTex region that spans northern Louisiana and portions
of Arkansas, Mississippi and eastern Texas;
o the onshore Gulf Coast and offshore Gulf of Mexico;
o the Rocky Mountain region consisting of the Williston Basin in
eastern Montana and western North Dakota and the Powder River,
Green River and Wind River Basins in Wyoming; and
o the Permian Basin in eastern New Mexico and western Texas.
As of December 31, 2002, we had estimated proved reserves of
approximately 36.1 MMBbls of oil and 274.2 Bcf of natural gas, or a total of
490.9 BCFE, 88% of which were proved developed and 56% of which were natural
gas, with a PV-10 value of $824.8 million. For the year ended December 31, 2002,
we produced 55.1 BCFE representing average daily production of 150.8 MMCFE per
day.
We focus our resources in selected domestic basins where we believe
that our expertise in geology, geophysics and drilling and completion techniques
provides us with competitive advantages. We have assembled a balanced program of
low-to-medium-risk development and exploitation projects to provide the
foundation for steady growth. In addition, we have a portfolio of
higher-potential exploration projects and non-conventional gas plays in the
Rocky Mountain region that we believe could significantly increase our reserves
and production. We measure and rank our investment decisions based on their
risk-adjusted impact on per share net asset value. In the past, we have sold
selected assets when we believed attractive prices were available, and we will
continue to evaluate such opportunities in the future.
We seek to develop our existing property base and acquire acreage with
additional potential in our core areas. From January 1, 2000, through December
31, 2002, we participated in the drilling or recompletion of 623 gross wells
with an average success rate of 82%. During that same period we added estimated
1
proved reserves of 347 BCFE at an average finding cost of $1.44 per MCFE. Our
average annual production replacement was 214% during this three-year period,
and our production has grown at an average rate of 21% per year over the same
time period.
As of December 31, 2002, we had an acreage position of 1,145,507 gross
(542,736 net) acres of which 504,873 gross (325,290 net) acres were undeveloped.
For 2003 we have budgeted capital expenditures of $135 million for ongoing
development, exploitation and exploration programs in our core operating areas
and $90 million for acquisitions of oil and gas properties.
Our principal offices are located at 1776 Lincoln Street, Suite 700,
Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Business Strategy
Our objective is to build stockholder value through consistent economic
growth in reserves and production that increase net asset value per share, cash
flow per share and earnings per share. The principal elements of our strategy
are as follows:
o Maintain Focused Geographic Operations. We focus on
exploration, development and acquisition activities in five
core operating areas where we have built a balanced portfolio
of proved reserves, development drilling opportunities and
higher-potential exploration and non-conventional gas
prospects. We believe that our leasehold position is a
strategic asset. Our senior technical managers, each
possessing over 20 years of experience, head up regional
technical offices supported by centralized administration in
our Denver office. We believe that our long-standing presence,
our established networks of local industry relationships and
our acreage holdings in our core operating areas provide us
with a competitive advantage. In addition, we believe that we
can continue to expand our operations without the need to
proportionately increase the number of employees.
o Continue Exploitation and Development of Existing Properties.
We use our comprehensive base of geological, geophysical,
engineering and production experience in each of our core
operating areas to source prospects for our ongoing
low-to-medium-risk development and exploitation programs. We
conduct detailed geologic studies and use an array of
technologies and tools including 2-D and 3-D seismic imaging,
hydraulic fracturing and reservoir stimulation techniques, and
specialized logging tools to enhance the potential of our
existing properties. In 2002 we participated in the drilling
or recompletion of 168 gross wells with a 79% success rate.
o Pursue Higher-Risk Higher-Potential Exploration Projects. We
have allocated approximately 7% of our 2003 drilling and
exploration capital expenditures budget to higher-potential
exploration and unconventional gas projects. Our strategy is
to test several of these prospects each year that in total
have the potential to significantly increase our reserves. We
seek to invest in a diversified mix of projects and generally
limit our capital exposure by participating with other
experienced industry partners. We plan to test projects in the
Mid-Continent region and Rocky Mountain area during 2003.
o Make Selective Acquisitions. We seek to make selective niche
acquisitions of oil and gas properties that complement our
existing operations, offer economies of scale and provide
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further development, exploitation and exploration
opportunities based on proprietary geologic concepts. We
believe that the focus on smaller, negotiated transactions
where we have specialized geologic knowledge or operating
experience has enabled us to acquire attractively priced and
under-exploited properties. In addition, we will pursue
corporate acquisitions that we believe will be accretive.
Examples of this type of acquisition include our 1999 Nance
Petroleum Corporation and King Ranch Energy, Inc.
acquisitions, both of which were acquired with our common
stock. We have budgeted $90.0 million for acquisitions in
2003, of which $74.0 million closed in January 2003, including
the acquisition of properties from Flying J Oil & Gas Inc.
and Big West Oil & Gas Inc. in exchange for the issuance
of 3,380,818 restricted shares of St. Mary common stock.
o Control Operations. We believe it is important to control
geologic and operational decisions as well as the timing of
those decisions. At December 31, 2002, we operated 31% of our
properties on a volume basis and 66% on a PV-10 value basis.
We are the operator of properties representing approximately
81% of our 2003 capital budget.
o Maintain Financial Flexibility. Conservative use of financial
leverage has long been a critical element of our strategy. We
believe that maintaining a strong balance sheet is a
significant competitive advantage that enables us to pursue
acquisition and other opportunities, especially in weaker
price environments. It also provides us with the financial
resources to weather periods of volatile commodity prices or
escalating costs.
Significant Developments Since December 31, 2001
o 2002 Acquisitions of Oil and Gas Properties. In December 2002
St. Mary completed a $69.5 million acquisition of properties
in the Williston Basin from Burlington Resources Oil & Gas
Company LP. The properties are located in Montana and North
Dakota and produce approximately 3,100 barrels of oil and
3,300 Mcf of gas per day. Smaller acquisitions during 2002
included the $7.5 million Mid-Continent acquisition from
Merchant Resources LP, the $4.9 million acquisition in the
Huxley Field located in east Texas and $5.8 million in various
other properties. We used cash from our March 2002 senior
convertible note placement and borrowings under our bank
credit facility to fund these acquisitions.
o 2003 Acquisition of Oil and Gas Properties. In January 2003
St. Mary issued 3,380,818 shares of its restricted common
stock valued at $71.6 million to acquire Rocky Mountain
properties from Flying J Oil & Gas Inc. and Big West Oil
& Gas Inc. This acquisition included properties located in
the Williston, Powder River and Green River Basins with 66.9
BCFE of proved reserves and production of approximately 2,100
barrels of oil and 8,200 Mcf of gas per day. We also received
a net amount of $2.8 million in cash for normal purchase price
adjustments. In addition, St. Mary made a non-recourse loan to
Flying J and Big West of $71.6 million at LIBOR plus 2% for up
to a 39-month period. The loan is secured by a pledge of the
shares of St. Mary stock issued to Flying J and Big West. The
loan was funded through borrowings under our bank credit
facility.
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o Increase in 2002 Year-End Reserves. Proved reserves increased
28% from December 31, 2001 to 490.9 BCFE as of December 31,
2002. We added 101.6 BCFE through acquisitions for cash and
40.3 BCFE from drilling activities. There were net upward
revisions of previous reserves totaling 26.4 BCFE. This upward
revision was the result of a 33.9 BCFE increase from price
revisions, which was partially offset by 7.5 BCFE in negative
performance revisions.
o New York Stock Exchange Listing. On November 20, 2002 St. Mary
Land & Exploration Company's common stock began trading on
the New York Stock Exchange. The Company believes the NYSE
will improve visibility with investors and the auction market
structure will help reduce intra-day volatility and increase
the liquidity in St. Mary's stock. Prior to November 20, 2002
St. Mary's common stock was traded on the Nasdaq National
Market System.
o Senior Convertible Notes. In March 2002 we issued in a private
placement a total of $100.0 million of our 5.75% senior
convertible notes due 2022 with a1/2% contingent interest
provision. We received net proceeds of $96.7 million after
deducting the initial purchasers' discount and offering
expenses paid by us. The notes are general unsecured
obligations and rank on a parity in right of payment with all
our existing and future senior indebtedness and other general
unsecured obligations. They are senior in right of payment to
all our future subordinated indebtedness. The notes are
convertible into our common stock at a conversion price of
$26.00 per share, subject to adjustment. We can redeem the
notes with cash in whole or in part at a repurchase price of
100% of the principal amount plus accrued and unpaid interest
beginning on March 20, 2007. The note holders have the option
of requiring us to repurchase the notes for cash at 100% of
the principal amount plus accrued and unpaid interest
(including contingent interest) upon (1) a change in control
of St. Mary or (2) on March 20, 2007, March 15, 2012 and March
15, 2017. On March 20, 2007, we may pay the repurchase price
with cash, shares of our common stock or any combination of
cash and our common stock. We are not restricted from paying
dividends, incurring debt, or issuing or repurchasing our
securities under the indenture for the notes. There are no
financial covenants in the indenture. We used a portion of the
net proceeds from the notes to repay our credit facility
balance and used the remaining net proceeds to fund a portion
of our 2002 capital expenditures.
o Revolving Credit Agreement. In January 2003 we entered into a
new long-term revolving credit agreement with nine banks. The
maximum loan amount is $300 million with a calculated
borrowing base of $250 million. We have reduced the commitment
amount to $150 million to meet our projected needs. The
maturity date is January 27, 2006. Interest is accrued based
on the borrowing base utilization and is currently LIBOR plus
1.25%.
Major Customers
During 2002 there were no sales to individual customers that accounted
for more than 10% of our total oil and gas production revenue. During 2001 sales
to Transok Gas Company accounted for 12.0% and sales to BP Amoco accounted for
11.3% of our total oil and gas production revenue. During 2000 sales to BP Amoco
accounted for 22.3% of our total oil and gas production revenue.
4
Employees and Office Space
As of December 31, 2002, St. Mary had 185 full-time employees. None of
our employees are subject to a collective bargaining agreement. We consider our
relations with our employees to be good. We lease approximately 42,660 square
feet of office space in Denver, Colorado for our executive and administrative
offices, of which 9,479 square feet is subleased. We also lease approximately
14,990 square feet of office space in Tulsa, Oklahoma; approximately 11,740
square feet in Shreveport, Louisiana; approximately 7,500 square feet in
Lafayette, Louisiana; and approximately 15,830 square feet in Billings, Montana.
Title to Properties
Substantially all of our working interests are held pursuant to leases
from third parties. A title opinion is usually obtained prior to the
commencement of drilling operations on properties. We have obtained title
opinions or conducted a thorough title review on substantially all of our
producing properties and believe that we have satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. Our properties are subject to a mortgage under our credit facility,
customary royalty interests, liens for current taxes, and other burdens that we
believe do not materially interfere with the use of or affect the value of such
properties. We perform only a minimal title investigation before acquiring
undeveloped properties.
Competition
The oil and gas industry is intensely competitive. Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and gas reserves. Our competitive position depends on our
geological, geophysical and engineering expertise, our financial resources, and
our ability to select, acquire and develop proved reserves. We believe that the
locations of our leasehold acreage, our exploration, drilling and production
capabilities and the experience of our management and that of our industry
partners generally enable us to compete effectively in our core operating areas.
However, we compete with a substantial number of major and independent oil and
gas companies that have larger technical staffs and greater financial and
operational resources than we do. Many of these companies not only engage in the
acquisition, exploration, development and production of oil and natural gas
reserves, but also have refining operations, market refined products and
generate electricity. We also compete with other oil and natural gas companies
in attempting to secure drilling rigs and other equipment necessary for drilling
and completion of wells. Drilling equipment may be in short supply from time to
time.
Government Regulations
Our business is subject to various federal, state and local laws and
governmental regulations that may be changed from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties,
taxation and environmental protection. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and gas wells below actual production capacity in order to
conserve supplies of oil and gas.
St. Mary'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. We could be liable for
environmental damages caused by previous property owners. As a result,
substantial liabilities to third parties or governmental entities may be
5
incurred, and the payment of such liabilities could have a material adverse
effect on our financial condition and results of operations. We maintain
insurance coverage for our operations, including limited coverage for sudden
environmental damages, but we do not believe that insurance coverage for
environmental damage that occurs over time is available at a reasonable cost.
Moreover, we do 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, we may be subject to liability or may lose
substantial portions of our properties in the event of certain environmental
damages. St. Mary could incur substantial costs to comply with environmental
laws and regulations.
Energy Regulations. With respect to federal energy regulation, the
transportation and sale for resale of natural gas in interstate commerce have
historically been regulated pursuant to several laws enacted by Congress and
regulations promulgated under these laws by the Federal Energy Regulatory
Commission and its predecessor. In the past the federal government has regulated
the prices at which gas could be sold. Congress removed all price and non-price
controls affecting wellhead sales of natural gas effective January 1, 1993.
However, Congress could reenact price controls in the future.
Our sales of natural gas are affected by the availability, terms and
cost of transportation. The price and terms of access to pipeline transportation
are subject to extensive federal and state regulation. From 1985 to the present,
several major regulatory changes have been implemented by Congress and the FERC
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC is continually proposing and implementing new rules and
regulations affecting those segments of the natural gas industry that remain
subject to the FERC's jurisdiction, most notably interstate natural gas
transmission companies. These initiatives may also affect the intrastate
transportation of gas under certain circumstances. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry, and these initiatives generally reflect more
light-handed regulation.
The ultimate impact of the complex rules and regulations issued by the
FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial and
final FERC decisions. We cannot predict what further action the FERC will take
on these matters. Some of the FERC's more recent proposals may, however,
adversely affect the availability and reliability of interruptible
transportation service on interstate pipelines. Additional proposals and
proceedings that might affect the natural gas industry are pending before
Congress and the courts. The natural gas industry historically has been very
heavily regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will continue. We
do not believe that we will be affected by any action taken that differs
materially from other natural gas producers and marketers with whom we compete.
Our sales of crude oil, condensate and natural gas liquids are
currently not regulated and are made at market prices. However, in a number of
instances the ability to transport and sell such products are dependent on
pipelines whose rates, terms and conditions of service are subject to FERC
jurisdiction under the Interstate Commerce Act. Certain regulations implemented
by the FERC in recent years could result in an increase in the cost of
transportation service on certain petroleum product pipelines. We do not believe
that these regulations affect us any differently than other producers of these
products.
Certain operations we conduct are on federal oil and gas leases that
the Minerals Management Service administers. The MMS issues such leases through
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competitive bidding. These leases contain relatively standardized terms and
require compliance with detailed MMS regulations and, for offshore leases,
orders pursuant to the Outer Continental Shelf Lands Act, which are subject to
change by the MMS. For offshore operations, lessees must obtain MMS approval for
exploration plans and development and production plans prior to the commencement
of such operations. In addition to permits required from other agencies such as
the Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency, lessees must obtain a permit from the MMS prior to the commencement of
drilling. Lessees must also comply with detailed MMS regulations governing,
among other things:
o engineering and construction specifications for offshore
production facilities;
o safety procedures;
o flaring of production;
o plugging and abandonment of Outer Continental Shelf or OCS
wells;
o calculation of royalty payments and the valuation of
production for this purpose; and
o removal of facilities.
To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met. The cost of such bonds or other
surety can be substantial, and we cannot assure that we can continue to obtain
bonds or other surety in all cases. Under certain circumstances the MMS may
require our operations on federal leases to be suspended or terminated.
Many of the states in which we conduct our oil and gas drilling and
production activities regulate such activities by requiring, among other things,
drilling permits and bonds and reports concerning operations. The laws of these
states also govern a number of environmental and conservation matters, including
the handling and disposing of waste material, plugging and abandonment of wells,
restoration requirements, unitization and pooling of natural gas and oil
properties and establishment of maximum rates of production from natural gas and
oil wells. Some states prorate production to the market demand for oil and
natural gas.
Environmental Regulations. Our operations are subject to numerous laws
and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, and impose substantial liabilities for any
pollution resulting from our operations.
Public interest in the protection of the environment has increased
dramatically in recent years. Onshore and offshore drilling in some areas has
been opposed by environmental groups and, in some areas, has been restricted.
Legislation has also been proposed in Congress from time to time that would
reclassify certain oil and gas exploration and production wastes as "hazardous
wastes," which would make the reclassified wastes subject to much more stringent
handling, disposal and clean-up requirements. To the extent laws are enacted or
other governmental actions are taken that prohibit or restrict offshore drilling
7
or impose environmental protection requirements that result in increased costs
to the natural gas and oil industry (both onshore and offshore), our business
and prospects could be adversely affected. We believe that we are in substantial
compliance with current applicable environmental laws and regulations and that
continued compliance with existing requirements would not have a material
adverse impact on us.
Violation of environmental laws and regulations can lead to the
imposition of administrative, civil or criminal penalties; remedial obligations;
and in some instances injunctive relief. In addition, violations of
environmental laws or the discharge of hazardous materials or oil could result
in liability for personal injuries, property damage, remediation and cleanup
costs, and other environmental damages. As a result, substantial liabilities to
third parties or governmental entities may be incurred, and the payment of such
liabilities could have a material adverse effect on our financial condition and
results of operations.
The Oil Pollution Act and regulations thereunder impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills in United States waters. A
"responsible party" includes the owner or operator of an onshore facility,
pipeline or vessel, or the lessee or permittee of the area in which an offshore
facility is located. The OPA assigns liability to each responsible party for oil
cleanup costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. Likewise, if the party fails to report a spill or to cooperate fully
in the cleanup, liability limits do not apply. Even if applicable, the liability
limits for offshore facilities require the responsible party to pay all removal
costs, plus up to $75 million in other damages. Few defenses exist to the
liability imposed by the OPA.
The OPA imposes ongoing requirements on a responsible party, including
the preparation of oil spill response plans and proof of financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill. As amended by the Coast Guard
Authorization Act of 1996, the OPA requires responsible parties for covered
offshore facilities that have a worst case oil spill of more than 1,000 barrels
to demonstrate financial responsibility in amounts ranging from at least $10
million in specified state waters to at least $35 million in federal outer
continental shelf waters, with higher amounts of up to $150 million if a formal
risk assessment indicates that a higher amount should be required based on
specific risks posed by the operations or if the worst case oil spill discharge
volume possible at the facility may exceed the applicable threshold volumes
specified under the final rule of the MMS implementing these financial
responsibility requirements as enacted in August 1998. We do not anticipate that
we will experience any difficulty in continuing to satisfy the MMS requirements
for demonstrating financial responsibility under the OPA.
The Federal Water Pollution Control Act, also known as the Clean Water
Act, imposes restrictions and strict controls regarding the discharge of
produced waters and other oil and gas wastes into navigable waters. Permits must
be obtained to discharge pollutants into waters and to conduct construction
activities in waters and wetlands. The FWPCA and similar state laws provide for
civil, criminal and administrative penalties for any unauthorized discharges of
pollutants and unauthorized discharges of reportable quantities of oil and other
hazardous substances. Many state discharge regulations and the general permits
from the Federal National Pollutant Discharge Elimination System prohibit the
discharge of produced water and sand, drilling fluids, drill cuttings and
certain other substances related to the oil and gas industry into coastal
waters. Although the costs to comply with zero discharge mandates under federal
or state law may be significant, the entire industry is expected to experience
similar costs, and we believe that these costs will not have a material adverse
8
impact on our results of operations or financial position. The United States
Environmental Protection Agency has adopted regulations requiring certain oil
and gas exploration and production facilities to obtain permits for storm water
discharges. Costs may be associated with the treatment of wastewater or
developing and implementing storm water pollution prevention plans.
The Comprehensive Environmental Response, Compensation, and Liability
Act, also known as the "Superfund" law, imposes liability, without regard to
fault or the legality of the original conduct, on certain classes of persons
that are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons, including the owner or operator of the
disposal site or sites where the release occurred and companies that transported
or disposed or arranged for the transport or disposal of the hazardous
substances under CERCLA, may be subject to joint and several liability for the
costs of cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources. It is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.
We generate both hazardous and nonhazardous solid wastes which are
subject to requirements of the Federal Resource Conservation and Recovery Act
and comparable state statutes. From time to time, the EPA has considered making
changes in nonhazardous waste standards that would result in stricter disposal
requirements for these wastes. Furthermore, it is possible that some wastes that
we generate that are currently classified as nonhazardous may be in the future
be designated as "hazardous wastes," resulting in the wastes being subject to
more rigorous and costly disposal requirements. Changes in applicable
regulations may result in an increase in our capital expenditures or operating
expenses.
We currently own or lease, and have in the past owned or leased,
onshore properties that for many years have been utilized for or associated with
the exploration and production of oil and gas. Although we have utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us or on or under other locations where such
wastes have been taken for disposal. These properties and the wastes disposed
thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
laws, we could be required to remove or remediate previously disposed wastes
(including waste disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination by prior owners or
operators), or to perform remedial plugging or closure operations to prevent
future contamination.
Our operations are also subject to the Federal Clean Air Act and
comparable state statutes. Amendments to the Clean Air Act adopted in 1990
contain provisions that may result in the imposition of increasingly stringent
pollution control requirements with respect to air emissions from the operations
of stationary and mobile source equipment. Such air pollution control
requirements may include specific equipment or technologies, permits with
emissions and operational limitations, pre-approval of new or modified projects
or facilities producing air emissions, and similar measures. Failure to comply
with applicable air statutes or regulations may lead to the assessment of
administrative, civil or criminal penalties, and/or result in the limitation or
cessation of construction or operation of certain air emission sources.
9
Risk Factors
Risks Related to Our Business
In addition to the other information set forth elsewhere in this Form
10-K, the following factors should be carefully considered when evaluating St.
Mary.
Oil and natural gas prices are volatile, and an extended decline in prices would
hurt our profitability and financial condition.
Our revenues, operating results, profitability, future rate of growth
and the carrying value of our oil and gas properties depend heavily on
prevailing market prices for oil and gas. We expect the markets for oil and gas
to continue to be volatile. Any substantial or extended decline in the price of
oil or gas would have a material adverse effect on our financial condition and
results of operations. It could reduce our cash flow and borrowing capacity, as
well as the value and the amount of our oil and gas reserves. Lower prices may
also reduce the amount of oil and gas that we can economically produce.
Historically, the markets for oil and gas have been volatile, and they
are likely to continue to be volatile. Wide fluctuations in oil and gas prices
may result from relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and other factors that are beyond our control,
including:
o worldwide and domestic supplies of oil and natural gas;
o the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
o political instability or armed conflict in oil or gas
producing regions;
o the price and level of foreign imports;
o worldwide economic conditions;
o marketability of production;
o the level of consumer demand;
o the price, availability and acceptance of alternative fuels;
o the availability of pipeline capacity;
o weather conditions; and
o actions of federal, state, local and foreign authorities.
These external factors and the volatile nature of the energy markets
make it difficult to estimate future prices of oil and natural gas. Declines in
oil and gas prices would reduce our revenue and could also reduce the amount of
oil and gas that we can produce economically and, as a result, could have a
material adverse effect on our financial condition, results of operations and
reserves. Further, oil and gas prices do not necessarily move in tandem. Because
10
approximately 56% of our proved reserves were natural gas reserves as of
December 31, 2002, our financial results are slightly more affected by changes
in natural gas prices.
A material portion of our production, revenues and cash flows are derived from
one field.
Production from the Judge Digby Field accounted for approximately 10%
of our total oil and gas production volumes during 2002. If the level of
production from this field substantially declines other than through normal
depletion over the expected reserve life, it could have a material adverse
impact on our overall production levels and our revenues.
Our future success depends on our ability to replace reserves that we produce.
Our future success depends on our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. As of December 31, 2002
our proved reserves would last approximately 8.9 years if produced constantly at
the 2002 rate of production. In order to maintain current production rates we
must locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. We may do this even during periods of low oil and
gas prices. Without successful exploration or acquisition activities, our
reserves, production and revenues will decline rapidly. In addition,
approximately 12% of our total estimated proved reserves at December 31, 2002,
were undeveloped. By their nature, undeveloped reserves are less certain.
Recovery of such reserves will require significant capital expenditures and
successful drilling operations. We cannot assure you that we will be able to
find and develop or acquire additional reserves at an acceptable cost.
Our producing property acquisitions carry significant risks.
Our recent growth is due in part to, and our growth strategy relies in
part on, acquisitions of producing properties and exploration and production
companies. Successful acquisitions require an assessment of a number of factors
beyond our control. These factors include recoverable reserves, future oil and
gas prices, operating costs and potential environmental and other liabilities.
These assessments are inexact and their accuracy is inherently uncertain. In
connection with these assessments, we perform a review of the subject properties
that we believe is generally consistent with industry practices. However, such a
review will not reveal all existing or potential problems. In addition, our
review may not permit us to become sufficiently familiar with the properties to
fully assess their deficiencies and capabilities. We do not inspect every well.
Even when we do inspect a well, we may not always discover structural,
subsurface or environmental problems that may exist or arise.
In connection with our acquisitions, we may not be entitled to
contractual indemnification for preclosing liabilities, including environmental
liabilities. Normally, we acquire interests in properties on an "as is" basis
with limited remedies for breaches of representations and warranties. In
addition, competition for producing oil and gas properties is intense and many
of our competitors have financial and other resources substantially greater than
those available to us. Therefore, we cannot assure you that we will be able to
acquire oil and gas properties that contain economically recoverable reserves or
that we will acquire such properties at acceptable prices.
Additionally, significant acquisitions can change the nature of our
operations and business depending upon the character of the acquired properties,
which may have substantially different operating and geological characteristics
or be in different geographic locations than our existing properties. While it
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is our current intention to continue to concentrate on acquiring properties with
development, exploitation and exploration potential located in our five core
operating areas, we cannot assure you that in the future we will not decide to
pursue acquisitions of properties located in other geographic regions. To the
extent that such acquired properties are substantially different than our
existing properties, our ability to efficiently realize the expected economic
benefits of such transactions may be limited.
We may not be able to successfully integrate future property or corporate
acquisitions.
We seek to make selective niche acquisitions of oil and gas properties,
and we will pursue corporate acquisitions that we believe will be accretive.
However, integrating acquired properties and businesses involves a number of
special risks. These risks include the possibility that management may be
distracted from normal business concerns by the need to integrate operations and
systems and in retaining and assimilating additional employees. Any of these or
other similar risks could lead to potentially adverse short-term or long-term
effects on our operating results. We cannot assure you that we will be able to
obtain adequate funds for future property or corporate acquisitions,
successfully integrate our future property or corporate acquisitions or that we
will realize any of the anticipated benefits of the acquisitions.
Substantial capital is required to replace and grow reserves.
