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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, 2001.
OR
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.
Commission File Number 000-20872
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 41-0518430
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1776 Lincoln Street, Suite 1100, Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)
(303) 861-8140
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
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(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ x ] No [ ]
Indicate by check mark if disclosure of delinquent 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. [ X ]
The aggregate market value of 26,932,198 shares of voting stock held by
non-affiliates of the Registrant, based upon the closing sale price of the
common stock on March 12, 2002 of $19.93 per share as reported on the Nasdaq
National Market System, was $536,758,706. 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 12, 2002, the registrant had 27,805,529 shares of common
stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III (Items 10, 11, 12 and 13) is incorporated
by reference from the Registrant's definitive proxy statement relating to its
2002 annual meeting of stockholders to be filed within 120 days from December
31, 2001.
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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, 2000............3
Major Customers.............................................4
Employees and Office Space..................................4
Title to Properties.........................................4
Competition.................................................5
Government Regulations......................................5
Risk Factors................................................9
Cautionary Statement about Forward-Looking Statements......19
Glossary...................................................20
ITEM 2. PROPERTIES.....................................................23
Operations.................................................23
Acquisitions...............................................27
Reserves...................................................28
Production.................................................29
Productive Wells...........................................29
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...........................32
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS....................................34
ITEM 6. SELECTED FINANCIAL DATA........................................35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................37
Overview...................................................37
Critical Accounting Policies and Estimates.................37
Results of Operations......................................39
Liquidity and Capital Resources............................44
Accounting Matters.........................................49
Effects of Inflation and Changing Prices...................50
Environmental..............................................50
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TABLE OF CONTENTS
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(Continued)
ITEM PAGE
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK....................................................51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................52
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE............................52
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.............52
ITEM 11. EXECUTIVE COMPENSATION.........................................52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT.................................................52
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................52
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K............................................52
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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 of Common Oil and Gas Terms".
Throughout this document we make statements that are classified as
"forward-looking". Please refer to the "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 western Oklahoma and northern Texas;
o the ArkLaTex region that spans northern Louisiana and portions of
eastern Texas, Arkansas and Mississippi;
o the onshore Gulf Coast and offshore Gulf of Mexico;
o the Williston Basin in eastern Montana and western North Dakota; and
o the Permian Basin in eastern New Mexico and western Texas.
As of December 31, 2001, we had estimated proved reserves of
approximately 23.7 MMBbls of oil and 241.2 Bcf of natural gas, or a total of
383.2 BCFE, 86% of which were proved developed and 63% of which were natural
gas, with a PV-10 value of $363.8 million. For the year ended December 31, 2001,
we produced 54.1 BCFE representing average daily production of 148.2 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-risk
higher-potential exploration projects 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 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, 1999 through December
31, 2001, we participated in the drilling and recompletion of 622 gross wells
with an average success rate of 83%. During that same period we added estimated
proved reserves of 347 BCFE at an average finding cost of $1.15 per MCFE. Our
average annual production replacement was 251% during this three-year period,
and our production has grown at an average rate of 18% per year over the same
time period.
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As of December 31, 2001, we had an acreage position of 1,192,077 gross
(539,658 net) acres of which 620,540 gross (347,432 net) acres were undeveloped.
For 2002 we have budgeted capital expenditures of $104.0 million for ongoing
development, exploitation and exploration programs in our core operating areas
and $60.0 million for acquisitions of oil and gas properties and acreage.
Our principal offices are located at 1776 Lincoln Street, Suite 1100,
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-risk higher-potential
exploration 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 located
near core properties and are 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 2001 we participated in the drilling and
recompletion of 252 gross drilling wells with an 83% success rate.
o Pursue Higher-Risk Higher-Potential Exploration Projects. We have
allocated approximately 15% of our 2002 drilling and exploration
capital expenditures budget to higher-risk higher-potential
exploration projects 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 exploration projects and generally
limit our capital exposure by participating with other experienced
industry partners. We plan to test several of these prospects in the
Gulf Coast region and Rocky Mountain area during 2002.