We make, and will continue to make, substantial expenditures to find,
acquire, develop and produce oil and natural gas reserves. Our capital
expenditures for oil and gas properties were $193.0 million for 2002 and $182.9
million during 2001. We have budgeted total capital expenditures of $225.0
million in 2003. With the cash provided by operating activities and borrowings
under our credit facility, we believe we will have sufficient cash to fund
budgeted capital expenditures in 2003. If additional development or attractive
acquisition opportunities arise, we may consider other forms of financing,
including the public offering or private placement of equity or debt securities.
However, if oil and gas prices decrease or we encounter operating difficulties
that result in our cash flow from operations being less than expected, we may
have to reduce the capital we can spend in future years unless we raise
additional funds through debt or equity financing. We cannot assure you that
debt or equity financing, cash generated by operations or borrowing capacity
will be available to us on acceptable terms to meet these requirements.
Future cash flows and the availability of financing will be subject to
a number of variables, such as:
o our success in locating and producing new reserves;
o the level of production from existing wells;
o prices of oil and natural gas;
o lease operating expense, including workovers and taxes; and
o administrative expense.
Issuing equity securities to satisfy our financing requirements could
cause substantial dilution to existing stockholders. Debt financing could lead
to:
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o a substantial portion of our operating cash flow being
dedicated to the payment of principal and interest;
o us being more vulnerable to competitive pressures and economic
downturns; and
o restrictions on our operations.
If our revenues were to decrease due to lower oil and natural gas
prices, decreased production or other reasons, and if we could not obtain
capital through our credit facility or otherwise, our ability to execute our
development plans, replace our reserves or maintain production levels could be
greatly limited.
We may not obtain a bank credit facility borrowing base redetermination that
adequately meets our anticipated financing needs.
We closed a new long-term revolving credit facility in January 2003
with a 9-bank group led by Wachovia Bank. Under the facility, the maximum loan
amount is $300.0 million. The amount actually available from time to time
depends on a borrowing base that the lenders periodically redetermine based on
the value of our oil and gas properties and other assets. The stated total
borrowing base is $215.0 million and will be increased to $250.0 million after
sufficient mortgage collateral has been provided to the banks. Since we pay
commitment fees based on the unused portion of the borrowing base, we have
reduced the commitment that we have accepted under the borrowing base to $150.0
million to correspond with our projected funding requirements.
Our next borrowing base redetermination date is scheduled to occur on
or about April 15, 2003. We cannot assure you that the banks will agree to a
borrowing base redetermination that is adequate for our anticipated financing
needs.
If oil and gas prices decrease or exploration efforts are unsuccessful, we may
be required to take additional writedowns.
There is a risk that we will be required to write down the carrying
value of our oil and gas properties. This could occur when oil and gas prices
are low or if we have substantial downward adjustments to our estimated proved
reserves, increases in our estimates of development costs or deterioration in
our exploration results.
We follow the successful efforts accounting method. All property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending the determination of whether proved reserves have been
discovered. If proved reserves are not discovered with an exploratory well, the
costs of drilling the well are expensed. All geological and geophysical costs on
exploratory prospects are expensed as incurred. The capitalized costs of our oil
and gas properties, on a field-by-field basis, may not exceed the estimated
future net cash flows of that field. If capitalized costs exceed future net
revenues we write down the costs of each such field to our estimate of fair
market value. Unproved properties are evaluated at the lower of cost or fair
market value. This type of charge will not affect our cash flow from operating
activities, but it will reduce the book value of our stockholders' equity. We
review the carrying value of our properties quarterly, based on prices in effect
as of the end of each quarter or as of the time of reporting our results. Once
incurred, a writedown of oil and gas properties is not reversible at a later
13
date even if oil or gas prices increase. St. Mary incurred impairment and
abandonment charges on proved and unproved properties of $2.4 million, $4.7
million and $6.3 million in 2002, 2001 and 2000, respectively.
Information concerning our reserves and future net revenue estimates is
uncertain.
There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and their values, including many factors
beyond our control. Estimates of proved undeveloped reserves, which comprise a
significant portion of our reserves, are by their nature uncertain. The reserve
data included in this Annual Report on Form 10-K is estimated. Although we
believe these estimates are reasonable, actual production, revenues and reserve
expenditures will likely vary from estimates, and these variances may be
material.
Estimates of oil and natural gas reserves, by necessity, are
projections based on geologic and engineering data, and there are uncertainties
inherent in the interpretation of such data as well as the projection of future
rates of production and the timing of development expenditures. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that are difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions governing future
oil and natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows may vary substantially.
Any significant variance in the assumptions could materially affect the
estimated quantity and value of the reserves. Actual production, revenues and
expenditures with respect to our reserves will likely vary from estimates, and
such variances may be material. See "Business and Properties--Reserves."
In addition, you should not construe PV-10 value as the current market
value of the estimated oil and natural gas reserves attributable to our
properties. We have based the PV-10 value on prices and costs as of the date of
the estimate, in accordance with applicable regulations, whereas actual future
prices and costs may be materially higher or lower. For example, values of our
reserves at December 31, 2002 were estimated starting with a calculated weighted
average sales price of $31.20 per barrel of oil (NYMEX) and $4.74 per MMBtu of
gas (Gulf Coast spot price), then adjusted for transportation, quality and basis
differentials. During 2002 our monthly average realized gas prices were as high
as $3.99 per Mcf and as low as $2.24 per Mcf. For the same period our monthly
average realized oil prices were as high as $27.66 per Bbl and as low as $17.72
per Bbl. Many factors will affect actual future net cash flows, including:
o the amount and timing of actual production;
o supply and demand for oil and natural gas;
o curtailments or increases in consumption by natural gas
purchasers; and
o changes in governmental regulations or taxation.
14
The timing of the production of oil and natural gas properties and of
the related expenses affect the timing of actual future net cash flows from
proved reserves and, thus, their actual present value. In addition, the 10%
discount factor, which we are required to use to calculate PV-10 value for
reporting purposes, is not necessarily the most appropriate discount factor
given actual interest rates and risks to which our business or the oil and
natural gas industry in general are subject. As a result, our actual future net
cash flows could be materially different from the estimates included in this
Annual Report on Form 10-K.
Our industry is highly competitive.
Major oil companies, independent producers, and institutional and
individual investors are actively seeking oil and gas properties throughout the
world, along with the equipment, labor and materials required to operate
properties. Many of our competitors have financial and technological resources
vastly exceeding those available to us. Many oil and gas properties are sold in
a competitive bidding process in which we may lack technological information or
expertise available to other bidders. We cannot be sure that we will be
successful in acquiring and developing profitable properties in the face of this
competition.
Exploration and development drilling may not result in commercially productive
reserves.
Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil or natural gas
will be found. The cost of drilling and completing wells is often uncertain, and
oil and gas drilling and production activities may be shortened, delayed or
canceled as a result of a variety of factors, many of which are beyond our
control. These factors include:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o shortages in experienced labor;
o compliance with governmental requirements; and
o shortages or delays in the availability of drilling rigs and
the delivery of equipment.
The prevailing prices of oil and gas also affect the cost of and the
demand for drilling rigs, production equipment and related services.
We cannot assure you that the wells we drill will be productive or that
we will recover all or any portion of our investment in such wells. The seismic
data and other technologies we use do not allow us to know conclusively prior to
drilling a well that oil or gas is present or may be produced economically. The
cost of drilling, completing and operating a well is often uncertain, and cost
factors can adversely affect the economics of a project. Drilling activities can
result in dry wells or wells that are productive but do not produce sufficient
net revenues after operating and other costs to cover initial drilling costs.
15
Our future drilling activities may not be successful, nor can we be
sure that our overall drilling success rate or our drilling success rate for
activity within a particular area will not decline. Unsuccessful drilling
activities could have a material adverse effect on our results of operations and
financial condition. Also, we may not be able to obtain any options or lease
rights in potential drilling locations that we identify. Although we have
identified numerous potential drilling locations, we cannot be sure that we will
ever drill them or that we will produce oil or natural gas from them or any
other potential drilling locations.
Our business is subject to operating hazards that could result in substantial
losses.
Oil and gas operations are subject to many risks, including well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental hazards and
risks. If any of these hazards occurs, we could sustain substantial losses as a
result of:
o injury or loss of life;
o severe damage to or destruction of property, natural resources
and equipment;
o pollution or other environmental damage;
o clean-up responsibilities;
o regulatory investigations and penalties; and/or
o suspension of operations.
In addition, we may be liable for environmental damage caused by
previous owners of property we own or lease. As a result, we may face
substantial liabilities to third parties or governmental entities, which could
reduce or eliminate funds available for exploration, development or acquisitions
or cause us to incur losses. An event that is not fully covered by insurance
could have a material adverse effect on our financial condition and results of
operations.
We maintain insurance against some, but not all, of these potential
risks and losses. We may elect not to obtain insurance if we believe that the
cost of available insurance is excessive relative to the risks presented. In
addition, pollution and environmental risks generally are not fully insurable.
If a significant accident or other event occurs and is not fully covered by
insurance, it could adversely affect us.
Other independent oil and gas companies' limited access to capital may change
our exploration and development plans.
Many independent oil and gas companies have limited access to the
capital necessary to finance their activities. As a result, some of the other
working interest owners of our wells may be unwilling or unable to pay their
share of the costs of projects as they become due. These problems could cause us
to change, suspend or terminate our drilling and development plans with respect
to the affected project.
16
Hedging transactions may limit our potential gains and involve other risks.
To manage our exposure to price risks in the marketing of our oil and
natural gas, we enter into commodity price risk management arrangements from
time to time with respect to a portion of our current or future production.
While intended to reduce the effects of volatile oil and natural gas prices,
these transactions may limit our potential gains if oil or natural gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
o our production is less than expected;
o the counterparties to our futures contracts fail to perform
under the contracts; or
o a sudden, unexpected event materially impacts oil or natural
gas prices.
The terms of our hedging agreements may also require that we furnish
cash collateral, letters of credit or other forms of performance assurance in
the event that mark-to-market calculations result in settlement obligations by
us to the counterparties, which would encumber our liquidity and capital
resources.
Our industry is heavily regulated.
Federal, state and local authorities extensively regulate the oil and
gas industry. Legislation and regulations affecting the industry are under
constant review for amendment or expansion, raising the possibility of changes
that may affect, among other things, the pricing or marketing of oil and gas
production. Noncompliance with statutes and regulations may lead to substantial
penalties, and the overall regulatory burden on the industry increases the cost
of doing business and, in turn, decreases profitability. State and local
authorities regulate various aspects of oil and gas drilling and production
activities, including the drilling of wells (through permit and bonding
requirements), the spacing of wells, the unitization or pooling of oil and gas
properties, environmental matters, safety standards, the sharing of markets,
production limitations, plugging and abandonment, and restoration. Federal
authorities regulate many of these same activities for our drilling and
production operations in federal offshore waters. To cover the various
obligations of leaseholders in federal waters, federal authorities generally
require that leaseholders have substantial net worth or post bonds or other
acceptable assurances that such obligations will be met. The cost of these bonds
or other surety can be substantial, and we cannot assure you that we will be
able to obtain bonds or other surety in all cases. Under some circumstances,
federal authorities may require any of our operations on federal leases be
suspended or terminated. Any such suspension or termination could materially
adversely affect our financial condition and results of operations.
We must comply with complex environmental regulations.
Our operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities where we are engaged in exploration or production
operations. New laws or regulations, or changes to current requirements, could
have a material adverse effect on our business. We will continue to be subject
to uncertainty associated with new regulatory interpretations and inconsistent
interpretations between state and federal agencies. We could face significant
liabilities to the government and third parties for discharges of oil, natural
gas or other pollutants into the air, soil or water, and we could have to spend
substantial amounts on investigations, litigation and remediation. We cannot be
sure that existing environmental laws or regulations, as currently interpreted
17
or enforced, or as they may be interpreted, enforced or altered in the future,
will not materially adversely affect our results of operations and financial
condition. As a result, we may face material indemnity claims with respect to
properties we own or have owned.
Our business depends on transportation facilities owned by others.
The marketability of our oil and gas production depends in part on the
availability, proximity and capacity of pipeline systems owned by third parties.
The unavailability of or lack of available capacity on these systems and
facilities could result in the shut-in of producing wells or the delay or
discontinuance of development plans for properties. Although we have some
contractual control over the transportation of our product, material changes in
these business relationships could materially affect our operations. Federal and
state regulation of oil and gas production and transportation, tax and energy
policies, changes in supply and demand, pipeline pressures, damage to or
destruction of pipelines and general economic conditions could adversely affect
our ability to produce, gather and transport oil and natural gas.
We depend on key personnel.
Our success will continue to depend on the continued services of our
executive officers and a limited number of other senior management and technical
personnel with extensive experience and expertise in evaluating and analyzing
producing oil and gas properties and drilling prospects, maximizing production
from oil and gas properties and marketing oil and gas production. Loss of the
services of any of these people could have a material adverse effect on our
operations. We currently do not have employment agreements with our executive
officers other than Mark Hellerstein, our Chief Executive Officer. We do not
carry any key person life insurance policies.
Ownership of working interests, royalty interests and other interests by some of
our officers and directors may create conflicts of interest.
As a result of their prior employment with another company with which
St. Mary engaged in a number of transactions, Ronald D. Boone, the Executive
Vice President and Chief Operating Officer and a director of St. Mary, and two
other vice presidents of St. Mary own royalty interests in many of St. Mary's
properties, which were earned as part of the prior employer's employee benefit
programs. One vice president also owns certain working interests through
participation in acquisitions made by his former employer. Those persons have no
royalty participation in any new St. Mary properties.
Mr. Boone also owns 25% of Princeton Resources LLC, which owns the oil
and gas working interests that he acquired as a result of his prior employment.
Although Mr. Boone does not manage this entity, he may participate in any
investment decisions made by them.
As a result of these transactions and relationships, conflicts of
interest may exist between these persons and us. Although these persons owe
fiduciary duties to our stockholders and to us, we cannot assure you that
conflicts of interest will always be resolved in our favor.
Risks Related to Our Common Stock
Our certificate of incorporation and bylaws have provisions that discourage
corporate takeovers and could prevent shareholders from realizing a premium on
their investment.
18
Our certificate of incorporation and bylaws contain provisions that may
have the effect of delaying or preventing a change of control. These provisions,
among other things, provide for noncumulative voting in the election of the
board of directors and impose procedural requirements on stockholders who wish
to make nominations for the election of directors or propose other actions at
stockholders' meetings. These provisions, alone or in combination with each
other and with the rights plan described below, may discourage transactions
involving actual or potential changes of control, including transactions that
otherwise could involve payment of a premium over prevailing market prices to
shareholders for their common stock
On July 15, 1999, our board of directors adopted a stockholder rights
plan. The plan is designed to enhance the board's ability to prevent an acquirer
from depriving stockholders of the long-term value of their investment and to
protect stockholders against attempts to acquire us by means of unfair or
abusive takeover tactics. If the board of directors decides in accordance with
its fiduciary obligations that the terms of a potential acquisition do not
reflect the long-term value of St. Mary, under the plan the board of directors
could allow the holder of each outstanding share of our common stock other than
those held by the potential acquirer to purchase one additional share of our
common stock with a market value of twice the exercise price. This prospective
dilution to a potential acquirer would make the acquisition impracticable unless
the terms were improved to the satisfaction of the board of directors. However,
the existence of the plan may impede a takeover not supported by our board,
including a takeover that may be desired by a majority of our stockholders or
involving a premium over the prevailing stock price.
Our shares that are eligible for future sale may have an adverse effect on the
price of our common stock.
At February 28, 2003, we had 31,433,900 shares of common stock
outstanding. Of the shares outstanding, approximately 27,405,059 shares were
freely tradable without substantial restriction or the requirement of future
registration under the Securities Act. Also as of that date, options to purchase
3,025,007 shares of our common stock were outstanding, of which 1,911,398 were
exercisable. These options are exercisable at prices ranging from $9.25 to
$33.3125 per share. Sales of substantial amounts of common stock, or a
perception that such sales could occur, and the existence of options or warrants
to purchase shares of commons stock at prices that may be below the then -
current market price of the common stock could adversely affect the market price
of the common stock and could impair our ability to raise capital through the
sale of our equity securities.
Our Former Chairman of the Board and his extended family may be able to control
us.
Thomas E. Congdon, a director and our former Chairman of the Board, and
members of his extended family owned approximately 16% of the outstanding shares
of our common stock as of February 28, 2003. While no formal arrangements exist,
these extended family members may be inclined to act in concert with Mr. Congdon
on matters related to control of St. Mary, including for example the election of
directors or response to an unsolicited bid to acquire St. Mary. Accordingly,
Mr. Congdon and his family may be able to control or influence matters presented
to our stockholders.
We may not always pay dividends on our common stock.
Although we have paid cash dividends to stockholders every year since
1940 and we expect that our practice of paying dividends will continue, the
payment of future dividends remains in the discretion of the board of directors
19
and will continue to depend on our earnings, capital requirements, financial
condition and other factors. In addition, the payment of dividends is subject to
covenants in our bank credit facility, including the requirement that we
maintain certain levels of stockholder's equity. The board of directors may
determine in the future to reduce the current annual dividend rate of $0.10 per
share or discontinue the payment of dividends altogether.
Cautionary Statement about Forward-Looking Statements
This Annual Report on Form 10-K includes certain statements that may be
deemed to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. All statements, other than statements of historical facts, included in
this Form 10-K that address activities, events or developments that St. Mary's
management expects, believes or anticipates will or may occur in the future are
forward looking statements. Examples of forward-looking statements may include
discussion of such matters as:
o The amount and nature of future capital, development and
exploration expenditures;
o The drilling of wells;
o Reserve estimates and the estimates of both future net
revenues and the present value of future net revenues that are
included in their calculation;
o Future oil and gas production estimates;
o Repayment of debt;
o Business strategies;
o Expansion and growth of operations; and
o Other similar matters such as those discussed in Management's
Discussion and Analysis of Financial Condition and Results of
Operations.
These statements are based on certain assumptions and analyses made by us in
light of our experience and our perception of historical trends, current
conditions, expected future developments and other factors we believe are
appropriate in the circumstances. Such statements are subject to a number of
assumptions, risks and uncertainties, including such factors as the volatility
and level of oil and natural gas prices, uncertainties in cash flow, expected
acquisition benefits, production rates and reserve replacement, reserve
estimates, drilling and operating risks, competition, litigation, environmental
matters, the potential impact of government regulations, and other matters
discussed under the caption "Risk Factors", many of which are beyond our
control. Readers are cautioned that forward-looking statements are not
guarantees of future performance and that actual results or developments may
differ materially from those expressed or implied in the forward-looking
statements.
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Available Information
Our Internet website address is www.stmaryland.com. We make available
free of charge through our website's financial information section our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K, and amendments to those reports filed with or furnished to the SEC under
applicable securities laws as soon as reasonably practical after we
electronically file such material with, or furnish it to, the SEC. Our web site
information is not incorporated by reference into this Annual Report on Form
10-K.
Glossary
The terms defined in this section are used throughout this Annual
Report on Form 10-K.
2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
two-dimensional cross-section of the subsurface.
3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used herein in reference to natural gas.
BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Behind pipe reserves. Estimated net proved reserves in a formation in which
production casing has already been set in the wellbore but has not been
perforated and production tested.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
of six Mcf of gas (including gas liquids) to one Bbl of oil.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
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 that can be owned in land, including
surface and mineral (including oil and gas) rights.
21
Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated
by dividing the amount of total capital expenditures for oil and gas activities
by the amount of estimated net proved reserves added during the same period
(including the effect on proved reserves of reserve revisions).
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
of fluid and proppant (usually sand) into the formation under high pressure.
This creates artificial fractures in the reservoir rock, which increases
permeability and porosity.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
Mcf. One thousand cubic feet.
MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMcf. One million cubic feet.
MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
required to raise the temperature of a one-pound mass of water one degree
Fahrenheit.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net asset value per share. The result of the fair market value of total assets
less total liabilities, divided by the total number of outstanding shares of
common stock.
PV-10 value. The present value of estimated future gross revenue to be generated
from the production of estimated net proved reserves, net of estimated
production and future development costs, using prices and costs in effect as of
the date indicated (unless such prices or costs are subject to change pursuant
to contractual provisions), without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
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.
22
Proved undeveloped reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Reserve life. Expressed in years, represents the estimated net proved reserves
at a specified date divided by forecasted production for the preceding 12-month
period.
Royalty. The interest paid to the owner of mineral rights expressed as a
percentage of gross income from oil and gas produced and sold unencumbered by
expenses.
Royalty interest. An interest in an oil and gas property entitling the owner to
shares of oil and gas production free of costs of exploration, development and
production. Royalty interests are approximate and are subject to adjustment.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether such acreage contains estimated net proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to share in
the production.
ITEM 2. PROPERTIES
Operations
St. Mary's exploration, development and acquisition activities are
focused in five core operating areas: the Mid-Continent region; onshore Gulf
Coast and offshore Gulf of Mexico; the ArkLaTex region; the Rocky Mountain
region in Montana, North Dakota and Wyoming; and the Permian Basin in west Texas
and New Mexico. Information concerning each of our major areas of operations,
based on our estimated proved reserves as of December 31, 2002, is shown below.
Estimated Proved Reserves
----------------------------------------
MMCFE PV-10 Value
Oil Gas ------------------ ------------------------
(MBbls) (MMcf) Amount Percent (In thousands) Percent
------- ------- ------------------ ------------------------
Mid-Continent Region........... 1,315 140,840 148,731 30.3% $ 278,685 33.8%
ArkLaTex Region................ 1,350 47,464 55,566 11.3% 91,458 11.1%
Gulf Coast and Gulf of Mexico.. 400 37,505 39,906 8.1% 103,128 12.5%
Rocky Mountain Region.......... 27,422 35,568 200,096 40.8% 284,482 34.5%
Permian Basin.................. 5,632 12,795 46,588 9.5% 67,055 8.1%
------- ------- ------- ------- -------------- -------
Total.......................... 36,119 274,172 490,887 100.0% $ 824,808 100.0%
======= ======= ======= ======= ============== =======
Mid-Continent Region. Since 1973 St. Mary has been active in the
Mid-Continent region, where operations are managed by our 32-person Tulsa,
Oklahoma office. We have ongoing exploration and development programs in the
Anadarko and Arkoma Basins of Oklahoma and Texas. The Mid-Continent region
accounted for 30% of our estimated proved reserves as of December 31, 2002, or
23
148.7 BCFE, 84% of which were proved developed and 95% of which were natural
gas. We participated in drilling 50 gross wells in this region in 2002,
including 26 wells operated by us, 88% of which were completed as producers.
St. Mary's development and exploration budget in the Mid-Continent
region for 2003 totals $45.0 million. We plan to operate 36 drilling wells in
the Mid-Continent region during 2003 and to utilize three to four drilling rigs
throughout the year. Our 2003 budget also reflects participation in an
additional 10 to 30 wells to be operated by other entities.
Anadarko Basin. Our long history of operations and proprietary geologic
knowledge enables us to sustain economic development and exploration programs
despite periods of adverse industry conditions. We are applying state of the art
technology in hydraulic fracturing and innovative well completion techniques to
accelerate production and associated cash flow from the region's tight gas
reservoirs. We also continue to benefit from the continuing consolidation of
operators in the basin as we pursue attractive opportunities to acquire
properties.
Approximately 55% of the drilling activities for 2003 will be focused
on low-to-medium-risk development in the Cromwell, Granite Wash, Osborne, Red
Fork and Spiro formations. In addition, approximately 45% of our 2003
Mid-Continent capital budget is allocated to deeper, higher-potential wells in
the Morrow and Atoka formations at the NE Mayfield Field in Oklahoma and in
various other fields within the Morrow and Springer formations at depths up to
22,000 feet.
Carrier Prospect. Within its inventory of higher-risk higher-potential
exploration prospects, St. Mary holds an aggregate 42% working interest in 5,700
acres in Leon County, Texas. Our Carrier Prospect acreage relates to a platform
reef prospect located near the industry's prolific Cotton Valley pinnacle reef
discovery and targets potentially larger platform reefs that we believe
developed in the deeper waters of the basin during the Jurassic period. We plan
to seek industry participation for an initial test well in 2003.
Arkoma Basin. In February 2002 we expanded our Arkoma Basin holdings
with the acquisition of oil and gas properties and an 89-mile gas gathering
system from Merchant Resources #1 L.P. of Houston, Texas for $7.5 million. The
properties include undrilled locations and are expected to complement our
existing properties in the area. In 2002, we spud 11 wells in this area with an
82% success rate. The primary producing formations in this area include the
Booch, Hartshorne, Wapanucka and the Cromwell. Our average working interest for
these wells is 91%, and we anticipate drilling at least ten gross wells in this
area in 2002. Initial production rates from the wells have varied from
approximately 500 Mcf per day to 1,250 Mcf per day. Since the Merchant
acquisition we have increased production in this area from two MMcf per day to
nearly eight MMcf per day.
Gulf Coast and Gulf of Mexico Region. St. Mary's presence in south
Louisiana dates to the early 1900's when our founders acquired a franchise
property in St. Mary Parish on the shoreline of the Gulf of Mexico. These 24,900
acres of fee lands yielded $2.9 million of gross oil and gas royalty revenue in
2002. Our onshore Gulf Coast and Gulf of Mexico presence increased significantly
in 1999 with the acquisition of King Ranch Energy. This acquisition included
260,000 gross undeveloped acres (81,000 net acres) and a large 3-D seismic
database. The Gulf Coast and Gulf of Mexico region accounted for 8% of our
estimated proved reserves as of December 31, 2002, or 39.9 BCFE, 95% of which
were proved developed and 94% of which were natural gas.
24
St. Mary's diverse activities in the onshore Gulf Coast and Gulf of
Mexico are managed by our 13-person regional office in Lafayette, Louisiana and
include ongoing development and exploitation programs in multiple basins onshore
south Louisiana as well as several offshore shallow-water Gulf of Mexico blocks.
Advanced 3-D seismic imaging and interpretation techniques and extensive
subsurface geological interpretations are revitalizing exploration and
development activities in the Miocene trend along the Gulf Coast. Our
exploration and development budget in the Gulf Coast and Gulf of Mexico region
for 2003 is $17.0 million.
The Judge Digby Field is the largest field acquired in the King Ranch
Energy acquisition and is located outside Baton Rouge, Louisiana in Point Coupee
Parish. We have interests ranging from 10% to 20% in eleven wells that are
producing a total of 180 MMcf per day on a gross basis as of February 2003. This
ultra deep field produces from multiple Tuscaloosa reservoirs between 19,000 and
24,000 feet. The wells are characterized by high producing rates such as the
Parlange #11 completed in 2000 at an initial rate of 92,000 Mcf per day. We
believe this well had the highest initial production rate for a well ever
completed onshore Louisiana. New drilling in this field is continuing with the
completion of the J. Wuertele #3 in August 2002 with producing rates up to
60,000 Mcf per day. The Majors #4 was drilled to 22,962 feet and completed in
December 2002 in the C-3 and C-4 Tuscaloosa sands producing at initial rates up
to 36,000 Mcf per day. Two new wells and two sidetrack wells are planned for
2003 along with several recompletions in this multi-pay geologically complex
field.
In December 2002 we acquired additional interests in the High Island
Field where we drilled the successful Miami Corp T-1 well in 2001. This well is
currently producing 8,500 Mcf per day and we plan to drill an offset well in
2003.
Fee Lands. St. Mary owns 24,900 acres of fee lands and associated
mineral rights in St. Mary Parish located approximately 85 miles southwest of
New Orleans, Louisiana. Since the initial discovery on our fee lands in 1938,
our cumulative oil and gas revenues, primarily landowner's royalties, from the
Bayou Sale, Horseshoe Bayou and Belle Isle fields have exceeded $235 million. We
currently lease 9,945 acres and have granted a seismic option to Seismic
Exchange, Inc. on the remaining 14,969 acres. The survey is underway and will
cover the entire fee properties. SEI estimates the acquisition of the data to be
completed by mid-October. Under the terms of the agreement, we are entitled to
receive a copy of the processed data and have been granted the right to utilize
the data for our purpose or for purposes of showing the data to current lessees
and prospective lessees. Upon completion of the processing of the survey data,
we are hopeful this will encourage development drilling by our lessees,
facilitate the origination of new prospects and stimulate exploration interest
in deeper, untested horizons. Our principal operators on the fee properties are
BP Amoco, Cabot and Amerada Hess
ArkLaTex Region. St. Mary's operations in the ArkLaTex region are
managed by our 18-person office in Shreveport, Louisiana. The ArkLaTex region
accounted for 11% of our estimated proved reserves as of December 31, 2002, or
55.6 BCFE, 75% of which were proved developed and 85% of which were natural gas.
In 1992, we acquired oil and gas properties and rights to over 6,000 square
miles of proprietary 2-D seismic data in the region. Much of the Shreveport
office's successful exploration and development programs have derived from niche
acquisitions completed since 1992 totaling $23.2 million. These acquisitions
have provided access to strategic holdings of undeveloped acreage and
proprietary packages of geologic and seismic data, resulting in an active
program of additional development and exploration.
Our holdings in the ArkLaTex region are comprised of interests in
approximately 701 producing gross wells, including 117 wells operated by us;
interests in leases totaling approximately 77,158 gross acres; and mineral
25
servitudes totaling approximately 14,600 gross acres. Activities in the ArkLaTex
region during 2002 focused on the search for new opportunities and potential
analog fields as well as final development of several important field
discoveries made by our geoscientists since 1994. We completed two acquisitions
totaling $4.9 million for primarily undeveloped properties in the Huxley Field,
part of the James Lime Horizontal Trend. Our initial well, the USA N No. 2-H was
completed in early 2003 at a rate of 3,800 Mcf per day. We have six additional
wells planned in the Huxley Field in 2003.
In 2003 we will continue to focus on the search for new opportunities
and potential analog fields in which to apply our proprietary geologic models
and production techniques. We anticipate participating in 35 gross wells in the
ArkLaTex region and are the operator of properties representing approximately
85% of our 2003 ArkLaTex region capital expenditures budget.
Rocky Mountain Region. Nance Petroleum Corporation, a wholly owned
subsidiary of St. Mary, has conducted operations in the Williston Basin in
eastern Montana and western North Dakota on our behalf since 1991, initially
under a joint venture arrangement and subsequently as a wholly owned subsidiary.
This area has expanded into the Green River Basin with properties acquired from
Choctaw and Flying J and the Powder River Basin with our coal-bed methane pilot
project and additional properties acquired from Flying J in 2003. The Rocky
Mountain region accounted for 41% of our estimated proved reserves as of
December 31, 2002, or 200.1 BCFE, 96% of which were proved developed and 82% of
which were oil.
Our office in Billings, Montana includes a 35-person staff. A
significant portion of the exploration and development in the Rocky Mountain
Region is based on the interpretation of 3-D seismic data. We have successfully
used 3-D seismic imaging to delineate structure and porosity development in the
Red River formation. Since 1991 we have successfully completed 34 out of 38
gross wells drilled and operated. Our prospect inventory continues to expand as
results from current activity lead to additional areas to conduct 3-D seismic
surveys. Ten additional 3-D surveys are planned for 2003.
St. Mary spent $17 million on exploration and development in the
Williston Basin in 2002. In December 2002 we completed a $69.5 million
acquisition of Williston Basin properties from Burlington Resources. These
properties currently produce approximately 3,100 barrels of oil and 3,300 Mcf of
gas per day. Our 2003 Rocky Mountain Region exploration and development capital
budget is $33.0 million. We plan to drill seventeen operated wells with working
interests ranging from 48% to 100%. We are the operator of properties
representing approximately 86% of our Rocky Mountain Region capital budget in
2003.
In January 2003 St. Mary issued 3,380,818 shares of its restricted
common stock valued at $71.6 million to acquire Rocky Mountain properties from
Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. This acquisition
included properties located in the Williston, Powder River and Green River
Basins with 66.9 BCFE of proved reserves and production of approximately 2,100
barrels of oil and 8,200 Mcf of gas per day. We also received a net amount of
$2.8 million in cash for normal purchase price adjustments. In addition, St.
Mary made a non-recourse loan to Flying J and Big West of $71.6 million at LIBOR
plus 2% for up to a 39-month period, which is secured by a pledge of the shares
of St. Mary stock issued to Flying J and Big West. The loan was funded through
borrowings under our bank credit facility.
Permian Basin Region. The Permian Basin area covers a significant
portion of eastern New Mexico and western Texas and is one of the major
producing basins in the United States. The basin includes hundreds of oil fields
26
undergoing secondary and enhanced oil recovery projects. 3-D seismic imaging of
existing fields and advanced secondary recovery programs are substantially
increasing oil recoveries in the Permian Basin. Our holdings in the Permian
Basin resulted from a series of niche property acquisitions since 1995, which
total $22.1 million. We believe that our Permian Basin operations provide us
with a solid base of long-lived oil reserves, promising longer-term exploration
and development prospects and the potential for secondary recovery projects. The
Permian Basin region accounted for 9.5% of our estimated proved reserves as of
December 31, 2002, or 46.6 BCFE, of which 73% were proved developed and 73% were
oil.
St. Mary participated in drilling 15 gross wells in 2002 with an 80%
success rate. The East Shugart Delaware Unit waterflood project was initiated in
2000 with a 5-well pilot project. Production flattened out in 2002 and the
initial response from the water injection is anticipated in 2003. We are hopeful
the East Shugart waterflood will be an analog to our successful Parkway Delaware
Unit waterflood that increased production from 325 Bbl per day in 1996 when the
property was acquired to 1,200 Bbl per day in 2002.
Our Permian Basin capital budget for 2002 is $12.0 million. In addition
to drilling four injection wells in the East Shugart Delaware waterflood, two
wells are planned at our Samboca prospect, six in-fill wells are planned at Ft.
Chadbourne and three wells in the Parkway and HJSA fields.
Other Areas. We have acquired leases covering 145,000 gross acres in
which we own an average 90% working interest in the Hanging Woman Basin of
Montana and Wyoming for prospective coalbed methane development. We have drilled
an 18-well pilot program and are evaluating its results. We are also currently
investigating permitting and environmental issues related to these prospects. We
will be unable to determine the future potential of these prospects until we
have completed the evaluation of our pilot program and have resolved all such
permitting and environmental issues. An environmental public interest group has
filed a lawsuit against the federal Bureau of Land Management seeking to cancel
certain federal leases related to coalbed methane development in Montana, which
could affect 48,000 of our 145,000 gross leased acres. We will monitor this
lawsuit as part of our investigation of environmental issues related to these
prospects. See "Legal Proceedings" for a discussion of this lawsuit.
On April 26, 2002, the Interior Board of Land Appeals of the U.S.
Department of the Interior issued an order that reversed a decision by the
Bureau of Land Management dismissing a protest by the Wyoming Outdoor Council
and Powder River Basin Resource Council of the offer for sale in February 2000
of three oil and gas leases in the Powder River Basin in Wyoming. The Board held
that the BLM determination to allow the offer for sale of the three particular
leases did not comply with environmental laws since the environmental analysis
used by the BLM in making that determination did not contain a discussion of the
unique potential impacts associated with coalbed methane extraction and
development or consider reasonable alternatives relevant to a pre-leasing
environmental analysis. On October 15, 2002, the Board refused to reconsider
this lease holding. The order addressed only three particular leases covering
approximately 2,600 acres that are not included in our Hanging Woman Basin
project. However, we cannot assure you that other leases, including issued
leases that we hold in the Hanging Woman Basin, will not be challenged on a
similar basis.
Coalbed methane production is similar to our traditional natural gas
production as to the physical producing facilities and the product produced.
However, the subsurface mechanisms that allow the gas to move to the wellbore
and the producing characteristics of coalbed methane wells are very different
from traditional natural gas production. Unlike conventional gas wells, which
27
require a porous and permeable reservoir, hydrocarbon migration and a natural
structural and/or stratigraphic trap, the coalbed methane gas is trapped in the
molecular structure of the coal itself until released by pressure changes
resulting from the removal of in situ water. Frequently, coalbeds are partly or
completely saturated with water. As the water is removed, internal pressures on
the coal are decreased, allowing the gas to desorb from the coal and flow to the
wellbore. Unlike traditional gas wells, new coalbed methane wells often produce
water for several months and then, as the water production decreases, natural
gas production increases as the coal seams de-water.
Coalbed methane gas production in the Hanging Woman Basin requires
state permits for the use of well-site pits and evaporation ponds for the
disposal of produced water. However, groundwater produced from the coal seams
can generally be discharged into arroyos, surface waters, well-site pits and
evaporation ponds without a permit if it does not exceed surface discharge
permit levels, and if it meets state and federal primary drinking water
standards. All of these disposal options require an extensive third-party water
sampling and laboratory analysis program to ensure compliance with state permit
standards. Where water of lesser quality is involved or the wells produce water
in excess of the applicable volumetric permit limits, additional disposal wells
would have to be drilled to re-inject the produced water back into deep
underground rock formations.
Duchesne Deep. In 2002 we acquired over 12,000 acres in the Uinta Basin
of Utah to drill a basin centered gas test in the Mesaverde formation at depths
up to 16,000 feet. Using current technology and our experience drilling and
completing tight gas sand formations, our objective is to economically produce
gas from the tight Mesaverde sand. The first well was spud in September 2002 and
reached total depth in early 2003. The well will undergo extensive testing and
if successful, $4.8 million is budgeted in 2003 for additional acreage and to
drill two additional wells.
Acquisitions
In December 2002 we completed a $69.5 million acquisition of Williston
Basin properties from Burlington Resources Oil and Gas Company LP. Other
acquisitions in 2002 totaled $18.2 million including the $7.5 million
acquisition of Arkoma Basin, Oklahoma properties from Merchant Resources LP and
the $4.9 Huxley Field acquisition in east Texas. In November 2001, we completed
a $40.5 million acquisition from Choctaw II Oil & Gas, Ltd. of oil and gas
properties located in our Williston Basin core area and the Green River Basin in
Wyoming. During the last five years we have completed over $232 million of
acquisitions. For 2003 we have budgeted $90.0 million for property acquisitions.
However, we have the financial capacity to commit substantially greater
resources to purchases should additional opportunities be identified. In January
2003 we closed a $68.8 million acquisition of Rocky Mountain properties from
Flying J Oil & Gas Inc. and Big West Oil & Gas Inc., after purchase price
adjustments. This acquisition included 66.9 BCFE of proved reserves located in
the Williston, Powder River and Green River Basins. In January 2003 we also
closed a $5.2 million acquisition of interests in our Ft. Chadbourne field in
west Texas.
Reserves
The following table presents summary information with respect to the
estimates of our proved oil and gas reserves for each of the years in the
three-year period ended December 31, 2002, as prepared by both Ryder Scott
Company, independent petroleum engineers, and us. For the periods presented,
Ryder Scott Company evaluated properties representing approximately 80% of our
28
total PV-10 value while we evaluated the remainder. The PV-10 values shown in
the following table are not intended to represent the current market value of
the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor
costs have been escalated, but prices include the effects of hedging contracts.
You should read the following table along with the sections entitled "Risk
Factors - Risks Related to Our Business - Information concerning our reserves
and future net revenue estimates is uncertain".
As of December 31,
--------------------------------
2002 2001 2000
---- ---- ----
Proved Reserves Data:
Oil (MBbls) 36,119 23,669 20,950
Gas (MMcf) 274,172 241,231 225,975
MMCFE 490,887 383,247 351,673
PV-10 value (in thousands) (1) $ 824,808 $ 363,795 $ 1,153,663
Proved Developed Reserves 88% 86% 87%
Production Replacement 306% 166% 168%
Reserve Life (years) (2) 8.9 7.1 6.7
- ------------------
(1) PV-10 value as of December 31, 2002, was calculated using prices in
effect at December 31, 2002, of $31.20 per barrel of oil (NYMEX) and
$4.74 per MMBtu of gas (Gulf Coast spot price). Both of these prices
were then adjusted for transportation, quality and basis differentials.
These prices were 57% and 79% higher, respectively, than prices used to
calculate PV-10 value as of December 31, 2001. The PV-10 value includes
a deficit totaling $23,398,000 attributable to price hedging contracts.
(2) Reserve life represents the estimated proved reserves at the dates
indicated divided by actual production for the preceding 12-month
period.
Production
The following table summarizes the average volumes of oil and gas
produced from properties in which St. Mary held an interest during the periods
indicated:
Years Ended December 31,
------------------------------
2002 2001 2000
---- ---- ----
Operating Data:
Net production:
Oil (MBbls)................................ 2,815 2,434 2,398
Gas (MMcf)................................. 38,164 39,491 38,346
MMCFE...................................... 55,055 54,093 52,731
Average net daily production:
Oil (Bbls)................................. 7,713 6,667 6,551
Gas (Mcf).................................. 104,558 108,195 104,769
MCFE....................................... 150,836 148,199 144,075
Average sales price (1):
Oil (per Bbl).............................. $ 25.34 $ 23.29 $ 23.53
Gas (per Mcf).............................. $ 3.00 $ 3.73 $ 3.44
Additional per MCFE data:
Lease operating expense.................... $ 0.66 $ 0.75 $ 0.48
Transportation costs....................... $ 0.06 $ 0.04 $ 0.04
Production taxes........................... $ 0.20 $ 0.23 $ 0.21
General and administrative................. $ 0.26 $ 0.22 $ 0.21
Depreciation, depletion and amortization... $ 0.99 $ 0.95 $ 0.76
-----------------
(1) Includes the effects of St. Mary's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
29
Productive Wells
As of December 31, 2002, we had interests in 1,256 gross (558 net)
productive oil wells and 1,457 gross (334 net) productive gas wells. Productive
wells are either producing wells or wells capable of commercial production
although currently shut in. One or more completions in the same wellbore 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.
Drilling Activity
The following table sets forth the wells drilled and recompleted in
which St. Mary participated during each of the three years indicated:
Years Ended December 31,
---------------------------------------------------
2002 2001 2000
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development:
Oil..................... 26 11.52 48 14.49 40 17.37
Gas..................... 103 38.89 154 33.28 107 24.94
Non-productive.......... 27 14.42 31 7.13 31 9.38
--- ----- --- ----- --- -----
156 64.83 233 54.90 178 51.69
--- ----- --- ----- --- -----
Exploratory:
Oil..................... 3 1.22 3 1.55 6 4.17
Gas..................... 1 .10 9 1.84 11 3.63
Non-productive.......... 8 2.64 7 2.56 8 4.32
--- ----- --- ----- --- -----
12 3.96 19 5.95 25 12.12
--- ----- --- ----- --- -----
Farmout or non-consent... 8 - 9 - 8 -
--- ----- --- ----- --- -----
Total (1) ............... 176 68.79 261 60.85 211 63.81
=== ===== === ===== === =====
---------------------------
(1) Does not include 14, 12 and 12 gross wells completed on St.
Mary's fee lands during 2002, 2001 and 2000, respectively, in
which we have only a royalty interest.
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not own any drilling equipment.
30
Acreage
The following table sets forth the gross and net acres of developed and
undeveloped oil and gas leases, fee properties, mineral servitudes and lease
options held by St. Mary as of December 31, 2002. Undeveloped acreage includes
leasehold interests that may already have been classified as containing proved
undeveloped reserves.
Developed Acres (1) Undeveloped Acres (2) Total
------------------- --------------------- -------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Arkansas............................ 2,256 399 166 28 2,422 427
Louisiana.......................... 90,574 33,075 25,709 10,381 116,283 43,456
Montana............................ 57,732 28,630 174,923 139,410 232,655 168,040
New Mexico......................... 7,160 2,151 1,320 920 8,480 3,071
North Dakota....................... 93,362 36,780 95,999 61,064 189,361 97,844
Oklahoma........................... 231,147 60,633 43,661 20,163 274,808 80,796
Texas.............................. 138,304 49,155 92,941 35,735 231,245 84,890
Wyoming............................ 17,598 6,277 56,689 48,942 74,287 55,219
Other (3) ......................... 2,501 346 13,465 8,647 15,966 8,993
------- ------- ------- ------- --------- -------
640,634 217,446 504,873 325,290 1,145,507 542,736
------- ------- ------- ------- --------- -------
Louisiana Fee Properties............ 10,337 10,337 14,577 14,577 24,914 24,914
Louisiana Mineral Servitudes........ 9,785 5,346 4,768 4,255 14,553 9,601
------- ------- ------- ------- --------- -------
20,122 15,683 19,345 18,832 39,467 34,515
------- ------- ------- ------- --------- -------
Total ........................... 660,756 233,129 524,218 344,122 1,184,974 577,251
======= ======= ======= ======= ========= =======
-----------
(1) Developed acreage is acreage assigned to producing wells for the
spacing unit of the producing formation. Developed acreage in certain
of St. Mary'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 proved reserves.
(3) Includes interests in Alabama, Colorado, Kansas, Mississippi, South
Dakota, Utah and Washington. St. Mary also holds an overriding royalty
interest in an additional 43,108 gross acres in Utah.
31
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims
arising out of our operations in the normal course of business. As of this date,
no legal proceedings are pending against us that individually or collectively
could have a material adverse effect upon our financial condition or results of
operations.
On March 27, 2002, Nance Petroleum Corporation, a wholly owned
subsidiary, was named along with several other leaseholders and interested
parties as an additional co-defendant in a lawsuit that was originally filed in
the U.S. District Court for the District of Montana on June 12, 2001. The
plaintiff, the Northern Plains Resource Council, Inc. ("NPRC"), an environmental
public interest group, sued the U.S. Bureau of Land Management, the U.S.
Secretary of the Interior, the Montana BLM State Director and Fidelity
Exploration & Production Company. The lawsuit, which was reported in our 2001
Form 10-K and our 2002 Form 10-Qs, seeks the cancellation of all federal leases
related to coalbed methane development in Montana issued by the BLM since
January 1, 1997. This cancellation is sought primarily on the grounds of an
alleged failure of the BLM to comply with federal environmental laws. NPRC
alleges that the environmental impacts of coalbed methane development were not
properly analyzed before the challenged leases were issued. The Montana portion
of our Hanging Woman Basin coalbed methane project contains approximately 71,000
total net acres. The lawsuit potentially affects the approximately 47,000 net
acres that are subject to federal leases. Based on information presently
available, we believe that the BLM complied with the applicable environmental
laws. Nevertheless, there is no assurance as to the outcome of the lawsuit, and
therefore, there is no assurance that it will not adversely affect our coalbed
methane project. Even if the federal leases in Montana become unavailable, we
anticipate continuing with the Hanging Woman Basin project in Wyoming, and
obtaining additional non-federal leases in Montana. See "Properties - Other
Areas" for a discussion of other recent coalbed methane legal developments.
As previously reported in our 2002 Quarterly Reports on Form 10-Q, GNK
Acquisition Corp., a recently acquired wholly owned subsidiary, was served in a
lawsuit on May 1, 2002, that had been filed earlier in 2002 in the District
Court in Shelby County, Texas. This suit was filed by Samson Lone Star Limited
Partnership against GNK Acquisition Corp. and GNK, Inc., the previous owner of
GNK Acquisition Corp. This suit was settled and dismissed in February 2003 with
no material effect on our financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
the fourth quarter of 2002.
32
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the names, ages and positions held by
St. Mary's executive officers as of January 31, 2003.
Name Age Position
- ---- --- --------
Mark A. Hellerstein 50 Chairman of the Board, President
and Chief Executive Officer
Ronald D. Boone 55 Executive Vice President and Chief
Operating Officer
Robert L. Nance 66 Senior Vice President, and President
of Nance Petroleum Corporation, a
wholly-owned subsidiary of St. Mary
since 1999
Robert T. Hanley 56 Vice President - Business Development
Richard C. Norris 47 Vice President - Finance, Secretary
and Treasurer
Milam Randolph Pharo 50 Vice President - Land and Legal
Garry A. Wilkening 52 Vice President - Administration and
Controller
Douglas W. York 41 Vice President - Acquisitions and
Engineering
Each of the executive officers has held the above positions for the
past five years, with the exception of the following:
Mark A. Hellerstein was appointed Chairman of the Board in September
2002.
Robert L. Nance has served as Senior Vice President of St. Mary since
2001.
Robert T. Hanley has served as Vice President - Business Development
since 2000. Mr. Hanley was Chief Financial Officer of Nance Petroleum
Corporation from 1999 to 2000 and Chief Financial Officer of Panterra Petroleum,
a partnership between St. Mary and Nance Petroleum Corporation, from 1992 to
1999.
Richard C. Norris has served as Vice President - Finance and Secretary
since 1999. Mr. Norris was appointed Treasurer in 1991, and from 1991 to 1999 he
was also Vice President - Accounting and Administration. Mr. Norris joined St.
Mary in 1982 as Corporate Controller.
Milam Randolph Pharo has served as Vice President - Land and Legal
since 1998. Mr. Pharo joined St. Mary in 1996 as Vice President - Land and was
previously in private practice as an attorney specializing in oil and gas
matters since 1977.
Garry A. Wilkening has served as Vice President - Administration since
1999. Mr. Wilkening joined St. Mary in 1993 as Corporate Controller.
The executive officers of the Company serve at the pleasure of the
board of directors and do not have fixed terms. Executive officers generally are
elected at the regular meeting of the board immediately following the annual
stockholders meeting. Any officer or agent elected or appointed by the board may
33
be removed by the board whenever in its judgement the best interests of the
Company will be served thereby without prejudice, subject however, to
contractual rights, if any, of the person so removed. Messrs. Hellerstein, Boone
and Nance are members of the board of directors.
There are no family relationships, first cousin or closer, between any
executive officer and director. There are no arrangements or understandings
between any officer and any other person pursuant to which that officer was
elected.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Market Information. St. Mary's common stock is currently traded on the
New York Stock Exchange under the symbol SM after transferring from the Nasdaq
on November 20, 2002. The range of high and low sales prices for the quarterly
periods in 2002 and 2001, as reported by the New York Stock Exchange after
November 19, 2002, and the Nasdaq National Market System before November 20,
2002, is set forth below:
Quarter Ended High Low
------------ ---- ---
December 31, 2002 $27.35 $23.16
September 30, 2002 24.71 19.00
June 30, 2002 25.05 21.00
March 31, 2002 23.25 18.75
December 31, 2001 $22.20 $14.65
September 30, 2001 21.81 14.58
June 30, 2001 25.24 19.25
March 31, 2001 35.00 20.63
Holders. As of February 28, 2003, the number of record holders of St.
Mary's common stock was 173. Management believes, after inquiry, that the number
of beneficial owners of our common stock is in excess of 3,700.
Dividends. St. Mary has paid cash dividends to stockholders every year
since 1940. Annual dividends of $0.10 per share were paid in each of the years
1998 through 2002. We expect that our practice of paying dividends on our common
stock will continue, although the payment of future dividends on our common
stock will continue to depend on our earnings, capital requirements, financial
condition and other factors. In addition, the payment of dividends is subject to
covenants in our bank credit facility, including the requirement that we
maintain certain levels of stockholders' equity. Dividends are currently paid on
a semi-annual basis. Dividends paid totaled $2,787,000 in 2002 and $2,795,000 in
2001.
Restricted Shares. On January 29, 2003, St. Mary issued 3,380,818
restricted shares of our common stock in connection with the acquisition of oil
and gas properties from Flying J Oil & Gas Inc. and Big West Oil & Gas
Inc. The shares are subject to contractual restrictions on transfer for a period
of two years and St. Mary will be required to file a registration statement for
the resale of the shares and have it declared effective upon the expiration of
the two-year period.
34
Equity Compensation Plans. St. Mary has a stock option plan, an
incentive stock option plan and an employee stock purchase plan under which
options and shares of St. Mary common stock are authorized for grant or issuance
as compensation to eligible employees, consultants and members of the board of
directors. Each of these plans has been approved by our stockholders. See Note 7
of the Notes to Consolidated Financial Statements included in this report for
further information about the material terms of these plans. The following table
is a summary of the shares of common stock authorized for issuance under our
equity compensation plans as of December 31, 2002:
( a ) ( b ) ( c )
Number of securities
Number of securities remaining available for
to be issued upon Weighted-average future issuance under
exercise of exercise price of equity compensation plans
outstanding options, outstanding options, (excluding securities
Plan Category warrants and rights warrants and rights reflected in column (a))
- ---------------------------------- -------------------- -------------------- -------------------------
Equity compensation plans approved
by security holders 3,061,566 $21.34 1,118,588(1)
Equity compensation plans not
approved by security holders - - -
-------------------- -------------------- -------------------------
Total 3,061,566 $21.34 1,118,588
==================== ==================== =========================
- --------------
(1) Includes 870,073 shares which are authorized for issuance
under our employee stock purchase plan.
35
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data for St. Mary
as of the dates and for the periods indicated. The financial data for each of
the five years presented were derived from the consolidated financial statements
of St. Mary. The following data should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations," which
includes a discussion of factors materially affecting the comparability of the
information presented, and in conjunction with St. Mary's consolidated financial
statements included elsewhere in this report.