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 further
development, exploitation and exploration opportunities based on
proprietary geologic concepts. We believe that the focus on smaller,
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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 completed for stock. We believe that 2002 will be a very active
year for the divestiture of oil and gas properties by larger and/or
financially leveraged industry participants. We have budgeted $60.0
million for acquisitions in 2002.
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, 2001, we operated 58% of our properties on a volume
basis and 54% on a PV-10 value basis. We are the operator of
properties representing approximately 73% of our 2002 drilling
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, 2000
o 2001 Acquisition of Oil and Gas Properties. In November 2001 St.
Mary completed a $40.5 million acquisition of properties from
Choctaw II Oil & Gas, Ltd. The properties are located in our
Williston Basin core area and the Green River Basin in Wyoming and
produce approximately 1,200 barrels of oil and 4,600 Mcf of gas per
day.
o Increase in 2001 Year-End Reserves. As of December 31, 2001 proved
reserves increased 9% from December 31, 2000 levels to 383.2 BCFE.
St. Mary added 35.7 BCFE through acquisitions for cash and 78.6 BCFE
from drilling activities. There were net downward revisions of
previous reserves totaling 24.4 BCFE consisting of 32.1 BCFE due to
price revisions, partially offset by 7.7 BCFE in positive
performance revisions.
o 2001 Acquisition of Coalbed Methane Prospects. In 2001 we acquired
leases covering 115,000 acres in which we own an average 92% 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 46,000 of our 115,000 leased acres. We
will monitor this lawsuit as part of our investigation of
environmental issues related to these prospects.
3
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 a 1/2% contingent interest provision. We
received net proceeds, after deducting the initial purchasers'
discount and estimated offering expenses payalbe by us, of $96.7
million. 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. 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 will use the remaining net proceeds to fund a
portion of our 2002 capital budget.
Major Customers
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. During 1999 sales to Transok accounted for 13.3% of our
total oil and gas production revenue.
Employees and Office Space
As of December 31, 2001, St. Mary had 179 full-time employees. None of
our employees is 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 8,730 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 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.
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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
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, or the FERC, 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
5
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 materially
differently than 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
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.
6
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
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 action is taken that prohibits or restricts offshore drilling
or imposes 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. 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
7
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 OPA.
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, OPA requires responsible parties of 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 United States Department of the Interior Minerals Management
Service. On August 11, 1998, the MMS enacted a final rule implementing these
financial responsibility requirements. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under 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 to 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 Federal National
Pollutant Discharge Elimination System general permits 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 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
8
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.
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;
9
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
approximately 63% of our proved reserves were natural gas reserves as of
December 31, 2001, we are more susceptible to 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 16%
of our total oil and gas production volumes during 2001. 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, 2001
our proved reserves would last for approximately 7.1 years if produced
constantly at the 2001 rate of production. As a result, we must locate and
develop or acquire new oil and gas reserves to replace those being depleted by
production. We must 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 14% of
our total estimated proved reserves at December 31, 2001 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.
10
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 are generally not 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
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 or 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 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 potential 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 $182.9 million for 2001 and $125.2
million during 2000. We have budgeted total capital expenditures of $164.0
million in 2002. With the net proceeds from the sale of senior convertible notes
11
in March 2002 (see Item 7., Management's Discussion and Analysis), cash provided
by operating activities and borrowings under our credit facility, we believe we
will have sufficient cash to fund budgeted capital expenditures in 2002. 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; and
o prices of oil and natural gas.
Issuing equity securities to satisfy our financing requirements could
cause substantial dilution to existing shareholders. Debt financing could lead
to:
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 have a long-term revolving credit facility with a bank group
consisting of Bank of America, Comerica Bank-Texas and Wells Fargo Bank West.
Under the facility, the maximum loan amount is $115.0 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. Since we pay commitment fees based on the unused
portion of the borrowing base, we have limited the borrowing base that we have
accepted to correspond with our actual funding requirements. The accepted
borrowing base under the facility as of December 31, 2001 was $100.0 million.
12
Our next borrowing base redetermination date is scheduled to occur on
or about April 15, 2002. 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
date even if oil or gas prices increase. St. Mary incurred impairment and
abandonment charges on proved and unproved properties of $4.7 million, $6.3
million and $10.6 million in 2001, 2000 and 1999, 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.
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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, 2001 were estimated starting with a calculated weighted
average sales price of $19.84 per barrel of oil (NYMEX) and $2.65 per MMBtu of
gas (Gulf Coast spot price), then adjusted for quality and basis differentials.
During 2001 our realized gas prices were as high as $7.86 per Mcf and as low as
$2.21 per Mcf. 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.
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;
14
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.
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.
15
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.
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
16
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
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.
17
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 working interests and royalty interests in
many of St. Mary's properties, which were earned as part of the prior employer's
employee benefit programs. Those persons have no royalty participation in any
new St. Mary properties.
Mr. Boone also owns 50% of Princeton Resources Ltd. and has a 33%
interest in Baron Oil Corporation, entities that manage the oil and gas working
and royalty interests which he acquired as a result of his prior employment.
Although Mr. Boone does not manage these corporations, he may participate in any
investment decisions made by them.
David C. Dudley, a director of St. Mary, is Operating Manager of Dudley
& Associates, LLC, a closely-held oil and gas exploration and production
firm. From time to time we may compete with Mr. Dudley's firm for acquisition,
exploitation, exploration or development prospects.
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.
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.
18
Our shares that are eligible for future sale may have an adverse effect on the
price of our common stock.
At January 31, 2002 we had 27,777,338 share of common stock
outstanding. Of the shares outstanding, approximately 26,904,006 shares were
freely tradable without substantial restriction or the requirement of future
registration under the Securities Act. In addition, as of that date, options to
purchase 2,151,445 shares were outstanding, of which 1,378,403 were exercisable.
These options are exercisable at prices ranging from $9.25 to $33.3125 per
share. In connection with the private placement of the Notes, our executive
officers and directors have entered into lock-up agreements under which they
have agreed not to offer or sell any shares of our common stock or similar
securities for a period of 90 days from March 7, 2002 without the prior written
consent of the initial purchasers of the Notes. The initial purchasers may at
any time waive the terms of these lock-up agreements. 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 Chairman of the Board and his extended family may be able to control us.
Thomas E. Congdon, our Chairman of the Board, and members of his
extended family currently own approximately 18% of the outstanding shares of our
common stock. 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
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 altogether the payment of dividends.
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;
19
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.
Glossary
The terms defined in this section are used throughout this Form 10-K.
2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
two-dimensional cross-section of the subsurface.
3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used herein in reference to natural gas.
BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Behind pipe reserves. Estimated net proved reserves in a formation in which
production casing has already been set in the wellbore but has not been
perforated and production tested.
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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.
Finding cost. Expressed in dollars per BOE. Finding costs are calculated by
dividing the amount of total capital expenditures for oil and gas activities by
the amount of estimated net proved reserves added during the same period
(including the effect on proved reserves of reserve revisions).
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
of fluid and proppant (usually sand) into the formation under high pressure.
This creates artificial fractures in the reservoir rock, which increases
permeability and porosity.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
Mcf. One thousand cubic feet.
MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMcf. One million cubic feet.
MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
21
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.
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.
22
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 Williston Basin in
North Dakota and Montana; 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, 2001, is shown below.