Years Ended December 31,
------------------------------------------------------
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
(In thousands, except per share data)
Income Statement Data:
Operating revenues:
Oil and gas production $ 185,670 $ 203,973 $ 188,407 $ 73,387 $ 71,413
Gas marketing revenue 8,399 420 - - -
Gain (loss) on sale of proved
properties (2,633) 367 3,404 (55) 7,685
Derivative gain 3,188 - - - -
Other 1,770 2,709 3,855 1,582 411
---------- ---------- ---------- ---------- ----------
Total operating revenues 196,394 207,469 195,666 74,914 79,509
---------- ---------- ---------- ---------- ----------
Operating expenses:
Oil and gas production 50,839 55,000 38,461 19,574 17,770
Depletion, depreciation &
amortization 54,432 51,346 40,129 22,574 24,912
Exploration 19,501 19,518 9,633 11,593 11,705
Impairment of proved properties - 820 4,449 3,982 17,483
Abandonment and impairment of
unproved properties 2,446 3,865 1,841 6,616 4,457
General and administrative 14,299 11,762 11,166 9,172 7,097
Gas marketing expense 7,982 420 - - -
Derivative loss - 1573 - - -
Other 1,206 1,253 1,437 1,802 9,304
---------- ---------- ---------- ---------- ----------
Total operating expenses 150,705 145,557 107,116 75,313 92,728
---------- ---------- ---------- ---------- ----------
Income (loss) from operations 45,689 61,912 88,550 (399) (13,219)
Non-operating (expense) income (3,110) 376 737 75 (1,027)
Income tax (expense) benefit (15,019) (21,829) (33,667) 406 5,415
---------- ---------- ---------- ---------- ----------
Income (loss) from continuing operations 27,560 40,459 55,620 82 (8,831)
Gain on sale of discontinued operations,
net of income taxes - - - - 34
---------- ---------- ---------- ---------- ----------
Net income (loss) $ 27,560 $ 40,459 $ 55,620 $ 82 $ (8,797)
========== ========== ========== ========== ==========
Basic net income (loss) per common share $ 0.99 $ 1.45 $ 2.00 $ - $ (0.40)
========== ========== ========== ========== ==========
Diluted net income (loss) per common share $ 0.97 $ 1.42 $ 1.97 $ - $ (0.40)
========== ========== ========== ========== ==========
Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
Basic weighted average common shares
outstanding 27,856 27,973 27,781 22,198 21,874
Diluted weighted average common shares
outstanding 28,391 28,555 28,271 22,329 21,874
36
Years Ended December 31,
------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(In thousands, except per share data)
Balance Sheet Data (end of period):
Working capital $ 2,050 $ 34,000 $ 40,639 $ 13,440 $ 9,785
Net property and equipment 471,939 358,930 252,411 180,664 143,825
Total assets 537,139 436,989 321,895 230,438 184,497
Long-term obligations 113,601 64,000 22,000 13,000 19,398
Total stockholders' equity 299,513 286,117 250,136 188,772 134,742
Other Data:
Discretionary cash flow (1) $ 118,762 $ 141,278 $ 132,947 $ 43,984 $ 44,332
Net Cash provided by (used in):
Operating activities 141,709 127,492 92,267 40,755 45,386
Investing activities (180,931) (159,075) (112,868) (22,243) (36,982)
Financing activities 46,260 29,080 13,025 (12,138) (7,695)
Capital and exploration expenditures, cash
and noncash 192,988 182,863 125,184 91,184 57,855
- ------------
(1) Discretionary cash flow is calculated as net income plus depreciation
and amortization expense, exploration expense, deferred tax expense and
unrealized derivative loss minus deferred tax benefit and unrealized
derivative gain. Discretionary cash flow is presented since it is a
financial measure widely used for St. Mary's industry, and management
believes that it provides useful additional information for analysis of
St. Mary's ability to satisfy capital expenditure expectations and debt
service and working capital requirements. Discretionary cash flow
should not be considered in isolation or as a substitute for net
income, income from operations, 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. As discretionary cash flow
excludes some, but not all, items that affect net income and may vary
among companies, the discretionary cash flow presented above may not be
comparable to similarly titled measures of other companies. The
following table provides a reconciliation of discretionary cash flow to
net cash provided by operating activities for the periods presented.
Following is a reconciliation of discretionary cash flow to cash
provided by operations:
Years Ended December 31,
------------------------------------------------------
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
Discretionary cash flow $ 118,762 $ 141,278 $ 132,947 $ 43,984 $ 44,332
Writedown of investments - - - - 8,502
Loss (gain) on sales 1,797 (367) (5,560) 55 (7,685)
Non-exploratory dry hole
exploration expense (11,824) (10,490) (8,844) (6,602) (6,813)
Minority interest & other 40 (1,327) 1,260 29 1,039
Changes in working capital 32,934 (1,602) (27,536) 3,289 6,011
---------- ---------- ---------- ---------- ----------
Cash Flow from Operations $ 141,709 $ 127,492 $ 92,267 $ 40,755 $ 45,386
========== ========== ========== ========== ==========
37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
Overview
During the year ended December 31, 2002, the financial markets were
characterized by instability. At the same time some stability returned to the
oil and gas industry. The NYMEX gas price averaged $3.25 per MMBtu and oil
prices averaged $26.06 per barrel. Rig costs and operating costs decreased
slightly with after-hedge price realizations down 11%, cash costs plus DD&A flat
on an MCFE basis, production relatively flat and a $2.6 million pre-tax loss on
property sales compared to a $367,000 pre-tax gain in 2001, net income decreased
$14.2 million to $26.7 million. We replaced 305% of our 2002 production at a
finding cost of $1.15 per MCFE. This success was led by excellent drilling
results at the NE Mayfield field in Oklahoma. In December 2002 we acquired the
Williston Basin properties of Burlington Resources Oil & Gas Company LP for
$69.5 million in cash. In March 2002 we completed a private placement of $100.0
million of senior convertible notes.
The industry enters 2003 with less than average gas in storage, cold
weather in the eastern half of the United States, a continuing petroleum
industry strike in Venezuela and the possibility of escalating conflict in the
Middle East. Rig and other service costs have remained moderate, and the rig
count has not increased to the extent predicted. Our financial condition is
excellent, and we have an outstanding inventory of prospects to be drilled. We
caution that higher gas prices may cause rig rates and operating costs to
increase in future months. Subject to uncertainties specified in our cautionary
statement about forward-looking statements, we project that results of
operations for 2003 should reflect higher revenues and higher net income.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operation is based
upon the information reported in our consolidated financial statements. The
preparation of these consolidated financial statements requires us to make
assumptions and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses as well as the disclosure of contingent
assets and liabilities at the date of our financial statements. We base our
decisions on historical experience and various other sources that are believed
to be reasonable under the circumstances. Actual results may differ from the
estimates we calculated due to changing business conditions or unexpected
circumstances. Policies we believe are critical to understanding our business
operations and results of operations are detailed below. For additional
information on our significant accounting policies you should see Note 1 -
Summary of Significant Accounting Policies and Note 11 - Disclosures About Oil
and Gas Producing Activities in our accompanying consolidated financial
statements.
Revenue recognition - We are engaged in the exploration, development,
acquisition and production of natural gas and crude oil. Our revenue
recognition policy is significant because revenue is a key component of
our results of operations and our forward-looking statements contained
in Liquidity and Capital Resources. We derive our revenue primarily
from the sale of produced natural gas and crude oil. Revenue is
recorded in the month our production is delivered to the purchaser, but
payment is generally received between 30 and 90 days after the date of
production. At the end of each month we make estimates of the amount of
production delivered to the purchaser and the price we will receive. We
use our knowledge of our properties, their historical performance, the
anticipated effect of weather conditions during the month of
production, NYMEX and local spot market prices and other factors as the
38
basis for these estimates. Variances between our estimates and the
actual amounts received are recorded in the month payment is received.
Crude oil and Natural Gas Hedging - Generally, our crude oil and
natural gas hedging contracts will qualify for cash flow hedge
accounting under Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This
policy is significant because it affects the timing of revenue
recognition in our statements of operations and is discussed
prominently in our forward looking statements contained in Liquidity
and Capital Resources. Under this accounting pronouncement a majority
of the gain or loss from a contract qualifying as a cash flow hedge is
recorded in the month the contract settles with the counterparty. We
include this gain or loss in oil and gas production revenues. If our
natural gas and crude oil hedge contracts did not qualify for hedge
accounting treatment or we chose not to use this hedge accounting
methodology, our periodic statements of operations could include
significant changes in the estimate of non-cash derivative gain or loss
due to swings in the value of these contracts. Consequently we would
report a different amount for oil and gas production revenues in our
statement of operations. These fluctuations could be especially
significant in a volatile pricing environment such as we have
encountered over the last three years.
Oil and gas reserve quantities - Estimated reserve quantities and the
related estimates of future net cash flows affect our periodic
calculations of depletion, depreciation and impairment for our proved
oil and gas properties. 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 periods from known reservoirs under
existing economic and operating conditions. Future cash inflows and
future production and development costs are determined by applying
benchmark prices and costs, including transportation, quality and basis
differentials, in effect at the end of each period to the estimated
quantities of oil and gas remaining to be produced at the end of that
period. Expected cash flows are reduced to present value using a
discount rate that depends upon the purpose for which the reserve
estimates will be used. Reserve estimates are inherently imprecise, and
estimates of new discoveries are more imprecise than those of proved
producing oil and gas properties. We expect that periodic reserve
estimates will change in the future as additional information becomes
available or as oil and gas prices and operating and capital costs
change. Changes in depletion, depreciation or impairment calculations
caused by changes in reserve quantities or net cash flows are recorded
in the period that the reserve estimates changed.
Valuation of long-lived and intangible assets - Our property and
equipment is recorded at cost. An impairment allowance is provided on
unproved property when we determine that the property will not be
developed. We evaluate the realizability of our proved producing and
other long-lived assets whenever events or changes in circumstances
indicate that an impairment may have occurred. Our impairment test
compares the expected undiscounted future net revenues from a property,
using escalated pricing with the related net capitalized costs of the
property at the end of each period. When the net capitalized costs
exceed the undiscounted future net revenue of a property, the cost of
the property is written down to our estimate of fair value, which is
determined by applying a 15% discount rate to future net revenues.
Other companies have their own criteria for acceptable internal rates
of return, which may differ from our criteria. Additionally, our
criteria for an acceptable internal rate of return are subject to
change over time. Different pricing assumptions or discount rates could
result in a different calculated impairment.
39
Income taxes - We provide for deferred income taxes on the difference
between the tax basis of an asset or liability and its carrying amount
in our financial statements in accordance with Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes." 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. Considerable judgment is required in determining
when these events may occur and whether recovery of an asset is more
likely than not. Additionally, our federal and state income tax returns
are generally not filed before the consolidated financial statements
are prepared, therefore we estimate the tax basis of our assets and
liabilities at the end of each period as well as the effects of tax
rate changes, tax credits and net operating loss carryforwards.
Adjustments related to differences between the estimates we used and
actual amounts we reported are recorded in the period in which we file
our income tax returns. These adjustments and changes in our estimates
of asset recovery could have a material impact on our results of
operations.
The remaining portion of Management's Discussion and Analysis contains
additional discussion of management and accounting policies that are relevant to
specific disclosures.
40
Results of Operations
The following table sets forth selected operating data for the periods
indicated:
Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
(In thousands, except per volume data)
Oil and gas production revenues:
Gas production................................... $ 114,334 $ 147,292 $ 131,979
Oil production................................... 71,336 56,681 56,428
---------- ---------- ----------
Total......................................... $ 185,670 $ 203,973 $ 188,407
========== ========== ==========
Net production:
Gas (MMcf)....................................... 38,164 39,491 38,346
Oil (MBbls)...................................... 2,815 2,434 2,398
MMCFE............................................ 55,055 54,093 52,731
Average sales price (1):
Gas (per Mcf).................................... $ 3.00 $ 3.73 $ 3.44
Oil (per Bbl).................................... $ 25.34 $ 23.29 $ 23.53
Oil and gas production costs:
Lease operating expenses......................... $36,472 $ 40,505 $ 25,567
Transportation costs............................. 3,184 2,321 1,817
Production taxes................................. 11,183 12,174 11,077
---------- ---------- ----------
Total......................................... $ 50,839 $ 55,000 $ 38,461
========== ========== ==========
Additional per MCFE data:
Sales price (see Discussion under
Accounting Matters)............................ $ 3.37 $ 3.77 $ 3.57
Lease operating expenses......................... (0.66) (0.75) (0.48)
Transportation costs............................. (0.06) (0.04) (0.04)
Production taxes................................. (0.20) (0.23) (0.21)
---------- ---------- ----------
Operating margin.............................. $ 2.45 $ 2.75 $ 2.84
========== ========== ==========
Depletion, depreciation and amortization......... $ 0.99 $ 0.95 $ 0.76
Impairment of proved properties.................. $ 0.00 $ 0.02 $ 0.08
General and administrative....................... $ 0.26 $ 0.22 $ 0.21
---------------------
(1) Includes the effects of the Company's hedging activities.
41
2002 to 2001 Comparison
Oil and Gas Production Revenues. Oil and gas production revenues
decreased $18.3 million, or 9% to $185.7 million in 2002 compared to $204.0
million in 2001. The following table presents the components of increases or
(decreases) between 2002 and 2001:
Production Price Price
% Change $ Change % Change
------------------------------------
o Natural Gas (3%) ($0.73)/Mcf (20%)
o Oil 16% $2.05/Bbl 9%
Projections of pricing for oil and gas lead us to believe that our
average realized price for both natural gas and oil will increase in 2003. We
also expect our acquisitions in late 2002 and early 2003 to cause a significant
increase in oil production in 2003. Average net daily production increased to a
new annual record of 150.8 MMCFE in 2002 compared to 148.2 MMCFE in 2001. Our
November 2001 acquisition from Choctaw II Oil & Gas, Ltd. added $13.7
million of revenue and average daily production of 11.2 MMCFE in 2002. Wells
completed in 2002 and our acquisitions added average net daily production of
19.7 MMCFE. These increases offset declines in average daily production from
older properties that include an average 5.8 MMCFE/day decline from the Judge
Digby field.
St. Mary hedged approximately 53.9% or 1,518 MBbls of its oil
production for 2002 and realized a $1.9 million increase in oil revenue
attributable to hedging compared to a $1.9 million decrease in 2001. Without
these contracts we would have received an average price of $24.67 per Bbl in
2002 compared to $24.08 per Bbl in 2001. We also hedged 44.9% of our 2002 gas
production or 18.9 million MMBtu and realized a $4.1 million decrease in gas
revenue attributable to hedging compared to a $19.2 million decrease in gas
revenues in 2001. Without these contracts we would have received an average
price of $3.10 per Mcf for 2002 compared to $4.22 per Mcf in 2001. With the
contracts we currently have in place and the December 31, 2002, projections of
pricing for natural gas and crude oil in 2003, we project that we will record
decreases in both oil and gas revenues attributable to hedging in 2003.
Gain (loss) on sale of proved properties. In December we closed the
sale of our Flour Bluff field in Texas and recognized a $2.6 million loss.
Marketed Gas Revenue and Expense. For the year ended December 31, 2002,
we received $8.4 million from the sale of marketed natural gas produced by third
parties. Costs associated with these revenues totaled $8.0 million and resulted
in gross margin to us of $417,000. Due to pipeline imbalances, cost inflation,
and fluctuations in natural gas prices we may not always have a positive gross
margin from gas marketing activities.
Oil and Gas Production Expenses. Oil and gas production expenses
consist of lease operating expenses, production taxes and transportation
expenses. Total production expenses decreased $4.2 million, or 8% in 2002 to
$50.8 million compared with $55.0 million in 2001. In the second quarter of 2002
our Gulf Coast region experienced a $2.7 million decrease in LOE that was
comprised of a decrease in workover expense and an adjustment due to the
issuance of a revised Authorization for Expenditure by the operator at Judge
Digby. This AFE indicated that workover LOE we previously expensed under the
original AFE should have been capitalized and recorded as property, plant and
equipment. Our total workover expense decreased $5.1 million from 2001 to 2002.
Other decreases in LOE attributable to our efforts to reduce LOE in total and on
a per MCFE basis were offset by $7.3 million of LOE incurred on properties
42
acquired since November 2001, wells completed in 2002 and the $863,000 increase
in transportation costs. The $991,000 decrease in production taxes reflects the
decrease in revenue discussed above.
Total production costs per MCFE decreased 10% to $0.92 for 2002
compared with $1.02 in 2001. This decrease is comprised of the following:
o A $0.03 per MCFE decrease in production taxes due to lower per
MCFE prices.
o A $0.09 per MCFE decrease in LOE, net of general inflation
increases, due to our efforts to decrease LOE in total and on
a per MCFE basis.
o A $0.10 per MCFE decrease in LOE attributable to the decrease
in total workover expense in excess of general cost inflation
increases.
o A $0.03 per MCFE increase in LOE and transportation costs
attributable to property acquisitions and 2002 well additions
outside of the Williston Basin.
o A $0.09 per MCFE increase in LOE and transportation costs
attributable to increased activity in the higher cost
Williston Basin.
Although we continue to monitor these costs, we believe that the trend
of decreases in LOE on an absolute basis and on a per MCFE basis will not
continue into the future. New workover activity is always a possibility in our
Gulf Coast region, and it is likely that our acquisitions of producing
properties in the higher-cost, oil-based Williston Basin will cause a general
increase in LOE and will lead to additional workover activities as we attempt to
enhance the performance and lengthen the lives of those properties.
Depreciation, Depletion, Amortization and Impairment. DD&A
increased $3.1 million or 6% to $54.4 million in 2002 compared with $51.3
million in 2001. This increase reflects both the increase in production between
the respective periods for 2002 and 2001 and acquisitions and drilling results
from both years that caused DD&A per MCFE to increase by 4% to $0.99 in 2002
compared with $0.95 in 2001.
Abandonment and impairment of unproved properties decreased $1.4
million or 37% to $2.4 million in 2002 compared to $3.9 million in 2001. This
decrease is due to a decrease in abandonment of expired leases in 2002. It is
not likely that this trend will continue into the future due to our increased
investment in unproved properties from our acquisitions in late 2002 and early
2003.
Exploration. Exploration expense for 2002 remained constant at $19.5
million. Percentages of total exploration expense are as follows:
2002 2001
---- ----
o Geological and geophysical expenses 13% 19%
o Exploratory dry holes 39% 47%
o Overhead and other expenses 48% 34%
In 2003 we have budgeted for geological and geophysical expenses and
expect to incur overhead and other expenses in the pursuit of exploration.
However, oil and gas exploration is imprecise, and success can be affected by
numerous factors. Not every likely geological structure contains oil or natural
gas. Even when oil or natural gas is discovered there are no guarantees that
sufficient quantities can be produced to justify the completion of an
exploratory well.
43
General and Administrative. General and administrative expenses
increased $2.5 million or 22% to $14.3 million in 2002 compared to $11.8 million
in 2001. On a per MCFE basis these costs increased 18% to $0.26 in 2002 from
$0.22 in 2001. We experienced an increase in non-compensation general expenses
of $1.0 million due primarily to increased personnel and general cost inflation.
This amount plus a $3.7 million increase in compensation expense associated with
increased personnel and our incentive plans were partially offset by a $2.2
million increase in COPAS overhead reimbursement from operations and costs
allocated to exploration expense. As we continue to grow in size and number of
personnel we expect that general and administrative expenses will also grow.
However, we anticipate that these expenses will decrease on a per MCFE basis in
2003.
Interest Expense. Interest expense increased to $3.9 million in 2002.
This amount reflects accrued interest on our senior convertible notes. The
amount we accrued and paid in 2002 was affected by a fixed-rate to floating-rate
interest rate swap we entered into in March 2002 and closed at a net gain in
December 2002. Without this swap, interest expense for the period ending
December 31, 2002, would have been $4.6 million. We anticipate that interest
expense in 2003 will be significantly higher than the 2002 amount due to
termination of the interest rate swap and increased borrowing from our credit
facility.
Income Taxes. Income tax expense totaled $15.0 million in 2002
resulting in an effective tax rate of 35.3% compared to $21.8 million in 2001 at
an effective tax rate of 35.0%. The effective rate change from 2001 reflects
increased accrued state income taxes from marginal rate adjustments offset by
adjustments to valuation allowances against state net operating loss carryovers.
We adjusted the valuation allowance after we considered a number of factors,
including our prior utilization of net operating losses and carryovers, tax
planning strategies for utilizing both federal and state net operating loss and
capital loss carryovers and projections of future taxable income. We also took
into account the reversal of prior temporary timing differences and the effect
that recent acquisitions will have on anticipated expenditures for intangible
drilling costs. Based on the weight of positive and negative evidence regarding
the recoverability of our net deferred tax assets, we concluded that only a
partial valuation allowance was required. Future effective tax rates could be
adversely affected if our taxable income increases to the point of being taxed
at the highest federal marginal rate, increased revenues in states with higher
statutory rates, unfavorable changes in tax laws and regulations, and by changes
in our opinion of our ability to absorb our deferred tax assets due to changes
in economic conditions.
Net Income. Net income decreased to $27.6 million for 2002 compared to
$40.5 million for 2001. A 20% decrease in gas prices and a 3% decrease in gas
production partially offset by a 16% increase in oil production and a 9%
increase in oil price resulted in an $18.3 million decrease in oil and gas
production revenue between the two periods. Other large items causing a decrease
in net income were a $3.0 million decrease in gain from property sales, a $3.1
million increase in DD&A, a $2.5 million increase in G&A and a $3.5
million increase in interest expense. The decreases were partially offset by a
$4.8 million increase in derivative gains, a $4.2 million decrease in production
costs, and a $1.4 million decrease in unproved property impairment. The net
result of the changes caused a $6.8 million decrease in income tax expense.
2001 to 2000 Comparison
Oil and Gas Production Revenues. Oil and gas production revenues
increased $15.6 million, or 8% to a record $204.0 million in 2001 compared to
$188.4 million in 2000. Revenue from gas production increased $15.3 million or
12%. This increase was a result of a gas production volume increase of 3% and an
8% increase in the average realized gas price to $3.73 per Mcf in 2001. Revenue
44
from oil production increased $253,000. This increase resulted from an oil
production volume increase of 1% offset by a 1% decrease in the average realized
oil price to $23.29 per Bbl in 2001. Our share of revenue from wells completed
in 2001 added $27.5 million of revenue and our December 2000 acquisition of JN
Exploration properties added $11.5 million of revenue and average daily
production of 7.4 MMCFE in 2001. Average net daily production increased to a new
annual record of 148.2 MMCFE in 2001 compared to 144.1 MMCFE in 2000. Wells
completed in 2001 offset 22.3 MMCFE of decline in average daily production from
older properties.
St. Mary hedged approximately 34.6% or 841 MBbls of its oil production
for 2001 and realized a $1.9 million decrease in oil revenue attributable to
hedging compared to a $13.2 million decrease in 2000. Without these contracts we
would have received an average price of $24.08 per Bbl in 2001 compared to
$29.01 per Bbl in 2000. We also hedged 40.6% of our 2001 gas production or 17.6
million MMBtu and realized a $19.2 million decrease in gas revenue attributable
to hedging compared to a $20.5 million decrease in gas revenues in 2000. Without
these contracts we would have received an average price of $4.22 per Mcf for
2001 compared to $3.97 per Mcf in 2000.
Oil and Gas Production Expenses. Total production expenses increased
$16.5 million, or 43% in 2001 to $55.0 million compared with $38.5 million in
2000. During 2001 we experienced a $4.9 million increase in workover expense,
most of which related to activity in the Williston Basin and the Gulf Coast
Region. Williston Basin acquisitions in the last half of 2000 and in 2001 added
$1.7 million of LOE. Recurring LOE from our JN Exploration acquisition
properties represented $1.1 million of the increase and wells completed in 2001
added another $1.1 million. We experienced higher recurring LOE from wells
completed in the Williston Basin, the Permian Basin and the Gulf Coast/Gulf of
Mexico as a result of increased competition for limited availability of services
and general cost inflation. Higher production taxes and transportation expenses
resulting from higher oil and gas revenues account for $1.6 million of the
increase. Total production costs per MCFE increased 40% to $1.02 for 2001
compared with $0.73 in 2000. An $0.18 per MCFE increase was due to the increase
in workover expense, plus LOE from acquisitions and wells completed in 2001.
Another $0.02 per MCFE increase was due to increased production taxes and
transportation expenses. The remaining increase is due to general cost
inflation.
Depreciation, Depletion, Amortization and Impairment. DD&A
increased $11.2 million or 28% to $51.3 million in 2001 compared with $40.1
million in 2000. DD&A expense per MCFE increased 25% to $0.95 in 2001
compared to $0.76 in 2000. This increase reflects acquisitions and drilling
results in 2000 and 2001 that added costs at a higher per unit rate. The
DD&A per MCFE rate was further affected by downward adjustments to reserves
due to pricing differences between December 31, 2001 and December 31, 2000.
St. Mary recorded an $820,000 impairment of proved oil and gas
properties in 2001 compared with $4.4 million in 2000. Impairments in 2001
include a declining performance adjustment of $520,000 from the Thornton South
prospect in Texas and various marginal well impairments.
Abandonment and impairment of unproved properties increased $2.0
million or 110% to $3.9 million in 2001 compared to $1.8 million in 2000. This
increase is due to an increase in abandonment of expired leases in 2001 and the
impairment of leasehold costs related to several exploratory dry holes.
45
Exploration. Exploration expense for 2001 increased $9.9 million or
103% to $19.5 million compared with $9.6 million in 2000. Percentages of total
exploration expense are as follows:
2001 2000
---- ----
o Geological and geophysical expenses 19% 24%
o Exploratory dry holes 47% 21%
o Overhead and other expenses 34% 55%
General and Administrative. General and administrative expenses
increased $596,000 or 5% to $11.8 million in 2001 compared to $11.2 million in
2000. Increases in compensation expense associated with increased personnel, our
incentive plans and general cost inflation were offset by a $4.3 million
increase in COPAS overhead reimbursements from operations and costs allocated to
exploration expense
Income Taxes. Income tax expense totaled $21.8 million in 2001
resulting in an effective tax rate of 35.0% compared to $33.7 million in 2000
with an effective tax rate of 37.7%. The effective rate change from 2000
reflects decreased accrued state income taxes from marginal rate adjustments and
a decrease in deferred federal income tax due to a 1% rate decrease from the
highest federal marginal rate.
Net Income. Net income decreased to $40.5 million for 2001 compared to
$55.6 million for 2000. An 8% increase in gas prices and a 3% increase in
production volumes resulted in a $15.6 million increase in oil and gas
production revenue. Increases in oil and gas production costs and DD&A of
$27.8 million, a $5.2 million decrease from gains on sale of proved property and
KMOC stock and a $9.9 million increase in exploration expense offset the
increase in revenue and an $11.8 million decrease in income tax expense.
Liquidity and Capital Resources
Our primary sources of liquidity are the cash provided by operating
activities, debt financing, sales of non-strategic properties and access to the
capital markets. All of these sources can be impacted by significant
fluctuations in oil and gas prices. An unexpected decrease in prices would
reduce expected cash flow from operating activities, might reduce the borrowing
base on our credit facility, could reduce the value of our non-strategic
properties and historically has limited our industry's access to the capital
markets.