Estimated Proved Reserves
-----------------------------------------
Oil Gas MMCFE PV-10
------------------ -----------------------
(MBbls) (MMcf) Amount Percent (In thousands) Percent
------- ------- ------- ------- -------------- -------
Mid-Continent Region........... 1,203 119,062 126,281 33.0% $ 126,219 34.7%
ArkLaTex Region................ 1,295 40,940 48,711 12.7% 37,978 10.4%
Gulf Coast and Gulf of Mexico.. 1,025 44,126 50,274 13.1% 63,594 17.5%
Williston Basin................ 16,248 24,376 121,867 31.8% 101,930 28.0%
Permian Basin.................. 3,898 12,727 36,114 9.4% 34,074 9.4%
------- ------- ------- ------- --------- -------
Total.......................... 23,669 241,231 383,247 100.0% $ 363,795 100.0%
======= ======= ======= ======= ========= =======
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 Basin of Oklahoma and Texas. The Mid-Continent region accounted for 33%
of our estimated proved reserves as of December 31, 2001, or 126.3 BCFE, 85% of
which were proved developed and 94% of which were natural gas. We participated
in drilling 88 gross wells in this region in 2001, including 30 wells operated
by us, 83% of which were completed as producers.
St. Mary's development and exploration budget in the Mid-Continent
region for 2002 totals $33.0 million. We plan to operate 28 drilling wells in
the Mid-Continent region during 2002 and to utilize three to four drilling rigs
throughout the year. Our 2002 budget also reflects participation in an
additional 100 to 125 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. We periodically pursue attractive opportunities to
acquire properties from companies that have elected to discontinue operations in
this basin. The $31.6 million acquisition of properties from JN Exploration that
closed in December 2000 is a good example of this type of opportunity.
Approximately one-half of the drilling activities for 2002 will be
focused on low-to-medium-risk development in the Cromwell, Granite Wash,
Osborne, Red Fork and Spiro formations. In addition, approximately one-half of
our 2002 Mid-Continent capital budget is allocated to deeper, higher-potential
wells in the lower Morrow formation below 19,000 feet at the NE Mayfield Field
in Oklahoma and in various other fields within the Morrow and Springer
formations at depths between 10,000 and 16,000 feet.
23
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 2002.
Arkoma Basin. In Coal County, Oklahoma, we have acquired a leasehold
position of 5,700 net acres. In 2001, we spud five gross wells, all of which
were completed as gas wells. The producing formations in this area include the
Booch, Hartshorne, Wapanucka and the Cromwell, which is the deepest formation at
approximately 6,700 feet. Our average working interest for these wells is 98%,
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. We are also actively pursuing additional leasehold
positions within this four township area both through leasing activity and the
acquisition of producing properties.
In February 2002 we acquired oil and gas properties and an 89-mile gas
gathering system in the Arkoma Basin from Merchant Resources #1 L.P. of Houston,
Texas for $7.8 million in cash. The properties include undrilled locations and
are expected to complement other St. Mary properties in the area. The properties
currently produce an estimated 1,200 Mcf of gas and 65 barrels of oil 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 more than $5.5 million of gross oil and gas royalty
revenue in 2001. 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 13% of our estimated proved reserves as of December 31, 2001, or 50.3 BCFE,
90% of which were proved developed and 88% of which were natural gas.
St. Mary's diverse activities in the onshore Gulf Coast and Gulf of
Mexico are managed by our 16-person regional office in Lafayette, Louisiana and
include ongoing development and exploration 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 2002 is $18.0 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 12% to 20% in nine wells that are
producing a total of 130 MMcf per day on a gross basis as of February 12, 2002.
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 Parlange #12 in the deepest field pay ever produced at Judge
Digby with initial rates of 64,000 Mcf per day. The J. Wuertele #2 was also
completed in 2001, at an initial rate of 45,000 Mcf per day. The J. Wuertele #3
was spud on November 15, 2001 and is currently drilling toward a projected total
depth of 22,000 feet. In addition to the drilling activity, multiple
24
recompletions of several wells are anticipated in 2002 in this multi-pay
geologically complex field.
In the Gulf of Mexico, we plan to test a large 3-D target at Matagorda
701 during 2002. Matagorda 701 is located 50 miles northeast of Corpus Christi,
Texas in 110 feet of water. We also plan to test a large fault block on the east
flank of the Matagorda 700 field in 2002.