We use cash for the acquisition, exploration and development of oil and
gas properties and for the payment of debt obligations, trade payables and
stockholder dividends. Exploration and development programs are generally
financed from internally generated cash flow, debt financing and cash and cash
equivalents on hand. In the event of an unexpected decrease in oil and gas
prices, cash uses such as the acquisition of oil and gas properties and the
payment of stockholder dividends are discretionary and can be reduced or
eliminated. At any given point in time, we may be obligated to pay for
commitments to explore for or develop oil and gas properties or incur trade
payables. However, future obligations can be reduced or eliminated when
necessary. We are currently only required to make interest payments on our debt
obligations. An unexpected increase in oil and gas prices provides flexibility
to modify our uses of cash flow.
We continually review our capital expenditure budget to reflect changes
in current and projected cash flow, acquisition opportunities, debt requirements
and other factors.
46
Cash Flow. St. Mary's net cash provided by operating activities
increased $14.2 million or 11% to $141.7 million in 2002 compared to $127.5
million in 2001. The increase reflects a change between years of $29.3 million
in other current assets relating to the collection of receivables, payment of
prepaid items and collection of refundable income taxes. We also had a change
between years of $5.2 million from increased accounts payable. These items
increasing cash flow from operations were offset by a decrease in net income of
$13.1 million and a $7.1 million decrease in the effect of non-cash items
between the periods. We anticipate significantly increased cash flow from
operations in 2003 as a result of expected higher oil and gas prices in 2003 and
increased production attributable to our property acquisitions in late 2002 and
early 2003.
St. Mary's net cash provided by operating activities increased $35.2
million or 40% to $127.5 million in 2001 compared to $92.3 million in 2000. The
increase reflects a change between years of $22.5 million from the collection of
receivables and a change between years of $15.4 million from increased accounts
payable.
Net cash used in investing activities increased $21.8 million in 2002
to $180.9 million compared to $159.1 million in 2001. Total 2002 capital
expenditures for cash, including acquisitions of oil and gas properties,
increased $14.2 million or 8% to $184.7 million in 2002 compared to $170.5
million in 2001 due to an increase in acquisition activity in 2002 offset by our
planned decrease in cash expended on drilling activities.
Net cash used in investing activities increased $46.2 million in 2001
to $159.1 million compared to $112.9 million in 2000. Total 2001 capital
expenditures for cash, including acquisitions of oil and gas properties,
increased $53.2 million or 45% to $170.5 million in 2001 compared to $117.3
million in 2000 due to an increase in drilling activity in 2001 offset by a
decrease in cash expended for oil and gas property purchases.
Net cash provided by financing activities increased $17.2 million to
$46.3 million in 2002 compared to $29.1 million in 2001. This increase reflects
our March 2002 private placement of $100.0 million of 5.75% senior convertible
notes due 2022. A portion of the net proceeds of $96.7 million was used to repay
the balance due on our credit facility at that time. By year end we had borrowed
$14.0 million on our credit facility, and subsequent to year end we borrowed an
additional $56.0 million to finance acquisitions that closed in early 2003. We
did not repurchase any of our common stock during 2002.
Net cash provided by financing activities increased $16.1 million to
$29.1 million in 2001 compared to $13.0 million in 2000. The increase is due to
a net $42.0 million increase in long-term debt during 2001 compared to a $9.0
million increase in 2000 offset by a $4.4 million decrease in proceeds received
from the sale of common stock related to our stock option programs. We also
repurchased $12.9 million of our common stock during 2001. We used our credit
facility to fund the acquisition of properties from Choctaw and finance current
operations.
St. Mary had $11.2 million in cash and cash equivalents and had working
capital of $2.1 million as of December 31, 2002 compared to $4.1 million in cash
and cash equivalents and working capital of $34.2 million as of December 31,
2001.
Pension Benefits. Substantially all of our employees who meet age and
service requirements participate in a non-contributory pension plan. At December
31, 2002, we have recorded a $1.2 million pre-tax loss in accumulated other
comprehensive income related to this plan. We believe this obligation will be
funded from future cash flow from operating activities. For purposes of
calculating our obligation under the plan, we have used an expected return on
47
plan assets of 8%. We think this rate of return is appropriate over the
long-term given the 60% equity and 40% debt securities mix of investment for
plan assets and the historical rate of return provided by equity and debt
securities since the 1920s. Our actual rate of return for 2002 was a negative
10.0% and was a negative 0.7% for 2001. The difference in investment income
using our projected rate of return compared to our actual rates of return for
the past two years was not material and will not have a material effect on
statements of operation or cash flow from operating activities in future years.
For the 2002 plan year, a 0.75% decrease in the discount rate combined
with a 0.25% decrease in the rate of future compensation increases caused a
$195,000 increase in the projected benefit obligation of the plan. We do not
believe this change was material and project that it will not have a material
effect on the results of operations or on cash flow from operating activities in
future periods.
We also have a supplemental non-contributory pension plan that covers
certain management employees. There are no plan assets for this plan. For the
2002 plan year, a 0.75% decrease in the discount rate combined with a 0.25%
decrease in the rate of future compensation increases caused a $91,000 increase
in the projected benefit obligation for this plan. This plan's accumulated
benefit obligation was $853,000 at December 31, 2002, and was $685,000 at
December 31, 2001. We believe this obligation will be funded from future cash
flow from operating activities.
Senior Convertible Notes. In March 2002 we issued in a private
placement a total of $100.0 million of our 5.75% senior convertible notes due
2022 with a 0.5% contingent interest provision. The contingent interest
provision did not apply to our first interest payment on September 15, 2002, but
it will apply to the payment due on March 15, 2003. Interest payments on the
notes will be made on March 15 and September 15 in subsequent years. We received
net proceeds of $96.7 million after deducting the initial purchasers' discount
and offering expenses paid by us. The notes are general unsecured obligations
and rank on a parity in right of payment with all our existing and future senior
indebtedness and other general unsecured obligations, and are senior in right of
payment with all our future subordinated indebtedness. The notes are convertible
into our common stock at a conversion price of $26.00 per share, subject to
adjustment. We can redeem the notes with cash in whole or in part at a
repurchase price of 100% of the principal amount plus accrued and unpaid
interest beginning on March 20, 2007. The note holders have the option of
requiring us to repurchase the notes for cash at 100% of the principal amount
plus accrued and unpaid interest upon (1) a change in control of St. Mary or (2)
on March 20, 2007, March 15, 2012 and March 15, 2017. If the note holders
require repurchase on March 20, 2007, we may pay the repurchase price with cash,
shares of our common stock valued at a discount to the market price at the time
of repurchase or any combination of cash and our discounted common stock. We are
not restricted from paying dividends, incurring debt, or issuing or repurchasing
our securities under the indenture for the notes. There are no financial
covenants in the indenture. We used a portion of the net proceeds from the notes
to repay our credit facility balance and used the remaining net proceeds to fund
a portion of our 2002 capital expenditures. On March 25, 2002, we entered into a
five-year fixed-rate to floating-rate interest rate swap on $50.0 million of the
notes. The floating rate was determined as LIBOR plus 0.36%. We elected to
terminate this swap on December 3, 2002, and received proceeds of $4.0 million.
Credit Facility. At December 31, 2002, we had an unsecured long-term
revolving credit facility with a bank group consisting of Bank of America,
Comerica Bank-Texas and Wells Fargo Bank West. Under this facility, the maximum
loan amount was $200.0 million. The amount actually available depended upon a
borrowing base that the lenders periodically redetermined based on the value of
48
our oil and gas properties and other assets. As of December 31, 2002, the stated
total possible borrowing base was $160.0 million. However, since we pay
commitment fees based on the unused portion of the borrowing base we limited the
borrowing base that we accepted to correspond with our actual funding
requirements. The accepted borrowing base was $40.0 million at December 31,
2002. The facility had a maturity date of December 31, 2006, and included a
revolving period that matured on June 30, 2003, at which time all outstanding
borrowings would convert to a term loan payable in quarterly installments
through the facility maturity date. We were required to comply with certain
covenants including maintenance of stockholders' equity at a specified level, as
well as restrictions on additional indebtedness, sales of oil and gas
properties, activities outside our ordinary course of business and certain
merger transactions. Borrowings under the facility were secured by a pledge of
collateral in favor of the banks and guarantees by subsidiaries. Such collateral
consisted of security interests in the oil and gas properties of St. Mary and
its subsidiaries.
As of December 31, 2002 and 2001, $14.0 million and $64.0 million,
respectively, was outstanding under this credit agreement. These outstanding
balances accrued interest at rates determined by St. Mary's debt to total
capitalization ratio at our option of either:
Debt to Capitalization Ratio <30% =>30%<40% =>40%<50% >50%
---------------------------------------------------------------------------------------
Option (1)
LIBOR plus 1.000% 1.250% 1.375% 1.625%
Option (2) - The higher of:
Federal funds rate plus 0.50% 0.50% 0.50% 0.50%
Prime rate plus - - - 0.25%
At December 31, 2002 our debt to capitalization ratio as defined under
the credit agreement was 27.5%.
On January 29, 2003, St. Mary entered into a new $300.0 million credit
facility with Wachovia Bank as Administrative Agent and eight other
participating banks. This new credit facility replaced our previous $200.0
million credit facility. The initial calculated borrowing base included
properties we acquired from Flying J Oil & Gas Inc. and Big West Oil &
Gas Inc. The borrowing base is currently at $215.0 million and will increase to
$250.0 million when we provide the remaining collateral. St. Mary has accepted
an initial commitment of $150.0 million under this facility. The credit
agreement has a maturity date of January 27, 2006. We are required to comply
with certain covenants that include a current ratio of 1.0 to 1.0, maintenance
of ERISA compliance, and restrictions on additional indebtedness, sales of oil
and gas properties, activities outside our ordinary course of business and
certain merger transactions. Interest is accrued based on the borrowing base
utilization percentage as LIBOR or the Alternate Base Rate (Prime), plus the
following:
Borrowing Base
Utilization Percentage <50% =>50%<75% =>75%<90% =>90% - - -
- ----------------------------------------------------------------------------------------
Eurodollar Loans 1.250% 1.500% 1.750% 2.000%
ABR Loans 0.000% 0.250% 0.500% 0.750%
Commitment Fee Rate 0.300% 0.375% 0.375% 0.500%
49
On the date we entered into this credit facility our loan balance
accrued interest at LIBOR plus 1.25%.
Schedule of Contractual Obligations. The following table summarizes our
future estimated principal payments and minimum lease payments for the periods
specified (in millions):
Long-Term Operating Total Cash
Debt Leases Obligation
------------------------------------
Less than 1 year $ - $ 1.6 $ 1.6
1-3 years - 2.5 2.5
4-5 years 14.0 1.9 15.9
After 5 years 100.0 3.7 103.7
------------------------------------
Total $ 114.0 $ 9.7 $ 123.7
====================================
In the next three years, we have two leases of office space for our
regional offices that will expire. A third lease for office space will expire in
year 4. Estimated costs to replace these leases are not included in the table
above. For purposes of the table we assume that the holders of our senior
convertible notes will not exercise the conversion feature.
Common Stock. At the annual stockholders meeting on May 23, 2001 the
stockholders of St. Mary voted to increase the amount of authorized common
shares to 100,000,000.
In August 1998 our board of directors authorized a stock repurchase
program whereby we may purchase from time-to-time, in open market transactions
or negotiated sales, up to two million of our common shares. Through March 12,
2003 we had repurchased a total of 1,009,900 shares of St. Mary common stock
under the program for $16.2 million at a weighted average price of $15.86 per
share, net of put option sale premiums received. We anticipate that additional
purchases of shares may occur as market conditions warrant. Any future purchases
will be funded with internal cash flow and borrowings under our credit facility.
On January 29, 2003, we issued a total of 3,380,818 restricted shares
of our common stock valued at $71.6 million to Flying J Oil & Gas Inc. and
Big West Oil & Gas Inc. for the acquisition of oil and gas properties, and
we made a non-recourse loan to Flying J and Big West in the amount of $71.6
million at LIBOR plus 2% for up to a 39-month period. The loan is secured by a
pledge of the 3,380,818 shares and during the 39-month loan period Flying J and
Big West can elect to sell these shares to St. Mary for $71.6 million plus
accrued interest on the loan for up to the first 30 months, and we can elect to
repurchase the shares for $97.4 million with the proceeds applied to repayment
of the loan. The shares are subject to contractual restrictions on transfer for
a period of two years. Flying J and Big West cannot increase their ownership
percentage in St. Mary for a period of 30 months.
Capital and Exploration Expenditures. Expenditures for exploration and
development of oil and gas properties and acquisitions are the primary use of
our capital resources. The following table sets forth certain information
regarding the costs incurred by us in our oil and gas activities during the
periods indicated.
50
Capital and Exploration Expenditures
------------------------------------
For the Years Ended
December 31,
------------
2002 2001 2000
---- ---- ----
(In thousands)
Development $ 74,376 $ 98,617 $ 48,996
Exploration 22,778 24,506 17,012
Acquisitions:
Proved 87,706 41,188 53,482
Unproved 8,128 18,552 5,694
-------- -------- ---------
Total $192,988 $182,863 $ 125,184
======== ======== =========
We continuously evaluate opportunities in the marketplace for oil and
gas properties and, accordingly, may be a buyer or a seller of properties at
various times. We will continue to emphasize smaller niche acquisitions
utilizing our technical expertise, financial flexibility and structuring
experience. In addition, we are also actively seeking larger acquisitions of
assets or companies that would afford opportunities to expand our existing core
areas, to acquire additional geoscientists and/or engineers, or gain a
significant acreage and production foothold in a new basin.
St. Mary's total costs incurred for capital and exploration activities
in 2002 increased $10.1 million or 6% compared to 2001. We spent $112.8 million
in 2002 for unproved property acquisitions and domestic exploration and
development compared to $141.7 million for the comparable period in 2001. This
decrease was a result of planned decreases in the drilling activity budget and a
$2.9 million decrease in unproved property acquisition activity. Well testing
continues on our two coalbed methane pilot programs located in the Hanging Woman
Basin. All pilot wells in the Antelope Draw field are currently shut-in while we
evaluate the data from dewatering. Prior to shut-in, production from the
Anderson coal averaged 250 Mcf/day. We are continuing to produce and test wells
at the Nest Prong field project. During the year, one of our partners exercised
their right to participate in a leasehold acquisition bringing our total to
145,000 gross acres in the project. We are subject to an environmental public
interest group lawsuit on 48,000 of these acres. See "Legal Proceedings" for a
discussion of this lawsuit.
In November 2001 we purchased oil and gas properties from Choctaw II
Oil & Gas, Ltd. for $40.5 million in cash. We used a portion of our credit
facility for this acquisition. The properties are primarily located in the
Williston Basin of Montana and North Dakota and in the Green River Basin of
Wyoming.
In December 2002 we purchased oil and gas properties from Burlington
Resources Oil & Gas Company LP for $69.5 million in cash. The properties are
located in the Williston Basin of Montana and North Dakota with extensive
overlap of ownership interest. Most of the properties will be operated by our
Nance subsidiary and are very concentrated in a manageable well count with high
ownership percentages in high quality long-lived properties. We financed this
acquisition using cash on hand and a portion of our bank credit facility. At the
time of acquisition, these properties were producing an estimated 3,100 Bbls of
oil per day and 3,300 Mcf of natural gas per day.
51
Capital Expenditure Budget. We anticipate spending approximately $225
million for capital and exploration expenditures in 2003 with $90 million
allocated for acquisitions of producing properties. Anticipated ongoing
exploration and development expenditures for each of our core areas is as
follows (in millions):
o Mid-Continent region $ 45
o Williston Basin and Rockies region $ 33
o ArkLaTex region $ 19
o Gulf Coast and Gulf of Mexico region $ 17
o Permian Basin $ 12
o Other $ 9
-----
Total $135
=====
We believe that the amount not funded from our internally generated
cash flow in 2003 can be funded from our existing cash and our bank credit
facility. The amount and allocation of future capital and exploration
expenditures will depend upon a number of factors including the number and size
of available acquisition opportunities and our ability to assimilate these
acquisitions. Also, the impact of oil and gas prices on investment
opportunities, the availability of capital and borrowing capability and the
success of our development and exploratory activity could lead to funding
requirements for further development. If additional development or attractive
acquisition opportunities arise, we may consider other forms of financing,
including the public offering or private placement of equity or debt securities.
In January 2003 we utilized our common stock, cash on hand and a
portion of our new credit facility to acquire $74.0 million of oil and gas
properties. On January 29, 2003, we closed a $71.6 million acquisition with
restricted shares of our common stock that included 66.9 BCFE or proved reserves
for $68.8 million of oil and gas properties and $2.8 million of cash for net
purchase price adjustments from Flying J Oil & Gas Inc. and Big West Oil
& Gas Inc. See the Common Stock section above for additional details. Half
of the value of the properties acquired is located in the Williston Basin. The
remaining value is split between the Powder River, Wind River and Green River
Basins of Wyoming and represents a significant increase of our presence in these
areas.
We seek to protect our rate of return on acquisitions of producing
properties by hedging cash flow when the economic criteria from our evaluation
and pricing model indicate it would be appropriate. Management's strategy is to
hedge cash flows from investments currently requiring a gas price in excess of
$3.25 per Mcf and an oil price in excess of $22.50 per Bbl in order to meet
minimum rate-of-return criteria. Management reviews these hedging parameters on
a quarterly basis. We anticipate this strategy will result in the hedging of
future cash flows from acquisitions. We generally limit our aggregate hedge
position to no more than 50% of total production but will hedge larger
percentages of total production in certain circumstances. We seek to minimize
basis risk and index the majority of oil hedges to NYMEX prices and the majority
of gas hedges to various regional index prices associated with pipelines in
proximity to our areas of gas production. Our cash flow hedging instruments
generally qualify for cash flow hedge accounting under SFAS No. 133. Our policy
requires that we diversify our hedge positions with various counterparties and
requires that such counterparties have clear indications of current financial
strength. Including hedges entered into since December 31, 2002 we have the
following contracts in place:
52
Swaps
-----
Average Quantity Average Fixed
Product Volumes/month Type Contract Price Duration
---------------------------------------------------------------------------------------------
Natural Gas 1,599,000 MMBtu $4.35 01/03 - 12/03
Natural Gas 844,000 MMBtu $4.04 01/04 - 12/04
Oil 206,200 Bbls $25.94 01/03 - 12/03
Oil 144,500 Bbls $23.71 01/04 - 12/04
Collars
Average Floor Ceiling
Product Volumes/month Price Price Duration
---------------------------------------------------------------------------------------------
Natural Gas 152,000 MMbtu $2.50 $5.96 02/03 - 12/03
On February 4, 2002, we entered into an agreement to monetize our
unrealized hedge gain receivable due from Enron for $1.1 million. This amount
was included in other comprehensive income at December 31, 2001, and was
recorded as a hedge gain in the first quarter of 2002. Hedge gains and losses
are reported in oil and gas production revenues in our consolidated statements
of operations. Amortization of $1.7 million of other comprehensive income
related to our commodity positions with Enron is also recorded in hedge gain. We
will record amortization of the remaining $49,000 of other comprehensive income
in hedge loss in 2003 for these contracts. Derivative gain in the consolidated
statements of operations includes $31,000 of net loss from oil and gas hedge
ineffectiveness.
Other Derivatives. Our senior convertible notes contain a provision for
payment of contingent interest if certain conditions are met. Under SFAS No. 133
this provision is considered an embedded equity-related derivative that is not
clearly and closely related to the fair value of an equity interest and
therefore must be separated and accounted for as a derivative instrument. The
value of the derivative at issuance was $474,000. This amount was recorded as a
decrease to the convertible notes payable in the consolidated balance sheets. Of
this amount, $75,000 was amortized through interest expense in 2002. Derivative
gain in the consolidated statements of operations includes $341,000 of net loss
from mark-to-market adjustments for this derivative.
Our fixed-rate to floating-rate interest rate swap on $50.0
million of senior convertible notes did not qualify for fair value hedge
treatment under SFAS No. 133. We entered into this contract in March 2002 and
closed it out in December 2002. Derivative gain in the consolidated statements
of operations includes $3.6 million of net gain from the termination of this
contract.
Accounting Matters
In December 2002 the Financial Accounting Standards Board issued SFAS
No. 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure:
an amendment of FASB Statement No. 123." This statement amends SFAS No. 123,
"Accounting for Stock-Based Compensation", to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, this statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
53
stock-based employee compensation and the effect of the method used on reported
results. The statement is effective for financial statements for fiscal years
ending after December 15, 2002. We will continue to account for stock-based
compensation using the methods detailed in Accounting Principles Board Opinion
No.25, "Accounting for Stock Issued to Employees."
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This statement addresses financial
accounting and reporting for costs associated with exit or disposal activities
and requires recognition of a liability for a cost associated with an exit or
disposal activity when the liability is incurred, as opposed to when the entity
commits to an exit plan. SFAS No. 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. We do not have any
pending or planned exit or disposal activities and do not expect a material
effect on our financial position or results of operations from the adoption of
this statement.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 requires that gains and losses from extinguishment of
debt be evaluated under the provisions of Accounting Principles Board Opinion
No. 30 and be classified as ordinary items unless they are unusual or infrequent
or meet the specific criteria for treatment as an extraordinary item. This
statement is effective for fiscal years beginning after May 15, 2002. We do not
anticipate that the adoption of this statement will have a material effect on
our financial position or results of operations.
In July 2001 the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations." This statement requires companies to recognize
the fair value of an asset retirement liability in the financial statements by
capitalizing that cost as part of the cost of the related long-lived asset. The
asset retirement liability should then be allocated to expense by using a
systematic and rational method. The statement is effective January 1, 2003. We
have not determined the impact of adoption of this statement.
Effects of Inflation and Changing Prices
Within the United States in 2002 and 2001 general cost inflation had an
effect on St. Mary as reflected in increased drilling costs and lease operating
costs. We cannot predict the future extent of any such effect.
St. Mary's results of operations and cash flows are affected by
material changes in oil and gas prices. Oil and gas prices are strongly impacted
by North American influences on natural gas and global influences on oil in
relation to supply and demand for petroleum products. Oil and gas prices are
further impacted by the quality of the oil and gas to be sold and the location
of our producing properties in relation to markets for our products. Oil and gas
price increases or decreases have a corresponding effect on our revenues from
oil and gas sales. Oil and gas prices also affect the prices charged for
drilling and related services. As oil and gas prices increase, revenues increase
and there is usually a corresponding increase in our costs of drilling and
related services. Also as oil and gas prices increase, the cost of acquiring
producing properties increases, which could limit the number and accessibility
of quality properties on the market.
Material changes in oil and gas prices affect the current and future
value of our estimated proved reserves and our borrowing capability, which is
largely based on the value of such proved reserves. More stable natural gas and
oil prices characterized most of 2002. Rig costs and operating costs decreased
slightly. At the end of the year, in spite of a weakened economy, less than
54
normal gas in storage, cold weather, a continuing petroleum industry strike in
Venezuela and the possibility of escalating conflict in the Middle East are
causing both oil and natural gas prices to increase. However, higher oil and gas
prices have not caused rig utilization to increase to the extent many expected.
In the near-term we do not expect competition for these limited resources to
increase, but continued high prices will encourage development activity and
could result in increases in the cost of both materials and personnel and
corresponding effects on the cost to explore for, drill for and produce oil and
gas. We continue to have good relationships with our vendors due to our
reputation for timely payment of invoices, a positive by-product of our strong
balance sheet.
Environmental
St. Mary's compliance with applicable environmental regulations has not
resulted in any significant capital expenditures or materially adverse effects
to our liquidity or results of operations. We believe we are in substantial
compliance with environmental regulations and foresee that no material
expenditures will be incurred in the future. However, we are unable to predict
the impact that future compliance with regulations may have on future capital
expenditures, liquidity and results of operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We hold derivative contracts and financial instruments that have cash
flow and net income exposure to changes in commodity prices or interest rates.
Financial and commodity-based derivative contracts are used to limit the risks
inherent in some crude oil and natural gas price changes that have an effect on
us.
Our board of directors has adopted a policy regarding the use of
derivative instruments. This policy requires every derivative used by St. Mary
to relate to underlying offsetting positions, anticipated transactions or firm
commitments. It prohibits the use of speculative, highly complex or leveraged
derivatives. Under the policy, the Chief Executive Officer and Vice President of
Finance must review and approve all risk management programs that use
derivatives. The board of directors and the audit committee periodically review
these programs.
Commodity Price Risk. We use various hedging arrangements to manage our
exposure to price risk from natural gas and crude oil production. These hedging
arrangements have the effect of locking in for specified periods, at
predetermined prices or ranges of prices, the prices we will receive for the
volumes to which the hedge relates. Consequently, while these hedging
arrangements are structured to reduce our exposure to decreases in prices
associated with the hedged commodity, they also limit the benefit we might
otherwise receive from any price increases associated with the hedged commodity.
The derivative gain or loss effectively offsets the loss or gain on the
underlying commodity exposures that have been hedged. The fair value of the
swaps are estimated based on quoted market prices of comparable contracts and
approximate the net gains or losses that would have been realized if the
contracts had been closed out at year-end. The fair values of the futures are
based on quoted market prices obtained from the New York Mercantile Exchange
adjusted fpr basis differentials.
For contracts in place on December 31, 2002, a hypothetical $0.10
change in the future NYMEX strip prices applied to a notional amount of 12.4
million MMBtu covered by natural gas swaps would cause a change in the gain or
(loss) from these contracts of $853,000 in 2003 and $321,000 in 2004. A
hypothetical $1.00 change in future NYMEX oil prices applied to a notional
amount of 2.5 MMBbls covered by crude oil swaps would cause a change in the gain
55
or (loss) from these contracts of $1.7 million in 2003 and $654,000 in 2004.
These hypothetical changes were discounted to present value using a 7.5%
discount rate since the latest expected maturity date of some of the swaps and
futures contracts is greater than one year from the reporting date.
Interest Rate Risk. Market risk is estimated as the potential change in
fair value resulting from an immediate hypothetical one-percentage point
parallel shift in the yield curve. The sensitivity analysis presents the
hypothetical change in fair value of those financial instruments we held at
December 31, 2002, that are sensitive to changes in interest rates. For
fixed-rate debt, interest rate changes affect the fair market value but do not
impact results of operations or cash flows. Conversely for floating-rate debt,
interest rate changes generally do not affect the fair market value but do
impact future results of operations and cash flows, assuming other factors are
held constant. The carrying amount of our floating rate debt approximates its
fair value. At December 31, 2002, we had floating-rate debt of $14.0 million and
had $100.0 million of fixed-rate debt. Assuming constant debt levels, the cash
flow impact for the next year resulting from a one-percentage point change in
interest rates would be approximately $140,000 before taxes. The results of
operations impact might be less than this amount as a direct effect of the
capitalization of interest to wells drilled in the next year. In prior years
when our debt amount was at a reduced level we capitalized a large portion of
our interest expense. Since we cannot predict the exact amount that would be
capitalized, we cannot predict the exact effect that a one-percentage point
shift would have on the results of operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements that constitute Item 8 follow the
text of this report. An index to the Consolidated Financial Statements and
Schedules appears in Item 14(a) of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
As previously reported in our current reports on Form 8-K filed with
the SEC on May 30, 2002 and June 5, 2002, on May 23, 2002 we dismissed Arthur
Andersen LLP as our independent accountants and on June 3, 2002 we engaged
Deloitte & Touche LLP as our new independent accountants. The St. Mary audit
committee and board of directors approved this change in accountants.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item concerning St. Mar's directors is
incorporated by reference to the information provided under the captions
"Election of Directors" and "Nominees for Election of Directors" in St. Mary's
definitive proxy statement for the 2003 annual meeting of stockholders to be
filed within 120 days from December 31, 2002. The information required by this
Item concerning St. Mary's executive officers is incorporated by reference to
the information provided in Part I-Item 4A-Executive Officers of the Registrant,
included in this Form 10-K.