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 10,357 acres and have an additional 14,557 acres that are
unleased. Our principal operators on the fee properties are BP Amoco, Cabot,
ExxonMobil and Badger Petroleum. We have encouraged development drilling by our
lessees, facilitated the origination of new prospects on acreage not held by
production and stimulated exploration interest in deeper, untested horizons. A
discovery at South Horseshoe Bayou in early 1998 and a subsequent successful
confirmation well in early 1999 established that significant accumulations of
gas are sourced and trapped at depths below 16,000 feet.
Centennial Project. St. Mary participated in a 51 square mile 3-D
seismic survey over the Spindletop field near Beaumont, Texas, which was
completed in 2001. Our partner group has leased or optioned approximately 19,000
acres within the seismic outline. We have a 21% working interest in this
project, which is planned to be a multi-year exploration and development
program. The partner group plans to drill several wells in this project in 2002.
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 13% of our estimated proved reserves as of December 31, 2001, or
48.7 BCFE, 85% of which were proved developed and 84% of which were natural gas.
In 1992, we acquired the ArkLaTex oil and gas properties of T. L. James &
Company, Inc. as well as rights to over 6,000 square miles of proprietary 2-D
seismic data in the region. Much of the Shreveport office's successful
exploration and development programs have derived from niche acquisitions
completed since 1992 totaling $18.2 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 502 producing gross wells, including 98 wells operated by us;
interests in leases totaling approximately 73,500 gross acres; and mineral
servitudes totaling approximately 14,600 gross acres. Activities in the ArkLaTex
region during 2001 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 have expanded into southern
Mississippi where the objective is to leverage our technical expertise in the
Mississippi salt play. St. Mary participated with a 50% working interest in two
successful wells in 2000 in the James Lime play in east Texas, where it
completed the Jones #1 and Jones #2 wells as multi-lateral wells, each with
initial production exceeding 4,000 Mcf per day. We will continue to be active in
this play in 2002.
In 2002 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 30 gross wells in the
ArkLaTex region and are the operator of properties representing approximately
25
75% of our 2002 $14 million drilling capital expenditures budget.
Williston Basin 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.
The Williston Basin region accounted for 32% of our estimated proved reserves as
of December 31, 2001, or 121.9 BCFE, 87% of which were proved developed and 80%
of which were oil.
Our office in Billings, Montana includes a 28-person staff, some of
which have spent over 20 years and their entire careers in the Williston Basin.
A significant portion of the exploration and development in the Williston Basin
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 30 out of 32 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. Seven 3-D surveys are planned for 2002, exceeding the number of surveys
conducted in any prior year.
St. Mary spent $16 million on exploration and development in the
Williston Basin in 2001. In November 2001 we completed a $40.5 million
acquisition of properties from Choctaw II Oil & Gas, Ltd. The properties are
located in our Williston Basin core area and the Green River Basin in Wyoming
and produce approximately 1,200 barrels of oil and 4,600 Mcf of gas per day. Our
2002 Williston Basin exploration and development capital budget is $22.0
million. We plan to drill ten operated wells with working interests ranging from
60% to 100%. We are the operator of properties representing approximately 80% of
our Williston Basin capital budget in 2002.
Permian Basin Region. The Permian Basin area covers a significant
portion of eastern New Mexico and western Texas and is one of the major
producing basins in the United States. The basin includes hundreds of oil fields
undergoing secondary and enhanced 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 $21.9 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% of our estimated proved reserves as of
December 31, 2001, or 36.1 BCFE, of which 81% were proved developed and 65% were
oil.
St. Mary participated in drilling 12 gross wells in 2001 with a 100%
success rate. The East Shugart Delaware Unit waterflood project was initiated in
2000. The initial response from the water injection is anticipated in 2002, and
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 aquired to 1,125 Bbl per day as of February 12,
2002.
Our Permian Basin capital budget for 2002 is $9.0 million. In addition
to drilling four injection wells in the East Shugart Delaware waterflood, two
Morrow test wells are planned in the Parkway field and six in-fill wells are
planned at Ft. Chadbourne. The HJSA top lease on 30,450 acres in Ward County,
Texas became effective on August 5, 2000 and at year-end 2001 was producing
2,800 MCFE per day net to St. Mary. 3-D seismic data over the 50 square mile
26
lease was reprocessed and is currently being evaluated. We believe opportunities
will develop with respect to our non-operated 21.4% interest in this lease.