The information required by this Item concerning compliance with
Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
reference to the information provided under the caption "Section 16(a)
Beneficial Ownership Reporting Compliance" in St. Mary's definitive proxy
56
statement for the 2003 annual meeting of stockholders to be filed within 120
days from December 31, 2002.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to
the information provided under the captions, "Director Compensation," "Executive
Compensation," "Report of the Compensation Committee on Executive Compensation,"
"Retirement Plans," "Performance Graph," and "Employee Agreements and
Termination of Employment and Change-in-Control Arrangements" in St. Mary's
definitive proxy statement for the 2003 annual meeting of stockholders to be
filed within 120 days from December 31, 2002.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item concerning security ownership of
certain beneficial owners and management is incorporated by reference to the
information provided under the caption "Security Ownership of Certain Beneficial
Owners and Management" in St. Mary's definitive proxy statement for the 2003
annual meeting of stockholders to be filed within 120 days from December 31,
2002.
The information required by this Item concerning securities authorized
for issuance under equity compensation plans is incorporated by reference to the
information provided under the caption "Equity Compensation Plans" in Part II -
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters,
included in this form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference to
the information provided under the caption "Certain Relationships and Related
Transactions" in St. Mary's definitive proxy statement for the 2003 annual
meeting of stockholders to be filed within 120 days from December 31, 2002.
ITEM 14. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are
designed for the purposes of ensuring that information required to be disclosed
in our SEC reports is recorded, processed, summarized and reported within the
time periods specified in the SEC's rules and forms, and that such information
is accumulated and communicated to our management, including the Chief Executive
Officer and the Vice-President - Finance, as appropriate to allow timely
decisions regarding required disclosure.
Within the 90-day period prior to the filing of this report, we carried
out an evaluation, under the supervision and with the participation of our
management, including the Chief Executive Officer and the Vice-President -
Finance, of the effectiveness of the design and operation of our disclosure
controls and procedures. Based upon that evaluation, the Chief Executive Officer
and the Vice-President - Finance concluded that our disclosure controls and
procedures are effective for the purposes discussed above. There have been no
significant changes in our internal controls or in other factors that could
significantly affect these controls subsequent to the date of the evaluation.
57
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
Reports of Independent Auditors....................................F-1
Reports of Independent Public Accountants..........................F-2
Consolidated Balance Sheets........................................F-3
Consolidated Statements of Operations..............................F-4
Consolidated Statements of Stockholders' Equity and
Comprehensive Income........................................... F-5
Consolidated Statements of Cash Flows..............................F-6
Notes to Consolidated Financial Statements.........................F-8
All other schedules are omitted because the required information is not
applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.
(b) Reports on Form 8-K.
St. Mary Land & Exploration Company filed the following current
reports on Form 8-K during the quarter ended December 31, 2002:
On October 3, 2002, we filed a current report on Form 8-K reporting
under Item 5 that we had signed a Purchase and Sale Agreement to acquire oil and
gas properties from Burlington Resources Oil & Gas Company LP.
On November 7, 2002, we filed a current report on Form 8-K reporting
under Item 9 that we had issued a press release announcing our earnings and
financial highlights for the third quarter of 2002.
On November 20, 2002, we filed a current report on Form 8-K reporting
under Item 9 that in connection with the filing of the Form 10-Q on November 13,
2002, the Chief Executive Officer and the Vice-President - Finance of the
registrant each signed a Certification pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002.
On December 12, 2002, we filed a current report on Form 8-K reporting
under Item 2 that on December 3, 2002, we purchased oil and gas properties from
Burlington Resources Oil & Gas Company LP.
On December 16, 2002, we filed a current report on Form 8-K reporting
under Item 5 that we had issued a press release announcing an agreement to
acquire oil and gas properties from Flying J Oil & Gas and Big West Oil
& Gas.
(c) Exhibits. The following exhibits are filed with or incorporated by
reference into this report on Form 10-K:
58
Exhibit
Number Description
------- -----------
2.1 Agreement and Plan of Merger dated July 27, 1999 among St.
Mary Land & Exploration Company, St. Mary Acquisition
Corporation, King Ranch, Inc. and King Ranch Energy, Inc. as
amended by Amendment No. 1 and Amendment No. 2 to Agreement
and Plan of Merger dated November 8, 1999 (included as Annex A
to the joint proxy/consent statement and prospectus contained
in the registrant's Amendment No. 2 to Form S-4/A
(Registration No. 333-85537) filed on November 12, 1999 and
incorporated herein by reference)
2.2 Stock Exchange Agreement dated June 1, 1999 among St. Mary
Land & Exploration Company, Robert L. Nance, Penni W.
Nance, Amy Nance Cebull and Robert Scott Nance (filed as
Exhibit 10.27 to the registrant's Registration Statement on
Form S-4 (Registration No. 333-85537) filed on August 19, 1999
and incorporated herein by reference)
2.3 Stock Exchange Agreement dated June 1, 1999 among St. Mary
Land & Exploration Company, Robert L. Nance and Robert T.
Hanley (filed as Exhibit 10.28 to the registrant's
Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein by
reference)
2.4 Stock Exchange Agreement dated June 1, 1999 between St. Mary
Land & Exploration Company and Robert T. Hanley (filed as
Exhibit 10.29 to the registrant's Registration Statement on
Form S-4 (Registration No. 333-85537) filed on August 19, 1999
and incorporated herein by reference)
3.1 Restated Certificate of Incorporation of St. Mary Land &
Exploration Company as amended in May 2001 (filed as Exhibit
3.1 to the registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001 and incorporated herein by
reference)
3.2 Restated By-Laws of St. Mary Land & Exploration Company as
amended in July 2001 (filed as Exhibit 3.1 to the registrant's
Quarterly Report on Form 10-Q (File No. 0-20872) for the
quarter ended September 30, 2001 and incorporated herein by
reference)
4.1 St. Mary Land & Exploration Company Shareholder Rights
Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the
registrant's Quarterly Report on Form 10-Q/A (File No.
0-20872) for the quarter ended June 30, 1999 and incorporated
herein by reference)
4.2 First Amendment to Shareholders Rights Plan dated March 15,
2002 as adopted by the Board of Directors on July 19, 2001
(filed as Exhibit 4.2 to the registrant's Annual Report on
Form 10-K (File No. 0-20872) for the year ended December 31,
2001 and incorporated herein by reference)
10.1 Stock Option Plan (filed as Exhibit 10.3 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
10.2 Stock Appreciation Rights Plan (filed as Exhibit 10.4 to the
registrant's Registration Statement on Form S-1 (Registration
No. 33-53512) and incorporated herein by reference)
10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
10.4 Net Profits Interest Bonus Plan, As Amended on September 19,
1996 and July 24, 1997 and January 28, 1999 filed as Exhibit
10.3 to registrant's Quarterly Report on Form 10-Q (File No.
0-20872) for the quarter ended March 31, 1999 and incorporated
herein by reference)
59
Exhibit
Number Description
------- -----------
10.5 Summary Plan Description/Pension Plan dated December 30, 1994
(filed as Exhibit 10.35 to the registrant's Annual Report on
Form 10-K (File No. 0-20872) for the year ended December 31,
1994 and incorporated herein by reference)
10.6 Non-qualified Unfunded Supplemental Retirement Plan, as
amended (filed as Exhibit 10.8 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
10.7 Summary Plan Description 401(k) Profit Sharing Plan (filed as
Exhibit 10.34 to the registrant's Annual Report on Form 10-K
(File No. 0-20872) for the year ended December 31, 1994 and
incorporated herein by reference)
10.8 St. Mary Land & Exploration Company Stock Option Plan, As
Amended on March 29, 2001 (filed as Exhibit 99.1 to
registrant's Registration Statement on Form S-8 (Registration
No. 333-88780) and incorporated herein by reference)
10.9 St. Mary Land & Exploration Company Incentive Stock Option
Plan, As Amended on March 29, 2001 (filed as Exhibit 99.2 to
registrant's Registration Statement on Form S-8 (Registration
No. 333-88780) and incorporated herein by reference)
10.10 St. Mary Land & Exploration Company Employee Stock
Purchase Plan (filed as Exhibit 10.48 filed to the
registrant's Annual Report on Form 10-K (File No. 0-20872) for
the year ended December 31, 1997 and incorporated herein by
reference)
10.11 First Amendment to St. Mary Land & Exploration Company
Employee Stock Purchase Plan dated February 27, 2001 (filed as
Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
(file No. 0-20872) for the quarter ended June 30, 2001 and
incorporated herein by reference)
10.12 Form of Change of Control Severance Agreements (filed as
Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
(File No. 0-20872) for the quarter ended September 30, 2001
and incorporated herein by reference)
10.13 Employment Agreement between Registrant and Mark A.
Hellerstein (filed as Exhibit 10.15 to the registrant's
Registration Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
10.14 Credit Agreement dated June 30, 1998 (filed as Exhibit 10.52
to the registrant's Quarterly Report on Form 10-Q (File No.
0-20872) for the quarter ended June 30, 1998 and incorporated
herein by reference)
10.15 Second Amendment to Credit Agreement dated June 27, 2000
(filed as Exhibit 10.1 to the registrant's Quarterly Report on
Form 10-Q (File No. 0-20872) for the quarter ended June 30,
2000 and incorporated herein by reference)
10.16 Third Amendment to Credit Agreement dated April 30, 2001
(filed as Exhibit 10.2 to the registrant's Quarterly Report on
Form 10-Q (File No. 0-20872) for the quarter ended June 30,
2001 and incorporated herein by reference)
10.17 Loan and Stock Purchase Agreement dated June 25, 1999 among
Resource Capital Fund L.P., St. Mary Land & Exploration
Company and St. Mary Minerals Inc. (filed as Exhibit 10.30 to
the registrant's Registration Statement on Form S-4
(Registration No. 333-85537) filed on August 19, 1999 and
incorporated herein by reference)
10.18 Credit Agreement dated June 25, 1999 among Summo Minerals
Corporation, Summo USA Corporation, Resource Capital Fund L.P.
and St. Mary Minerals Inc. (filed as Exhibit 10.31 to the
registrant's Registration Statement on Form S-4 (Registration
60
Exhibit
Number Description
------- -----------
No. 333-85537) filed on August 19, 1999 and incorporated
herein by reference)
10.19 Replacement Promissory Note dated June 25, 1999 payable to St.
Mary Minerals Inc. in the amount of $1,400,000 (filed as
Exhibit 10.32 to the registrant's Registration Statement on
Form S-4 (Registration No. 333-85537) filed on August 19, 1999
and incorporated herein by reference)
10.20 Pledge and Security Agreement dated June 25, 1999 among Summo
Minerals Corporation, Resource Capital Fund L.P., and St. Mary
Minerals Inc. (filed as Exhibit 10.33 to the registrant's
Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein by
reference)
10.21 Pledge and Security Agreement dated June 25, 1999 among Summo
USA Corporation, Resource Capital Fund L.P., and St. Mary
Minerals Inc. (filed as Exhibit 10.34 to the registrant's
Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein by
reference)
10.22 Warrant Agreement dated June 25, 1999 among Summo Minerals
Corporation, Resource Capital Fund L.P. and St. Mary Minerals
Inc. (filed as Exhibit 10.35 to the registrant's Registration
Statement on Form S-4 (Registration No. 333-85537) filed on
August 19, 1999 and incorporated herein by reference)
10.23 Agreement of Sale and Purchase dated October 16, 2000,
effective as of September 1, 2000, between JN Exploration and
Production Limited Partnership, Colt Resources Corporation,
Princeps Partners, Inc., and The William G. Helis Company, LLC
(collectively, "JN et al") and St. Mary Land & Exploration
Company (filed as Exhibit 10.1 to the registrant's Current
Report on Form 8-K (File No. 0-20872) dated January 5, 2001
and incorporated herein by reference)
10.24 Purchase and Sale Agreement dated September 28, 2001,
effective as of September 1, 2001; between Choctaw II Oil
& Gas, LTD and Nance Petroleum Corporation (filed as
Exhibit 10.1 to the registrant's Current Report on Form 8-K
(File No. 0-20872) dated December 10, 2001 and incorporated
herein by reference)
10.25 Registration Rights Agreement between St. Mary Land &
Exploration Company and Bear, Stearns & Co. Inc., et al
dated March 13, 2002 (filed as Exhibit 10.25 to the
registrant's Annual Report on Form 10-K (File No. 0-20872) for
the year ended December 31, 2001 and incorporated herein by
reference)
10.26 St. Mary Land & Exploration Company 5.75% Senior
Convertible Notes Due 2002 Indenture dated March 13, 2002
(filed as Exhibit 10.26 to the registrant's Annual Report on
Form 10-K (File No. 0-20872) for the year ended December 31,
2001 and incorporated herein by reference)
10.27 First Amendment to Credit Agreement dated December 22, 1998
(filed as Exhibit 10.27 to the registrant's Annual Report on
Form 10-K (File No. 0-20872) for the year ended December 31,
2001 and incorporated herein by reference)
10.28 Fourth Amendment to Credit Agreement dated March 4, 2002
(filed as Exhibit 10.28 to the registrant's Annual Report on
Form 10-K (File No. 0-20872) for the year ended December 31,
2001 and incorporated herein by reference)
10.29 Purchase and Sale Agreement dated October 1, 2002, effective
as of July 1, 2002; between Burlington Resources Oil & Gas
Company LP and The Louisiana Land and Exploration Company and
Nance Petroleum Corporation (filed as Exhibit 10.1 to the
61
Exhibit
Number Description
------- -----------
registrant's Current Report on Form 8-K (File No. 001-31539)
filed on December 12, 2002 and incorporated herein by
reference )
10.30 Purchase and Sale Agreement dated as of December 13, 2002
among Flying J Oil & Gas Inc., Big West Oil & Gas
Inc., NPC Inc. and St. Mary Land & Exploration Company
(filed as Exhibit 10.1 to the registrant's Current Report on
Form 8-K (File No. 001-31539) filed on February 13, 2003 and
incorporated herein by reference)
10.31 Addendum dated January 29, 2003 to Purchase and Sale Agreement
dated December 13, 2002 (filed as Exhibit 10.2 to the
registrant's Current Report on Form 8-K (File No. 001-31539)
filed on February 13, 2003 and incorporated herein by
reference)
10.32 Nonrecourse Secured Promissory Note dated January 29, 2003 by
Flying J Oil & Gas Inc. and Big West Oil & Gas Inc.
(filed as Exhibit 10.3 to the registrant's Current Report on
Form 8-K (File No. 001-31539) filed on February 13, 2003 and
incorporated herein by reference)
10.33 Stock Pledge Agreement from Flying J Oil & Gas Inc. and
Big West Oil & Gas Inc. to St. Mary Land & Exploration
Company executed as of January 29, 2003 (filed as Exhibit 10.4
to the registrant's Current Report on Form 8-K (File No.
001-31539) filed on February 13, 2003 and incorporated herein
by reference)
10.34 Registration Rights Agreement dated as of January 29, 2003
among St. Mary Land & Exploration Company, Flying J Oil
& Gas Inc. and Big West Oil & Gas Inc. (filed as
Exhibit 10.5 to the registrant's Current Report on Form 8-K
(File No. 001-31539) filed on February 13, 2003 and
incorporated herein by reference)
10.35 Put and Call Option Agreement dated as of January 29, 2003
among St. Mary Land & Exploration Company, Flying J Oil
& Gas Inc. and Big West Oil & Gas Inc. (filed as
Exhibit 10.6 to the registrant's Current Report on Form 8-K
(File No. 001-31539) filed on February 13, 2003 and
incorporated herein by reference)
10.36 Standstill Agreement dated as of January 29, 2003 among St.
Mary Land & Exploration Company, Flying J Oil & Gas
Inc. and Big West Oil & Gas Inc. (filed as Exhibit 10.7 to
the registrant's Current Report on Form 8-K (File No.
001-31539) filed on February 13, 2003 and incorporated herein
by reference) 10.37 Share Transfer Restriction Agreement dated
as of January 29, 2003 among St. Mary Land & Exploration
Company, Flying J Oil & Gas Inc. and Big West Oil &
Gas Inc. (filed as Exhibit 10.8 to the registrant's Current
Report on Form 8-K (File No. 001-31539) filed on February 13,
2003 and incorporated herein by reference)
10.38 Indemnity Guarantee Agreement dated January 29, 2003 between
NPC Inc. and Flying J Inc. (filed as Exhibit 10.9 to the
registrant's Current Report on Form 8-K (File No. 001-31539)
filed on February 13, 2003 and incorporated herein by
reference)
10.39 Promissory Note dated July 21, 2000 and Letter Agreement dated
July 21, 2000 for $200,000 Relocation Loan to Robert T. Hanley
(filed as Exhibit 10.29 to the registrant's Annual Report on
Form 10-K/A No. 2 (File No. 0-20872) for the year ended
December 31, 2001 and incorporated herein by reference)
10.40 Security Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company, St. Mary Operating Company, St.
Mary Energy Company, Nance Petroleum Corporation, St. Mary
Minerals Inc., Parish Corporation, Four Winds Marketing LLC,
and Roswell LLC, in favor of Bank of America, N.A. (filed as
62
Exhibit
Number Description
------- -----------
Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q
(File No. 000-20872) for the quarter ended June 30, 2002 and
incorporated herein by reference)
10.41 Stock Pledge Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company in favor of Bank of America, N.A.
(filed as Exhibit 10.2 to the registrant's Quarterly Report on
Form 10-Q (File No. 000-20872) for the quarter ended June 30,
2002 and incorporated herein by reference)
10.42 LLC Pledge Agreement made as of May 1, 2002 by St. Mary Land
& Exploration Company in favor of Bank of America, N.A.
(filed as Exhibit 10.3 to the registrant's Quarterly Report on
Form 10-Q (File No. 000-20872) for the quarter ended June 30,
2002 and incorporated herein by reference)
10.43 Guaranty made as of May 1, 2002 by St. Mary Operating Company,
St. Mary Energy Company, Nance Petroleum Corporation, St. Mary
Minerals, Inc., Parish Corporation, Four Winds Marketing LLC
and Roswell LLC in favor of Bank of America, N.A. (filed as
Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q
(File No. 000-20872) for the quarter ended June 30, 2002 and
incorporated herein by reference)
10.44* Credit Agreement dated as of January 27, 2003 among St. Mary
Land & Exploration Company, Wachovia Bank, National
Association of Administrative Agent, and the Lenders party
thereto
10.45* Amendment to and Extension of Office Lease dated as of
December 14, 2001
12.1* Computation of Ratios of Earnings to Fixed Charges
16.1 Letter by Arthur Andersen LLP to the Securities and Exchange
Commission dated May 28, 2002 (filed as Exhibit 16.1 to the
registrant's Current Report on Form 8-K (File No. 000-20872)
filed on May 30, 2002 and incorporated herein by reference)
21.1* Subsidiaries of Registrant
23.1* Consent of Deloitte & Touche LLP
23.2* Information About Lack of Consent of Arthur Andersen LLP
23.3* Consent of Ryder Scott Company, L.P.
24.1* Power of Attorney (included in signature page hereof)
------------------------------
* Filed with this Form 10-K.
(d) Financial Statement Schedules. See Item 14(c) above.
63
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries
We have audited the accompanying consolidated balance sheet of St. Mary Land
& Exploration Company and subsidiaries as of December 31, 2002, and the
related consolidated statements of operations, stockholders' equity and
comprehensive income, and cash flows for the year then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The Company's consolidated financial statements for each of the years
in the two-year period ended December 31, 2001, were audited by other auditors
who have ceased operations. Those auditors expressed an unqualified opinion on
those consolidated financial statements in their report dated February 18, 2002,
which report included an explanatory paragraph for the change in method of
accounting for derivative instruments and hedging activities on January 1, 2001.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31,
2002, and the results of its operations and its cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States of America.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 19, 2003
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
St. Mary Land & Exploration Company and Subsidiaries:
We have audited the accompanying consolidated balance sheets of St. Mary
Land & Exploration Company (a Delaware corporation) and subsidiaries as
of December 31, 2001 and 2000, and the related consolidated statements of
operations, stockholders' equity and comprehensive income, and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of St.
Mary Land & Exploration Company and subsidiaries as of December 31, 2001
and 2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United
States.
As explained in Notes 1 and 10 to the consolidated financial statements,
the Company changed its method of accounting for derivative instruments
and hedging activities on January 1, 2001.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado,
February 18, 2002.
NOTE: This Report of Independent Public Accountants dated February 18, 2002 by
Arthur Andersen LLP is a copy of the report previously issued by Arthur Andersen
LLP and included with Arthur Andersen LLP's consent in the Annual Report on Form
10-K for the year ended December 31, 2001 filed with the SEC on March 19, 2002
and the Annual Report on Form 10-K/A for the year ended December 31, 2001 filed
with the SEC on March 25, 2002. Such report has not been reissued by Arthur
Andersen LLP for inclusion with this Annual Report on Form 10-K for the year
ended December 31, 2002. After reasonable efforts, St. Mary Land &
Exploration Company has been unable to obtain a reissued report of Arthur
Andersen LLP for inclusion with this Form 10-K, and in reliance on Rule 2-02(e)
of Regulation S-X promulgated by the SEC is including a copy of the previously
issued report with this Form 10-K.
F-2
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
-----------------------------
ASSETS 2002 2001
------------ ------------
Current assets:
Cash and cash equivalents $ 11,154 $ 4,116
Short-term investments 1,933 -
Accounts receivable 35,399 46,484
Prepaid expenses and other 6,510 2,337
Accrued derivative asset - 8,194
Refundable income taxes 1,031 11,061
Deferred income taxes 3,520 29
------------ ------------
Total current assets 59,547 72,221
------------ ------------
Property and equipment (successful efforts
method), at cost:
Proved oil and gas properties 683,752 518,912
Less accumulated depletion, depreciation
and amortization (263,436) (216,288)
Unproved oil and gas properties, net of
impairment allowance of $8,865 in 2002
and $8,908 in 2001 47,984 53,054
Other property and equipment, net of
accumulated depreciation of $3,586 in
2002 and $3,120 in 2001 3,639 3,252
------------ ------------
471,939 358,930
------------ ------------
------------ ------------
Other noncurrent assets 5,653 5,838
------------ ------------
------------ ------------
Total Assets $ 537,139 $ 436,989
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 48,790 $ 34,858
Accrued derivative liability 8,707 -
Deferred income taxes - 3,363
------------ ------------
Total current liabilities 57,497 38,221
------------ ------------
Noncurrent liabilities:
Long-term credit facility 14,000 64,000
Convertible notes 99,601 -
Deferred income taxes 60,156 47,685
Other noncurrent liabilities 5,727 255
------------ ------------
Total noncurrent liabilities 179,484 111,940
------------ ------------
Commitments and contingencies (Notes 1,6,7,8)
------------ ------------
Minority interest 645 711
------------ ------------
Stockholders' equity:
Common stock, $0.01 par value: authorized
-100,000,000 shares; issued - 28,983,110
shares in 2002 and 28,779,808 shares in
2001; outstanding - 27,973,210 shares in
2002 and 27,769,908 shares in 2001 290 288
Additional paid-in capital 140,688 137,384
Treasury stock - at cost: 1,009,900 shares
in 2002 and 2001 (16,210) (16,210)
Retained earnings 182,512 157,739
Accumulated other comprehensive income
(loss) (7,767) 6,916
------------ ------------
Total stockholders' equity 299,513 286,117
------------ ------------
Total Liabilities and Stockholders' Equity $ 537,139 $ 436,989
============ ============
The accompaying notes are an integral part
of these consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
----------------------------------------------
2002 2001 2000
------------ ------------ ------------
Operating revenues:
Oil and gas production $ 185,670 $ 203,973 $ 188,407
Gain (loss) on sale of proved properties (2,633) 367 3,404
Marketed gas revenue 8,399 420 -
Other oil and gas revenue 682 2,166 1,421
Derivative gain 3,188 - -
Other revenues 1,088 543 2,434
------------ ------------ ------------
Total operating revenues 196,394 207,469 195,666
------------ ------------ ------------
Operating expenses:
Oil and gas production 50,839 55,000 38,461
Depletion, depreciation and amortization 54,432 51,346 40,129
Exploration 19,501 19,518 9,633
Impairment of proved properties - 820 4,449
Abandonment and impairment of unproved
properties 2,446 3,865 1,841
General and administrative 14,299 11,762 11,166
Derivative loss - 1,573 -
Marketed gas system operating expense 7,982 420 -
Minority interest and other 1,206 1,253 1,437
------------ ------------ ------------
Total operating expenses 150,705 145,557 107,116
------------ ------------ ------------
Income from operations 45,689 61,912 88,550
Nonoperating income (expense):
Interest income 758 466 897
Interest expense (3,868) (90) (160)
------------ ------------ ------------
Income before income taxes 42,579 62,288 89,287
Income tax expense 15,019 21,829 33,667
------------ ------------ ------------
Net income $ 27,560 $ 40,459 $ 55,620
============ ============ ============
Basic net income per common share $ 0.99 $ 1.45 $ 2.00
Diluted net income per common share $ 0.97 $ 1.42 $ 1.97
Basic weighted average shares outstanding 27,856 27,973 27,781
Diluted weighted average shares outstanding 28,391 28,555 28,271
The accompaying notes are an integral part
of these consolidated financial statements.
F-4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock Other Total
------------------- Paid-in Retained ------------------- Comprehensive Stockholders'
Shares Amount Capital Earnings Shares Amount Income Equity
---------- -------- ---------- ---------- ---------- -------- ------------- -------------
Balances, December 31, 1999 27,893,910 $ 279 $ 123,974 $ 67,230 (365,600) $ 2,995) $ 284 $ 188,772
Comprehensive income:
Net Income - - - 55,620 - - - 55,620
Unrealized net loss on marketable
equity securities available for
sale - - - - - - (143) (143) ------------
Total comprehensive income 55,477 ------------
Cash dividends, $ 0.10 per share - - - (2,775) - - - (2,775)
Treasury stock purchases - - - - (30,000) (344) - (344)
Issuance for Employee Stock
Purchase Plan 32,296 - 311 - - - - 311
ESPP disqualified distribution - - 3 - - - - 3
Sale of common stock, including
income tax benefit of stock
option exercises 619,220 6 8,597 - - - - 8,603
Directors' stock compensation 8,400 1 88 - - - - 89
---------- -------- ---------- ---------- ---------- -------- ------------- -------------
Balances, December 31, 2000 28,553,826 $ 286 $ 132,973 $ 120,075 (395,600)$ (3,339) $ 141 $ 250,136
Comprehensive income:
Net Income - - - 40,459 - - - 40,459
Unrealized net loss on marketable
equity securities available for
sale - - - - - - (132) (132)
Adoption of SFAS No. 133 (28,587) (28,587)
Reclass to earnings - - - - - - 21,102 21,102
Change in derivative instrument
fair value - - - - - - 14,392 14,392 ------------
Total comprehensive income 47,234 ------------
Cash dividends, $ 0.10 per share - - - (2,795) - - - (2,795)
Treasury stock purchases - - - - (614,300) (12,871) - (12,871)
Issuance for Employee Stock
Purchase Plan 29,772 - 575 - - - - 575
Sale of common stock, including
income tax benefit of stock
option exercises 187,810 2 3,598 - - - - 3,600
Directors' stock compensation 8,400 - 238 - - - - 238
---------- -------- ---------- ---------- ---------- -------- ------------- -------------
Balances, December 31, 2001 28,779,808 $ 288 $ 137,384 $ 157,739 (1,009,900)$(16,210) $ 6,916 $ 286,117
========== ======== ========== ========== ========== ======== ============= =============
Comprehensive income:
Net Income - - - 27,560 - - - 27,560
Unrealized net loss on marketable
equity securities available for
sale - - - - - - (725) (725)
Reclass to earnings - - - - - - 1,447 1,447
Change in derivative instrument
fair value - - - - - - (14,644) (14,644)
Minimum pension liability
adjustment - - - - - - (761) (761) ------------
Total comprehensive income 12,877 ------------
Cash dividends, $ 0.10 per share - - - (2,787) - - - (2,787)
Issuance for Employee Stock
Purchase Plan 18,217 - 344 - - - - 344
ESPP disqualified distribution - - 21 - - - - 21
Sale of common stock, including
income tax benefit of stock
option exercises 177,085 2 2,743 - - - - 2,745
Accelerated vesing of retiring
director options - - 52 - - - - 52
Directors' stock compensation 8,000 - 144 - - - - 144
---------- -------- ---------- ---------- ---------- -------- ------------- -------------
Balances, December 31, 2002 28,983,110 $ 290 $ 140,688 $ 182,512 (1,009,900)$(16,210) $ (7,767) $ 299,513
========== ======== ========== ========== ========== ======== ============= =============
The accompaying notes are an integral part
of these consolidated financial statements.
F-5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
----------------------------------------------
2002 2001 2000
------------ ------------ ------------
Reconciliation of net income to net cash
provided by operating activities:
Net income $ 27,560 $ 40,459 $ 55,620
Adjustments to reconcile net income to net
cash provided by operating
activities:
(Gain) loss on sale of proved properties 2,633 (367) (3,404)
Gain on sale of KMOC stock (836) - (2,156)
Depletion, depreciation and amortization 54,432 51,346 40,129
Impairment of proved properties - 820 4,449
Abandonment and impairment of unproved
properties 2,446 3,865 1,841
Unrealized derivative (gain) loss 373 1,573 -
Deferred income taxes 14,633 23,726 21,348
Exploratory dry hole expense 7,677 9,028 789
Minority interest and other 40 (1,327) 1,260
------------ ------------ ------------
108,958 129,123 119,876
Changes in current assets and liabilities:
Accounts receivable 11,085 (629) (23,138)
Prepaid expenses and other (4,173) (664) 228
Refundable income taxes 10,030 (11,061) 26
Accounts payable and accrued expenses 15,992 10,752 (4,652)
Current deferred income taxes (183) (29) (73)
------------ ------------ ------------
Net cash provided by operating activities 141,709 127,492 92,267
------------ ------------ ------------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 1,624 4,771 3,573
Capital expenditures (97,257) (131,680) (65,241)
Acquisition of oil and gas properties (87,466) (39,124) (52,076)
Proceeds from distribution and sale of
KMOC stock 3,114 6,960 -
Deposits to short term investments
available-for-sale (13,523) - -
Receipts from short term investments
available-for-sale 12,538 - -
Other 39 (2) 876
------------ ------------ ------------
Net cash used in investing activities (180,931) (159,075) (112,868)
------------ ------------ ------------
Cash flows from financing activities:
Proceeds from long-term debt 37,400 147,050 45,050
Repayment of long-term debt (87,400) (105,050) (36,050)
Proceeds from convertible debt 96,657 - -
Proceeds from sale of common stock 2,390 2,746 7,143
Repurchase of common stock - (12,871) (344)
Dividends paid (2,787) (2,795) (2,775)
Other - - 1
------------ ------------ ------------
Net cash provided by financing activities 46,260 29,080 13,025
------------ ------------ ------------
Net change in cash and cash equivalents 7,038 (2,503) (7,576)
Cash and cash equivalents at beginning of
period 4,116 6,619 14,195
------------ ------------ ------------
Cash and cash equivalents at end of period $ 11,154 $ 4,116 $ 6,619
============ ============ ============
The accompaying notes are an integral part
of these consolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Supplemental schedule of additional cash flow information and noncash
activities:
For the Years Ended December 31,
----------------------------------------------
2002 2001 2000
------------ ------------ ------------
(in thousands)
Cash paid for interest, including amounts capitalized $ 2,498 $ 764 $ 916
Cash paid (received) for income taxes (550) 11,205 92
In June 2002 the Company issued 800 shares of common stock to a director and
recorded compensation expense of $14,763.
In January 2002 the Company issued 7,200 shares of common stock to its
directors and recorded compensation expense of $129,683.
In April 2002 the Company accepted 9,472,562 shares of common stock in
Constellation Copper Corporation ("Constellation", formerly known as Summo
Minerals Corporation) in lieu of cash payment for the relief of a $1,400,000
loan and $15,311 in interest due to the Company.
In January 2001 the Company issued 8,400 shares of common stock to its
directors and recorded compensation expense of $237,852.
In June 2000 the Company received equipment valued at $1,202,000 as
partial proceeds for property sold.
In January 2000 the Company issued 8,400 shares of common stock to its
directors and recorded compensation expense of $88,368.
The accompaying notes are an integral part
of these consolidated financial statements.
F-7
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002
1. Summary of Significant Accounting Policies
Description of Operations
St. Mary Land & Exploration Company ("St. Mary" or the "Company")
is an independent energy company engaged in the exploration, development,
acquisition and production of natural gas and crude oil. The Company's
operations are conducted entirely in the United States.
Basis of Presentation
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. Subsidiaries that are not
wholly-owned are accounted for using full consolidation with minority interest
or by the equity or cost method as appropriate. All significant intercompany
accounts and transactions have been eliminated.
Stock Splits
In July 2000 St. Mary's Board of Directors approved a two-for-one stock
split effected in the form of a stock dividend whereby one additional common
share of stock was distributed for each common share outstanding. The stock
split was distributed on September 5, 2000, to shareholders of record as of the
close of business on August 21, 2000. All share and per share amounts for all
periods presented herein have been restated to reflect this stock split.
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 due to the short-term
nature of these instruments.
Short-term Investments
The Company's short-term investments consist primarily of equity
securities and investment-grade marketable debt, which are classified as
available-for-sale or held-to-maturity. Securities which have been categorized
as available-for-sale are stated at fair value based on quoted market prices.
Debt securities that the Company has the ability and intent to hold to maturity
are accounted for as held-to-maturity securities and are carried at amortized
cost.
Concentration of Credit Risk
Substantially all of the Company's receivables are within the oil and
gas industry, primarily from purchasers of oil and gas and from joint interest
owners. Although diversified within many companies, collectability is dependent
upon the general economic conditions of the industry. The receivables are not
collateralized, and to date the Company has had minimal bad debts.
The Company has accounts with separate banks in Denver, Colorado;
Shreveport, Louisiana; Tulsa, Oklahoma; Lafayette, Louisiana; and Billings,
Montana. At December 31, 2002 and 2001, the Company had $4,881,000 and
F-8
$6,576,000 respectively, invested in money market funds, including margin
accounts consisting of corporate commercial paper, repurchase agreements and
U.S. Treasury obligations. The Company's policy is to invest in highly rated
instruments and to limit the amount of credit exposure at each individual
institution.
Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending determination of whether the well has found proved
reserves. If an exploratory well does not find proved reserves, the costs of
drilling the well are charged to expense. Exploratory dry hole costs are
included in cash flows from investing activities within the consolidated
statements of cash flows. The costs of development wells are capitalized whether
productive or nonproductive.
Geological and geophysical costs on exploratory prospects and the costs
of carrying and retaining unproved properties are expensed as incurred. An
impairment allowance is provided on a property-by-property basis when the
Company determines that the unproved property will not be developed. Depletion,
depreciation and amortization ("DD&A") of capitalized costs of proved oil
and gas properties is provided on a field-by-field basis using the units of
production method based upon proved reserves. The computation of DD&A takes
into consideration restoration, dismantlement and abandonment costs and the
anticipated proceeds from equipment salvage. The restoration, dismantlement and
abandonment costs for onshore properties are expected to be offset by the
residual value of lease and well equipment. The Company had a recorded offshore
abandonment liability of $9,100,000 as of December 31, 2002, based on total
expected abandonment costs of $11,700,000 and a liability of $9,500,000 as of
December 31, 2001 based on total expected abandonment costs of $10,251,000. This
liability is included in accumulated DD&A on the consolidated balance
sheets. The Company recorded $204,000, $313,000 and $1,988,000 of offshore
abandonment liability accretion as part of DD&A expense in the consolidated
statements of operations for the years ended December 31, 2002, 2001 and 2000,
respectively.
The Company reviews its long-lived assets for impairments when events
or changes in circumstances indicate that an impairment may have occurred. The
impairment test compares the expected undiscounted future net revenues on a
field-by-field basis with the related net capitalized costs at the end of each
period. Expected future cash flows are calculated on all proved reserves using a
15% discount rate and escalated prices. When the net capitalized costs exceed
the undiscounted future net revenue of a property, the cost of the property is
written down to fair value, which is determined using discounted future net
revenues. During 2002, 2001 and 2000 the Company recorded impairment charges for
proved properties of $-0-, $820,000 and $4,449,000, respectively.
Sales of Producing and Nonproducing Properties
The sale of a partial interest in a proved property is accounted for as
normal retirement, and no gain or loss is recognized as long as this treatment
does not significantly affect the unit-of-production amortization rate. A gain
or loss is recognized for all other sales of producing properties and is
included in the results of operations.
The sale of a partial interest in an unproved property is accounted for
as a recovery of cost when substantial uncertainty exists as to recovery of the
cost applicable to the interest retained. A gain on the sale is recognized to
the extent that the sales price exceeds the carrying amount of the unproved
property. A gain or loss is recognized for all other sales of nonproducing
properties and is included in the results of operations.
F-9
Other Property and Equipment
Other property and equipment is recorded at cost. Costs of renewals and
improvements that substantially extend the useful lives of the assets are
capitalized. Maintenance and repairs are expensed when incurred. Depreciation is
provided using the straight-line method over the estimated useful lives of the
assets from 3 to 15 years. Gains and losses on dispositions of other property
and equipment are included in the results of operations.
Gas Balancing
The Company uses the sales method to account for gas imbalances. Under
this method, revenue is recorded on the basis of gas actually sold by the
Company. The Company records revenue for its share of gas sold by other owners
that cannot be volumetrically balanced in the future due to insufficient
remaining reserves. Related receivables totaling $898,000 at December 31, 2002,
and $984,000 at December 31, 2001, are included in other noncurrent assets in
the accompanying balance sheets. The Company also reduces revenue for gas sold
by the Company that cannot be volumetrically balanced in the future due to
insufficient remaining reserves. Related payables totaling $531,000 at December
31, 2002, and $353,000 at December 31, 2001, are included in other noncurrent
liabilities in the accompanying balance sheets. The Company's remaining
overproduced and underproduced gas balancing positions are considered in the
Company's proved oil and gas reserves (see Note 11 - Disclosures About Oil and
Gas Producing Activities).
Derivative Financial Instruments
The Company seeks to protect its rate of return on acquisitions of
producing properties, drilling prospects and other production by hedging cash
flows when the economic criteria from its evaluation and pricing model indicate
it would be appropriate. The Company intends for these derivative instruments
used for this purpose to be designated as and qualify as cash flow hedging
instruments under Statement of Financial Accounting Standards ("SFAS") No. 133.
Management's strategy is to hedge cash flows from investments currently
requiring a gas price in excess of $3.25 per Mcf and an oil price in excess of
$22.50 per Bbl in order to meet minimum rate-of-return criteria. Management
reviews these hedging parameters on a quarterly basis. The Company generally
limits its aggregate hedge position to no more than 50% of its total production
but will hedge larger percentages of total production in certain circumstances.
The Company seeks to minimize basis risk and indexes the majority of its oil
hedges to NYMEX prices and the majority of its gas hedges to various regional
index prices associated with pipelines in proximity to the Company's areas of
gas production.
The Company's hedge positions are diversified with various
counterparties, and the Company requires that such counterparties have clear
indications of current financial strength (See Note 10 - Derivative Financial
Instruments for additional discussion of derivatives).
Income Taxes
Deferred income taxes are provided on the difference between the tax
basis of an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively.
F-10
Earnings Per Share
Basic net income per common share of stock is calculated by dividing
net income by the weighted average of common shares outstanding during each
year. Diluted net income per common share of stock is calculated by dividing net
income by the weighted average of common shares outstanding and other dilutive
securities. Potentially dilutive securities of the Company consist of
outstanding options to purchase the Company's common stock and shares associated
with the convertible notes that were issued in 2002. The outstanding dilutive
securities related to in-the-money options for the years ended December 31,
2002, 2001 and 2000 were 534,610, 582,313 and 490,288, respectively. Options
that were out-of-the-money and therefore not considered in the diluted income
per share calculation were 1,539,227, 625,492, and -0- for the years ended
December 31, 2002, 2001 and 2000. Shares associated with the convertible notes
are accounted for using the if-converted method. Potentially dilutive shares of
3,076,922 in 2002 that related to the convertible notes were not included in the
calculation of diluted net income per share because they were anti-dilutive.
Stock-Based Compensation
At December 31, 2002 the Company had stock-based employee compensation
plans that are more fully described in Note 7. The Company accounts for
stock-based compensation using the intrinsic value recognition and measurement
principles prescribed in Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" ("APB No. 25") and related interpretations. No
stock-based employee compensation expense is reflected in net income as all
options granted under those plans had an exercise price equal to the market
value of the underlying common stock on the date of grant. The following table
illustrates the effect on net income and earnings per share if the Company had
applied the fair value recognition provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation," to stock-based employee compensation.
Pro Forma for the Years
Ended December 31,
-------------------------------------------
2002 2001 2000
---- ---- ----
(In thousands, except per share amounts)
Net income
As reported $ 27,560 $ 40,459 $ 55,620
Pro forma $ 22,894 $ 37,569 $ 52,515
Basic earnings per share
As reported $ .99 $ 1.45 $ 2.00
Pro forma $ .82 $ 1.34 $ 1.89
Diluted earnings per share
As reported $ .97 $ 1.42 $ 1.97
Pro forma $ .81 $ 1.32 $ 1.86
For purposes of pro forma disclosures, the estimated fair values of the
options are amortized to expense over the options' vesting periods. The effects
of applying SFAS No. 123 in the pro forma disclosure are not necessarily
indicative of actual future amounts. Additional awards in future years are
anticipated.
Comprehensive Income
Comprehensive income consists of net income, and unrealized gains and
losses on marketable equity securities held for sale, the effective component of
derivative instruments classified as cash flow hedges, and accrued pension
benefit obligation in excess of plan assets. Comprehensive income is presented
F-11
net of income taxes in the consolidated statements of stockholders' equity and
comprehensive income.
Major Customers
During 2002 no customer individually accounted for more than 10% of the
Company's total oil and gas production revenue. During 2001 two customers
individually accounted for 12.0% and 11.3% of the Company's total oil and gas
production revenue. During 2000 one customer accounted for 22.3% of the
Company's total oil and gas production revenue.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration,
development and production of natural gas and crude oil, and all of the
Company's operations are conducted in the United States. Consequently, the
Company currently reports as a single industry segment.
F-11
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of oil and gas
reserves, 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.
Recently Issued Accounting Standards
In July 2001 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement
requires companies to recognize the fair value of an asset retirement liability
in the financial statements by capitalizing that cost as part of the cost of the
related long-lived asset. The asset retirement liability should then be
allocated to expense by using a systematic and rational method. The statement is
effective January 1, 2003. The Company has not determined the impact of adoption
of this statement.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." This Statement rescinds SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt", and an amendment of that Statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." This
Statement also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." This Statement amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. This
Statement also amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their applicability
under changed conditions. The provisions of this Statement shall be applied in
fiscal years beginning after May 15, 2002. We currently do not believe that
adoption of this Statement will have an impact on the Company.
In June 2002 the FASB issued SFAS No. No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This Statement addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
F-12
Activity (including Certain Costs Incurred in a Restructuring)." The provisions
of this Statement are effective for exit or disposal activities that are
initiated after December 31, 2002, with early application encouraged. The
Company does not believe that adoption of this Statement will have a material
impact on the financial statements.
In December 2002 the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation -- Transition and Disclosure: an amendment of FASB
Statement No. 123." This Statement amends SFAS No. 123, "Accounting for
Stock-Based Compensation", to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, this Statement amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results. The
Statement is effective for financial statements for fiscal years ending after
December 15, 2002. The Company will continue to account for stock-based
compensation using the methods detailed in the stock-based compensation
accounting policy.
2. Accounts Receivable
Accounts receivable are composed of the following:
December 31,
-------------------------
2002 2001
---------- ----------
(In thousands)
Accrued oil and gas sales $25,962 $29,041
Due from joint interest owners 8,920 17,042
Other 517 401
---------- ----------
Total accounts receivable $35,399 $46,484
========== ==========
3. Acquisitions
On December 3, 2002, the Company completed the acquisition of oil and
gas properties located in Montana, North Dakota and Wyoming from Burlington
Resources Oil & Gas Company LP. The Company paid $69,469,000 in cash after
normal price adjustments. The Company utilized a portion of its existing credit
facility to fund the acquisition, and the transaction was accounted for as a
purchase.
On November 29, 2001, the Company completed the acquisition of oil and
gas properties located in Montana, North Dakota and Wyoming from Choctaw II Oil
and Gas, LTD. The Company paid $40,526,000 in cash after normal price
adjustments. The Company utilized a portion of its existing credit facility to
fund the acquisition, and the transaction was accounted for as a purchase.
On December 28, 2000, the Company completed the acquisition of oil and
gas properties primarily located in the Anadarko Basin of Oklahoma from JN
Exploration and Production Limited Partnership and affiliates for $31,613,000
million in cash after normal purchase price adjustments. The Company utilized
cash on hand and a portion of its existing credit facility to fund the
acquisition. The transaction was accounted for as a purchase.
F-13
4. Income Taxes
The provision for income taxes consists of the following:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---------- ---------- ----------
(in thousands)
Current Taxes:
Federal $ 719 $ 1,114 $ 11,194
State 569 620 1,181
Deferred taxes 13,731 20,095 21,292
---------- ---------- ----------
Total income tax expense $ 15,019 $ 21,829 $ 33,667
========== ========== ==========
The above taxes from continuing operations are net of alternative fuels
credits (Internal Revenue Code Section 29) of $167,000 in 2002, $185,000 in 2001
and $79,000 in 2000. Current federal tax does not reflect the tax benefit for
deductions from stock option exercises of $719,000 in 2002, $930,000 in 2001 and
$1,771,000 in 2000 because the benefit is included in additional paid-in capital
in the consolidated balance sheets. The net federal taxes payable for the years
ending December 31, 2002, 2001 and 2000 are $-0-, $184,000 and $9,423,000,
respectively.
The components of the net deferred tax liability are as follows:
December 31,
---------------------
2002 2001
---------- ----------
(in thousands)
Deferred Tax Liabilities
Oil and gas properties $ 71,448 $ 55,819
Derivative Instruments - 3,903
Other 62 147
---------- ----------
Total deferred tax liabilities 71,510 59,869
---------- ----------
Deferred Tax Assets
Amounts included in Other Comprehensive Income 4,181 -
State tax net operating loss carryforward 4,042 3,638
Federal net operating loss carryforward 3,142 -
Deferred capital loss 1,703 1,715
Other, primarily employee benefits 1,325 1,716
State and federal income tax benefit 775 3,497
Charitable contributions carryforward 218 -
Alternative minimum tax credit carryforward 215 184
---------- ----------
Total deferred tax assets 15,601 10,750
Valuation allowance (727) (1,929)
---------- ----------
Net deferred tax assets 14,874 8,821
---------- ----------
Total net deferred tax liabilities 56,636 51,048
Current deferred income tax assets (liabilities) 3,520 (3,363)
---------- ----------
Non-current net deferred tax liabilities $ 60,156 $ 47,685
========== ==========
Current refundable income tax $ 1,031 $ 11,061
========== ==========
F-14
In accordance with SFAS No. 109 the Company records purchase
adjustments to its long-term deferred income tax liability accounts to more
closely align book and tax basis at the time of acquisition. These adjustments
mitigate the effect of deferred income tax expense or reduced deferred income
tax benefit on future net income before income tax from acquisitions that
utilize the purchase method for accounting principles generally accepted in the
United States and are considered to be tax-free basis transfers for tax
accounting. During 1999 the Company adjusted its long-term deferred income tax
liability account for a $667,000 increase relating to its Nance Petroleum
Corporation ("Nance") stock acquisition and recorded a $10,426,000 decrease for
its King Ranch Energy ("KRE") stock acquisition as Nance's book basis was
greater than its tax basis, and KRE's tax basis was greater than its book basis.
The Company has been recording adjustments to reflect the utilization of
additional tax benefits of KRE by King Ranch, Inc. on it's 1999 Federal
consolidated income tax return and to reflect the utilization of tax benefits or
liabilities on its own federal consolidated returns since the original amounts
were recorded.
At December 31, 2002, the Company had state net operating loss
carryforwards of approximately $61,000,000, which expire between 2003 and 2021.
The Company's valuation allowance relates to those state net operating loss
carryforwards that the Company anticipates will expire before they can be
utilized. The net change in valuation allowance in 2002 results from an
evaluation of state net operating loss carryforwards that led to a conclusion by
the Company that more of the carryforwards will be offset by reversing state
temporary differences, projections of future taxable income and individual state
tax planning strategies before they expire than was anticipated in prior years.
Federal income tax expense differs from the amount that would be
provided by applying the statutory U.S. Federal income tax rate to income before
income taxes for the following reasons:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
--------------------------------
(in thousands)
Federal statutory taxes $ 14,477 $ 20,420 $ 30,267
Increase (reduction) in taxes resulting from:
State taxes (net of Federal benefit) 2,092 2,017 4,342
Statutory depletion (218) (238) (71)
Alternative fuel credits (Section 29) (167) (185) (79)
Change in valuation allowance (1,202) 34 (826)
Other 37 (219) 34
---------- ---------- ----------
Income tax expense from continuing
operations $ 15,019 $ 21,829 $ 33,667
========== ========== ==========
5. Long-term Debt and Notes Payable
In March 2002 the Company issued in a private placement a total of
$100,000,000 of 5.75% senior convertible notes due 2022 (the "Notes") with a
0.5% contingent interest provision (see Note 10-Derivative Financial
Instruments). The contingent interest provision did not apply to St. Mary's
first interest payment on September 15, 2002, but it will apply to the payment
due on March 15, 2003. Interest payments will be made on March 15 and September
15 in subsequent years. The Company received net proceeds of $96,661,000 after
deducting the initial purchasers' discount and offering expenses paid by the
Company. The Notes are general unsecured obligations and rank on parity in right
of payment with all existing and future unsecured senior indebtedness and other
F-15
general unsecured obligations. They are senior in right of payment to
all future subordinated indebtedness. The Notes are convertible into the
Company's common stock at a conversion price of $26.00 per share, subject to
adjustment. The Company can redeem the Notes with cash in whole or in part at a
repurchase price of 100% of the principal amount plus accrued and unpaid
interest (including contingent interest) beginning on March 20, 2007. The note
holders have the option of requiring the Company to repurchase the Notes for
cash at 100% of the principal amount plus accrued and unpaid interest (including
contingent interest) upon (1) a change in control of St. Mary or (2) on March
20, 2007, March 15, 2012, and March 15, 2017. If the note holders require
repurchase on March 20, 2007, the Company may elect to pay the repurchase price
with cash, shares of its common stock valued at a discount at the time of
repurchase, or any combination of cash and its discounted common stock. The
shares of common stock used in any repurchase will be discounted at 95% of
market price if 33% or less of the repurchase price is in shares of our common
stock; otherwise the stock will be discounted at 93% of market value. St. Mary
is not restricted from paying dividends, incurring debt, or issuing or
repurchasing its securities under the indenture for the Notes. There are no
financial covenants in the indenture. The Company used a portion of the net
proceeds from the Notes to repay its credit facility balance and used the
remaining net proceeds to fund a portion of its 2002 capital expenditures. On
March 25, 2002, the Company entered into a five-year fixed-rate to floating-rate
interest rate swap on $50,000,000 of Notes. The floating rate for each
applicable six-month period was determined as LIBOR plus 0.36%. For the
six-month calculation period ending March 15, 2003 this rate was 2.19%. The
interest rate swap contract was terminated on December 3, 2002. The Company
received proceeds of $3,952,000 upon termination of the contract and recorded a
derivative gain of $3,561,000 in the statement of operations. See Note 10 -
Derivative Financial Instruments for a discussion of the derivative accounting
for the interest rate swap.