Other Areas. In 2001 we acquired leases covering 115,000 acres in which
we own an average 92% 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 46,000 of our 115,000 leased acres. We will monitor this lawsuit as
part of our investigation of environmental issues related to these prospects.
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
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 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.
We are also currently investigating other potential unconventional
natural gas projects in the Rocky Mountains.
Acquisitions
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. In December 2000 we completed a
$31.6 million acquisition of oil and gas properties in the Mid-Continent region
from JN Exploration. Also in 2000 we completed $21.5 million of niche
acquisitions in our other core areas. During the last five years we have
completed over $171 million of acquisitions. For 2002 we have budgeted $60.0
27
million for property acquisitions. However, we have the financial capacity to
commit substantially greater resources to purchases should additional
opportunities be identified. In February 2002 we completed a $7.8 million
acquisition of properties in the Arkoma Basin of the Mid-Continent region from
Merchant Resources #1 L.P.
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, 2001, 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
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,
---------------------------------
2001 2000 1999
---- ---- ----
Proved Reserves Data:
Oil (MBbls) 23,669 20,950 18,900
Gas (MMcf) 241,231 225,975 207,642
MMCFE 383,247 351,673 321,042
PV-10 value (in thousands) (1) $ 363,795 $ 1,153,663 $ 351,016
Proved Developed Reserves 86% 87% 84%
Production Replacement 166% 168% 541%
Reserve Life (years) (2) 7.1 6.7 10.3
- ------------------
(1) PV-10 value as of December 31, 2001 was calculated using prices in
effect at December 31, 2001 of $19.84 per barrel of oil (NYMEX) and
$2.65 per MMBtu of gas (Gulf Coast spot price). Both of these prices
were then adjusted for transportation and basis differentials. These
prices were 26 % and 72 % lower, respectively, than prices used to
calculate PV-10 value as of December 31, 2000.
(2) Reserve life represents the estimated proved reserves at the dates
indicated divided by actual production for the preceding 12-month
period. The value as of December 31, 1999 reflects the acquisition of
King Ranch Energy in December 1999.
28
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,
----------------------------
2001 2000 1999
---- ---- ----
Operating Data:
Net production:
Oil (MBbls)................................................. 2,434 2,398 1,383
Gas (MMcf).................................................. 39,491 38,346 22,805
MMCFE....................................................... 54,093 52,731 31,104
Average net daily production:
Oil (Bbls).................................................. 6,667 6,551 3,790
Gas (Mcf)................................................... 108,195 104,769 62,478
MCFE........................................................ 148,199 144,075 85,216
Average sales price (1):
Oil (per Bbl)............................................... $ 23.29 $ 23.53 $ 16.56
Gas (per Mcf)............................................... $ 3.73 $ 3.44 $ 2.21
Additional per MCFE data:
Lease operating expense..................................... $ 0.75 $ 0.48 $ 0.44
Transportation costs........................................ $ 0.04 $ 0.04 $ 0.03
Production taxes............................................ $ 0.23 $ 0.21 $ 0.16
General and administrative.................................. $ 0.22 $ 0.21 $ 0.29
Depreciation, depletion and amortization.................... $ 0.95 $ 0.76 $ 0.73
(1) Includes the effects of St. Mary's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
Productive Wells
As of December 31, 2001, we had interests in 947 gross (319 net)
productive oil wells and 1,396 gross (268 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.