On March 4, 2002, St. Mary entered into an agreement to amend the
existing long-term revolving credit agreement. The lender may periodically
re-determine the aggregate borrowing base depending upon the value of St. Mary's
oil and gas properties and other assets. The accepted borrowing base was $40.0
million at December 31, 2002, and the stated total borrowing base was $160.0
million. The credit agreement has a maturity date of December 31, 2006 and
includes a revolving period that matures on June 30, 2003. Quarterly principal
payments will begin on September 30, 2003. The amended agreement deletes all
reference to and provisions of the short-term tranche previously available to
St. Mary. The Company must comply with certain covenants including maintenance
of stockholders' equity at a specified level and limitations on additional
indebtedness. These outstanding balances accrued interest at rates determined by
St. Mary's debt to total capitalization ratio at our option of either:
Debt to Capitalization Ratio <30% =>30%<40% =>40%<50% =>50%
----------------------------------------------------------------------------------------------
Option (1)
LIBOR plus 1.000% 1.250% 1.375% 1.625%
Option (2) - The higher of:
Federal funds rate plus 0.500% 0.500% 0.500% 0.500%
Prime rate plus - - - 0.250%
The debt to total capitalization ratio as defined under the agreement
was 27.5% as of December 31, 2002.
Outstanding borrowings under the revolving credit agreement were
$14,000,000 and $64,000,000 as of December 31, 2002 and 2001, respectively.
Borrowings under the Notes were $100,000,000 and $-0- as of December 31, 2002
F-16
and 2001, respectively. The weighted average interest rate paid in 2002 was 4.2%
including commitment fees paid on the unused portion of the accepted borrowing
base and including the effect of the interest rate swap contract. Borrowings
under the facility are secured by a pledge of collateral in favor of the banks
and guarantees by subsidiaries. Such collateral consists primarily of security
interests in the oil and gas properties of St. Mary and its subsidiaries.
The Company's estimated annual principal payments under the credit
agreement for the next four years are as follows:
Years Ending
December 31, (In thousands)
---------------- -------------
2003 $ 2,000
2004 4,000
2005 4,000
2006 4,000
-------------
Total $14,000
=============
In January 2003, this line of credit was closed and replaced, as
described in Note 13, Subsequent Events.
6. Commitments and Contingencies
The Company leases office space under various operating leases with
terms extending as far as May 31, 2012. The Company has a noncancelable sublease
of approximately $1,685,000 through 2012. Rent expense, net of sublease income,
was $1,082,000, $839,000 and $782,000 in 2002, 2001 and 2000, respectively. The
Company also leases office equipment under various operating leases. The annual
minimum lease payments for the next five years are presented below:
Years Ending
December 31, (In thousands)
--------------- ------------
2003 $1,573
2004 1,327
2005 1,205
2006 1,125
2007 861
Thereafter 3,674
------------
Total $9,724
============
7. Compensation Plans
The Company has a cash bonus plan that allows participants to receive
up to 100% of their aggregate base salary. Any awards under the cash bonus plans
are based on a combination of Company and individual performance. The Company
accrued $2,100,000 for cash bonuses in 2002 that will be paid in 2003, $170,000
for cash bonuses in 2001 that were paid in 2002, and $1,957,000 for cash bonuses
in 2000 that were paid in 2001.
Under the Company's net profits interest bonus plan, oil and gas wells
that are completed or acquired during a year are designated as a pool. Key
employees designated as participants by the Company's board of directors and
employed by the Company on the last day of that year vest and become entitled to
bonus payments after the Company recovers net revenues generated by the pool
F-17
equal to 100% of its investment in that pool. Thereafter, an amount generally
equal to 10% of net revenues generated by the pool will be allocated among the
participants and paid on a quarterly basis. The percentage of net revenues from
the pool to be split among the participants increases to 20% after the Company
recovers net revenues equal to 200% of its investment. The Company records
estimated compensation expense based on a number of assumptions including
estimates of oil and gas production, oil and gas prices, recurring and workover
lease operating expense and a present value discount factor. The Company uses a
discount factor to calculate present value that reflects recovery of its
investment, the timing of payments to participants and uncertainties associated
with the estimates. The estimates the Company uses will change from year-to-year
based on new information and any change in estimated compensation will be
recorded in the period that information becomes available. The Company recorded
estimated compensation expense of $5,600,000 in 2002, $5,259,000 in 2001 and
$877,000 in 2000 relating to the net profits interest bonus plan.
The Company has a defined contribution pension plan ("401(k) Plan")
that is subject to the Employee Retirement Income Security Act of 1974. The
401(k) Plan allows eligible employees to contribute up to 60% of their base
salaries. The Company matches each employee's contributions up to 6% of the
employee's base salary and also may make additional contributions at its
discretion. The Company's contributions to the 401(k) Plan were $621,000,
$559,000, and $412,000 for the years ended December 31, 2002, 2001 and 2000,
respectively. No discretionary contributions were made by the Company to the
401(K) Plan in any of these three years.
In September 1997 the Board of Directors approved the St. Mary Land
& Exploration Company Employee Stock Purchase Plan ("Stock Purchase Plan"),
which became effective January 1, 1998. Under the Stock Purchase Plan eligible
employees may purchase shares of the Company's common stock through payroll
deductions of up to 15% of eligible compensation. The purchase price of the
stock is 85% of the lower of the fair market value of the stock on the first or
last day of the purchase period. The Stock Purchase Plan is intended to qualify
under Section 423 of the Internal Revenue Code. The Company has set aside
1,000,000 shares of its common stock to be available for issuance under the
Stock Purchase Plan. In 2002, 2001 and 2000 shares issued under the Stock
Purchase Plan totaled 18,217, 29,772 and 32,296, respectively. Total proceeds to
the Company for the issuance of these shares were $344,000, $575,000 and
$311,000 in 2002, 2001 and 2000, respectively. The Company recorded compensation
expense of $21,000, $20,000 and $3,000 in 2002, 2001 and 2000, respectively, due
to nonqualified dispositions of stock acquired by employees under the Stock
Purchase Plan.
In 1996 the Company established the St. Mary Land & Exploration
Company Stock Option Plan and the St. Mary Land & Exploration Company
Incentive Stock Option Plan (collectively, the "Option Plans"). The Option Plans
grant options to purchase shares of the Company's common stock to eligible
employees, contractors, and current and former members of the Board of
Directors. In 2001 the stockholders approved an increase in the number of shares
of the Company's common stock reserved for issuance under the Option Plans from
3,300,000 shares to 4,300,000 shares. All options granted to date under the
Option Plans have been granted at exercise prices equal to the respective market
prices of the Company's common stock on the grant dates.
F-18
A summary of the status of the Company's Stock Option Plans, including
the 1990 and 1991 options and changes during the last three years follows:
For the Years Ended December 31,
------------------------------------------------------------------------------
2002 2001 2000
------------------------- ------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------- ----------- ------------ ------------ ------------ ------------
Outstanding, start of year 2,151,675 $ 19.42 1,986,124 $ 18.95 1,998,254 $ 11.63
Granted 1,109,541 23.55 397,009 18.86 653,848 33.31
Exercised 177,085 11.44 187,810 11.57 619,220 11.05
Forfeited 22,565 25.08 43,648 26.00 46,758 11.74
------------- ------------ ------------
Outstanding, end of year 3,061,566 21.34 2,151,675 19.42 1,986,124 18.95
============= ============ ============
Exercisable, end of year 1,944,382 19.79 1,418,404 17.09 1,150,196 15.00
============= ============ ============
Weighted average fair
value of options
granted during the year $ 10.77 $ 8.36 $ 14.75
============= ============ ============
A summary of additional information related to the options outstanding
as of December 31, 2002 follows:
Options Outstanding Options Exercisable
------------------------------------------------- ------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Number Contractual Exercise Number Exercise
Exercise Prices Outstanding Life Price Exercisable Price
- ---------------------- ------------- ---------------- -------------- -------------- -------------
$ 9.25 - $10.25 332,808 4.8 years $ 9.57 328,776 $ 9.57
12.38 - 14.69 517,367 6.7 years 12.58 517,367 12.58
15.93 - 17.50 280,111 7.3 years 16.55 196,353 16.82
21.19 - 25.00 1,314,209 9.5 years 23.17 430,847 22.83
33.31 - 33.31 617,071 8.0 years 33.31 471,039 33.31
------------- --------------
Total 3,061,566 8.0 years 21.34 1,944,382 19.79
============= ==============
SFAS No. 123 establishes a fair value method of accounting for
stock-based compensation plans either through recognition or disclosure. The
Company accounts for stock-based compensation under APB No. 25 and has elected
to adopt SFAS No. 123 through compliance with the disclosure requirements set
forth in the Statement. Because the exercise price of the Company's employee
stock options equals the market price of the underlying stock on the date of
grant, no compensation expense is recognized under APB No. 25. Pro forma
information regarding net income and earnings per share is required by SFAS No.
F-19
123 and has been determined as if the Company had accounted for its employee
stock options under the fair value method of that Statement.
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair values of options granted in 2002,
2001 and 2000 were estimated using the following weighted-average assumptions:
2002 2001 2000
---- ---- ----
Risk free interest rate 3.76% 4.35% 5.14%
Dividend yield 0.43% 0.53% 0.32%
Volatility Factor of the expected
market price of the Company's
common stock 47.54% 49.79% 47.11%
Expected life of the options (in years) 5.9 4.8 4.8
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options that have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, it
is management's opinion that the existing models do not necessarily provide a
reliable single measure of the fair value of St Mary's employee stock options.
F-20
8. Pension Benefits
The Company's employees participate in a non-contributory pension plan
covering substantially all employees who meet age and service requirements (the
"Qualified Pension Plan"). The Company also has a supplemental non-contributory
pension plan covering certain management employees (the "Nonqualified Pension
Plan"). The Company's disclosures about pension benefits are as follows:
For the Years Ended December 31,
2002 2001
---- ----
(In thousands)
Change in benefit obligations:
Benefit obligation at beginning of year $ 5,098 $ 3,054
Service Cost 442 323
Interest Cost 358 317
Amendments (46) 0
Actuarial loss 409 1,485
Benefits paid (25) (81)
-------- --------
Benefit obligation at end of year $ 6,236 $ 5,098
======== ========
Change in plan assets:
Fair value of plan assets at beginning of year $ 2,042 $ 1,775
Actual return on plan assets (255) (13)
Employer contribution 716 361
Benefits paid (25) (81)
-------- --------
Fair value of plan assets at end of year $ 2,478 $ 2,042
======== ========
Funded Status $(3,758) $(3,056)
Unrecognized net actuarial loss 2,925 2,326
Unrecognized prior service cost (41) (20)
-------- --------
Accrued benefit cost $ (874) $ (750)
======== ========
F-20
The Company's Qualified Pension Plan's accumulated benefit obligation
was $3,526,000 at December 31, 2002, and $2,646,000 at December 31, 2001. The
accumulated benefit obligation exceeds plan assets by $1,048,000. The
tax-adjusted liability of $761,000 was recorded in other comprehensive income at
December 31, 2002.
The Company's Nonqualified Pension Plan's accumulated benefit
obligation was $853,000 at December 31, 2002, and $685,000 at December 31, 2001.
There are no plan assets in the nonqualified plan due to the nature of the plan.
Assumptions used in the measurement of the Company's benefit obligation
are as follows:
For the Years Ended December 31,
--------------------------------
2002 2001
---- ----
Weighted-average assumptions:
Discount rate 6.50% 7.25%
Expected return on plan assets 8.00% 8.00%
Rate of compensation increase 4.75% 5.00%
F-21
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Components of net periodic benefit cost:
Service cost $ 442 $ 323 $ 257
Interest cost 358 317 193
Expected return on plan assets (146) (129) (119)
Amortization of prior service cost (25) (8) (7)
Amortization of net actuarial loss 211 188 36
------ ------ ------
Net periodic benefit cost $ 840 $ 691 $ 360
====== ====== ======
Prior service costs are amortized on a straight-line basis over the
average remaining service period of active participants. Gains and losses in
excess of 10% of the greater of the benefit obligation and the market-related
value of assets are amortized over the average remaining service period of
active participants.
9. Investment in Russian Joint Venture
In February 2000 St. Mary exercised its option to convert its Khanty
Mansiysk Oil Corporation ("KMOC") production payment receivable into common
stock of KMOC. In July 2000 the Company finalized a negotiated value for the
receivable that equated to 21,583 shares of KMOC common stock under the terms of
the original agreement. In December 2000 the Company sold 14,662 of these shares
for proceeds of $6,157,000, net of transaction costs and recognized a net gain
of $2,156,000.
In January 2002 the Company sold its remaining shares of KMOC common
stock for proceeds of $2,772,000 and recorded a gain of $838,000.
10. Derivative Financial Instruments
The Company realized a net gain of $878,000 from its derivative
contracts for the year ended December 31, 2002, a net loss of $22,675,000 for
the year ended December 31, 2001 and a net loss of $33,641,000 for the year
ended December 31, 2000.
The Company's senior convertible notes contain a provision for payment
of contingent interest if certain conditions are met. Under SFAS No. 133 this
provision is considered an embedded equity related derivative that is not
clearly and closely related to the fair value of an equity interest and
therefore must be separately treated as a derivative instrument. The value of
the derivative at issuance was $474,000. This amount was recorded as a decrease
to the convertible notes payable in the consolidated balance sheets. Of this
amount, $75,000 has been amortized through interest expense. Derivative gain in
the consolidated statements of operations includes $341,000 of net loss from
mark-to-market adjustments for this derivative.
The Company's fixed-rate to floating rate interest rate swap on
$50,000,000 of senior convertible notes did not qualify for fair value hedge
treatment under SFAS No. 133. This contract was entered into on March 25, 2002,
and was closed out on December 3, 2002. Derivative gain in the consolidated
statement of operations includes $3,561,000 of net realized gain from the
termination of the interest rate swap contract.
F-22
The following table summarizes derivative instrument activity.
2002 2001 2000
--------------- --------------- ---------------
Gain (Loss)
Derivative contract settlements included
in oil and gas production revenues $ (2,235,000) $ (21,102,000) $ (33,641,000)
Ineffective portion of hedges qualifying
for hedge accounting included in
derivative gain(loss) (32,000) 45,000 -
Non-qualified derivative contracts included
in derivative gain (loss) 3,220,000 (1,618,000) -
Amortization of contingent interest derivative
through interest expense (75,000) - -
--------------- --------------- ---------------
Total $ 878,000 $ (22,675,000) $ (33,641,000)
=============== =============== ===============
Including hedges entered into since December 31, 2002 the Company has
the following commodity swap contracts in place to hedge cash flow and reduce
the impact of oil and gas price fluctuations:
Swaps
-----
Average Quantity Average Fixed
Product Volumes/month Type Contract Price Duration
---------------------------------------------------------------------------------------------
Natural Gas 1,599,000 MMBtu $4.35 01/03 - 12/03
Natural Gas 844,000 MMBtu $4.04 01/04 - 12/04
Oil 206,200 Bbls $25.94 01/03 - 12/03
Oil 144,500 Bbls $23.71 01/04 - 12/04
Collars
-------
Average Floor Ceiling
Product Volumes/month Price Price Duration
---------------------------------------------------------------------------------------------
Natural Gas 152,000 MMbtu $2.50 $5.96 02/03 - 12/03
This table excludes commodity positions with Enron North America Corp,
which filed for bankruptcy protection in December 2001. A net non-cash gain of
$1,697,000 from these contracts is included in oil and gas production operating
revenues in the consolidated statements of operations. The Company will amortize
the remaining $49,000 unrealized hedge loss in 2003.
As noted in the table above, the last of those contracts will expire by
December 31, 2004. Derivative gain in the consolidated statement of operations
includes a loss of $31,000 from ineffectiveness related to these hedge
contracts. On December 31, 2002 the estimated fair value of contracts designated
and qualifying as cash flow hedges under SFAS No. 133 was a liability of
$9,980,000. The Company will reclassify this amount to gains or losses included
in oil and gas production operating revenues as the hedged production quantity
is produced. Based on current prices the net amount of existing unrealized
after-tax loss as of December 31, 2002 to be reclassified from accumulated other
comprehensive income to oil and gas production operating revenues in the next
twelve months would be $5,461,000, net of deferred income taxes. The Company
F-23
anticipates that all original forecasted transactions will occur by the end of
the originally specified time periods.
The Company adopted SFAS No. 133 adopted on January 1, 2001. SFAS No.
133 requires companies to report all derivatives at fair value as either assets
or liabilities and bases the accounting treatment of the derivatives on the
reasons an entity holds the instrument. The adoption of SFAS No. 133 resulted in
the Company recording a liability of $45,699,000 for the fair value of the
derivative instruments at January 1, 2001. The Company's adoption entry also
resulted in deferral of the recognition of this liability to accumulated other
comprehensive loss of $28,587,000, net of deferred income taxes.
See also Derivative Financial Instruments in Note 1 - Summary of
Significant Accounting Policies.
F-23
11. Disclosures About Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Producing Activities:
Costs incurred in oil and gas property acquisition, exploration and
development activities, whether capitalized or expensed, are summarized as
follows:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Development costs $ 74,376 $ 98,617 $ 48,996
Exploration 22,778 24,506 17,012
Acquisitions:
Proved 87,706 41,188 53,482
Unproved 8,128 18,552 5,694
-------- -------- --------
Total $192,988 $182,863 $125,184
======== ======== ========
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 2002, 2001, and 2000 was
prepared by Ryder Scott Company and St. Mary. The Company emphasizes that
reserve estimates are inherently imprecise and that estimates of new discoveries
are more imprecise than those of proved producing oil and gas properties.
Accordingly, these estimates are expected to change as future information
becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods.
F-24
Presented below is a summary of the changes in estimated domestic
reserves of the Company:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
-------- ---- ----
Oil or Oil or Oil or
Condensate Gas Condensate Gas Condensate Gas
---------- --- ---------- --- ---------- ---
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
Total proved reserves:
Developed and undeveloped:
Beginning of year 23,669 241,231 20,950 225,975 18,900 207,642
Revisions of previous estimate 3,611 4,696 (1,334) (16,421) 210 (1,172)
Discoveries and extensions 1,250 32,813 3,131 59,830 1,707 37,702
Purchases of minerals in place 10,578 38,118 3,774 13,086 3,149 21,689
Sales of reserves (174) (4,522) (418) (1,748) (618) (1,540)
Production (2,815) (38,164) (2,434) (39,491) (2,398) (38,346)
------ ------- ------ ------- ------ -------
End of year (a) 36,119 274,172 23,669 241,231 20,950 225,975
====== ======= ====== ======= ====== =======
Proved developed reserves:
Beginning of year 20,679 205,637 19,006 192,472 16,688 169,379
====== ======= ====== ======= ====== =======
End of year 33,580 228,973 20,679 205,637 19,006 192,472
====== ======= ====== ======= ====== =======
------------------
(a) At December 31, 2002, 2001, and 2000, includes approximately
1,151, 869 and 1,199 MMcf, respectively, representing the
Company's underproduced gas balancing position.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited):
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities,"
prescribes guidelines for computing a standardized measure of future net cash
flows and changes therein relating to estimated proved reserves. The Company has
followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying benchmark prices and costs, including transportation,
quality and basis differential, in effect at year-end to the year-end estimated
quantities of oil and gas to be produced in the future. Estimated future income
taxes are computed using current statutory income tax rates, including
consideration for estimated future statutory depletion and alternative fuels tax
credits. The resulting future net cash flows are reduced to present value
amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the FASB and the Securities and Exchange Commission. These
assumptions do not necessarily reflect the Company's expectations of actual
revenues to be derived from those reserves, nor their present worth. The
limitations inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process. The following
prices, adjusted for transportation, quality and basis differentials, were used
in the calculation of the standardized measure:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
Gas (per Mcf) $ 4.211 $ 2.502 $ 8.857
Oil (per Bbl) $29.311 $18.113 $ 25.439
F-25
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:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Future cash inflows $2,238,513 $1,020,948 $2,648,108
Future production and
development costs (783,991) (444,608) (570,711)
Future income taxes (429,618) (140,271) (727,929)
---------- ----------- ----------
Future net cash flows 1,024,904 436,069 1,349,468
10% annual discount (443,042) (154,192) (630,984)
---------- ----------- ----------
Standardized measure of
discounted future net cash flows $ 581,862 $ 281,877 $ 718,484
========== =========== ==========
The principle sources of change in the standardized measure of
discounted future net cash flows are as follows:
For the Years Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
(In thousands)
Standard measure, beginning of year $ 281,877 $ 718,484 $ 261,314
Sales of oil and gas produced,
net of production costs (137,066) (170,074) (183,586)
Net changes in prices and production costs 298,079 (820,253) 772,910
Extensions, discoveries and other,
net of production costs 92,227 71,265 203,786
Purchase of minerals in place 160,089 29,267 104,883
Development costs incurred during the year 23,802 35,736 12,436
Changes in estimated future development cost 4,265 (8,370) 351
Revisions of previous quantity estimates 49,892 (17,593) 306
Accretion of discount 34,749 109,912 33,871
Sales of reserves in place (708) (10,548) (3,329)
Net change in income taxes (177,335) 298,717 (357,780)
Other (48,009) 45,334 (126,678)
---------- ----------- ----------
Standardized measure, end of year $ 581,862 $ 281,877 $ 718,484
========== =========== ==========
F-26
12. Quarterly Financial Information (Unaudited)
The Company's quarterly financial information for fiscal 2002 and 2001
is as follows (in thousands, except per share amounts):
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Year Ended December 31, 2002:
Total Revenue $ 42,773 $ 50,028 $ 48,335 $ 55,258
Less: costs and expenses 38,991 33,322 35,634 42,758
---------- ---------- ---------- ----------
Operating Income $ 3,782 $ 16,706 $ 12,701 $ 12,500
Income before income taxes $ 3,440 $ 15,858 $ 1,187 $ 11,402
Net income $ 2,318 $ 10,589 $ 7,674 $ 6,979
Net income per common share:
Basic $ 0.08 $ 0.38 $ 0.28 $ 0.25
Diluted $ 0.08 $ 0.37 $ 0.27 $ 0.24
Dividends paid per share $ - $ 0.05 $ - $ 0.05
Year Ended December 31, 2001
Total Revenue $ 68,347 $ 55,776 $ 42,656 $ 40,690
Less: costs and expenses 36,626 32,804 37,129 38,998
---------- ---------- ---------- ----------
Operating Income 31,721 22,972 5,527 1,692
Income before income taxes $ 31,874 $ 23,119 $ 5,595 $ 1,700
Net income $ 20,393 $ 14,234 $ 4,861 $ 971
Net income per common share:
Basic $ 0.72 $ 0.51 $ 0.17 $ 0.04
Diluted $ 0.71 $ 0.50 $ 0.17 $ 0.03
Dividends paid per share $ - $ 0.05 $ - $ 0.05
13. Subsequent Events (Unaudited)
Long - Term Debt
In January 2003 the Company entered into a new long-term revolving
credit agreement that replaced the agreement dated June 30, 1998. The new credit
agreement specifies a maximum loan amount of $300,000,000. Borrowings under the
facility are secured by a pledge of collateral in favor of the lenders and by
common stock of material subsidiaries of the Company. The borrowing base is
currently $215,000,000 but will be increased to $250,000,000 when additional
collateral is provided to the lenders. The lenders may periodically re-determine
the aggregate borrowing base depending upon the value of St. Mary's oil and gas
properties and other assets. The aggregate commitment was $150,000,000 at
January 27, 2003, and the credit agreement has a maturity date of January 27,
2006. The Company must comply with certain covenants. Interest is accrued based
on the borrowing base utilization percentage as LIBOR or the Alternate Base Rate
("ABR"), which is the Prime rate plus the following:
F-27
Borrowing base
utilization percentage <30% =>30%<40% =>40%<50% =>50%
- -----------------------------------------------------------------------------------------------
Eurodollar Loans 1.250% 1.500% 1.750% 2.000%
ABR Loans 0.000% 0.250% 0.500% 0.750%
Commitment Fee Rate 0.300% 0.375% 0.375% 0.500%
Acquisitions
On January 29, 2003, the Company closed the previously announced
agreement to acquire oil and gas properties from Flying J Oil & Gas Inc. and
Big West Oil & Gas Inc. St. Mary issued 3,380,818 shares of its restricted
common stock valued at $71,594,000 for an estimated 66.9 BCFE of proved reserves
and a net amount of $2,800,000 in cash for purchase price adjustments. In
addition, St. Mary has made a non-recourse loan to Flying J and Big West of
$71,594,000 at LIBOR plus 2% for up to a 39-month period that is secured by a
pledge of these shares of St. Mary stock. During the 39-month loan period Flying
J and Big West can elect to sell their shares of St. Mary stock to the Company
for $71,594,000 plus accrued interest on the loan for the first thirty months,
and St. Mary can elect to purchase the shares for $97,447,000, with the proceeds
applied to the repayment of the loan.
F-28
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ST. MARY LAND & EXPLORATION COMPANY
---------------------------------------
(Registrant)
Date: March 12, 2003 By: /s/ MARK A. HELLERSTEIN
-----------------------------------
Mark A. Hellerstein
Chairman of the Board of Directors,
President and Chief Executive Officer
GENERAL POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Mark A. Hellerstein his or her true and
lawful attorney-in-fact and agent with full power of substitution and
resubstitution, for him or her and in his or her name, place and stead, in any
and all capacities, to sign any amendments to this annual report on Form 10-K,
and to file the same, with exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, hereby ratifying and
confirming all that said attorney-in-fact, or his substitute or substitutes, may
do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
/s/ MARK A. HELLERSTEIN Chairman of the Board of Directors, March 12, 2003
- ----------------------- President and Chief Executive Officer
Mark A. Hellerstein
/s/ RONALD D. BOONE Executive Vice President, Chief March 12, 2003
- ----------------------- Operating Officer and Director
Ronald D. Boone
/s/ ROBERT L. NANCE Senior Vice President and Director March 12, 2003
- -----------------------
Robert L. Nance
/s/ RICHARD C. NORRIS Vice President-Finance, March 12, 2003
- ----------------------- Secretary and Treasurer
Richard C. Norris
/s/ GARRY A. WILKENING Vice President-Administration March 12, 2003
- ----------------------- and Controller
Garry A. Wilkening
Signature Title Date
- --------- ----- ----
/s/BARBARA M. BAUMANN Director March 12, 2003
- -----------------------
Barbara M. Baumann
Director March 12, 2003
- -----------------------
Larry W. Bickle
Director March 12, 2003
- -----------------------
Thomas E. Congdon
/s/ WILLIAM J. GARDINER Director March 12, 2003
- -----------------------
William J. Gardiner
/s/ AREND J. SANDBULTE Director March 12, 2003
- -----------------------
Arend J. Sandbulte
Director March 12,2003
- -----------------------
John M. Seidl
CERTIFICATION
I, Mark A. Hellerstein, certify that:
1. I have reviewed this annual report on Form 10-K of St. Mary Land
& Exploration Company;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 12, 2003
/s/ MARK A. HELLERSTEIN
------------------------------------
Mark A. Hellerstein
Chairman of the Board, President and
Chief Executive Officer
CERTIFICATION
I, Richard C. Norris, certify that:
1. I have reviewed this annual report on Form 10-K of St. Mary Land
& Exploration Company;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 12, 2003
/s/ RICHARD C. NORRIS
------------------------------------
Richard C. Norris
Vice-President - Finance