29
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,
------------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
Development:
Oil.................................... 48 14.49 40 17.37 26 10.45
Gas.................................... 154 33.28 107 24.94 105 22.26
Non-productive......................... 31 7.13 31 9.38 14 5.75
233 54.90 178 51.69 145 38.46
--- ----- --- ----- --- -----
Exploratory:
Oil.................................... 3 1.55 6 4.17 1 .20
Gas.................................... 9 1.84 11 3.63 12 3.84
Non-productive......................... 7 2.56 8 4.32 9 2.56
--- ----- --- ----- --- -----
19 5.95 25 12.12 22 6.60
--- ----- --- ----- --- -----
Farmout or non-consent 9 - 8 - 6 -
--- ----- --- ---- --- -----
Total(1) ............................... 261 60.85 211 63.81 173 45.06
=== ===== === ===== === =====
- --------------------------
(1) Does not include 12, 4 and 1 gross wells completed on St. Mary's fee
lands during 2001, 2000 and 1999, respectively.
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, 2001. 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................................ 2,255 399 167 28 2,422 427
Louisiana............................... 98,588 33,493 41,837 13,818 140,425 47,311
Montana................................. 43,135 21,869 191,747 144,870 234,882 166,739
New Mexico.............................. 7,280 2,196 1,320 913 8,600 3,109
North Dakota............................ 55,464 22,080 136,511 67,592 191,975 89,672
Oklahoma................................ 193,443 44,728 53,883 18,940 247,326 63,668
Texas................................... 136,460 48,080 119,252 38,896 255,712 86,976
Wyoming................................. 12,209 3,318 48,415 38,693 60,624 42,011
Other (3) .............................. 2,501 346 8,083 4,884 10,584 5,230
------- ------- ------- ------- ------- -------
551,335 176,509 601,215 328,634 1,152,550 505,143
------- ------- ------- ------- --------- -------
Louisiana Fee Properties................. 10,357 10,357 14,557 14,557 24,914 24,914
Louisiana Mineral Servitudes............. 9,845 5,360 4,768 4,241 14,613 9,601
------- ------- ------- ------- ------- -------
20,202 15,717 19,325 18,798 39,527 34,515
------- ------- ------- ------- ------- -------
Total .............................. 571,537 192,226 620,540 347,432 1,192,077 539,658
======= ======= ======= ======= ========= =======
-----------
(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 44,388 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.
A lawsuit has been filed in the Federal District Court in Montana by an
environmental public interest group seeking the cancellation of all federal
leases related to coalbed methane development issued in the State of Montana
since January 1, 1997 on the grounds of an alleged failure of the federal Bureau
of Land Management to comply with federal environmental laws. The lawsuit
potentially affects 46,000 acres subject to federal leases of the 115,000 acres
in our Hanging Woman Basin coalbed methane project. While we have not been made
a party to the lawsuit and while we believe upon the basis of information
presently available to us that the applicable environmental laws have been
complied with, there is no assurance of the outcome of the lawsuit and therefore
there is no assurance that it will not adversely affect our coalbed methane
prospect. However, even if the Montana federal leases become unavailable, we
anticipate continuing with the Hanging Woman Basin prospect in Wyoming and
obtaining additional non-federal leases in Montana.
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 2001.
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, 2002.
Name Age Position
- ---- --- --------
Thomas E. Congdon 75 Chairman of the Board
Mark A. Hellerstein President and Chief Executive Officer
Ronald D. Boone 54 Executive Vice President and Chief
Operating Officer
Robert T. Hanley 55 Vice President - Business Development
Richard C. Norris 46 Vice President - Finance, Secretary and
Treasurer
Milam Randolph Pharo 49 Vice President - Land and Legal
Garry A. Wilkening 51 Vice President - Administration and
Controller
Douglas W. York 40 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:
Robert T. Hanley has served as Vice President - Business Development
since 2000. Prior to 2000, Mr. Hanley was Chief Financial Officer at Nance
Petroleum Corporation and Panterra Petroleum.
32
Richard C. Norris has served as Vice President - Finance and Secretary
since 1999. Prior to 1999, Mr. Norris was Vice President - Accounting and
Administration and Treasurer. He 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 joined St. Mary in 1993 as Corporate Controller. He
was named Vice President - Administration in 1999. Prior to joining St. Mary,
Mr. Wilkening was Corporate Controller for Fuel Resources Development Company, a
subsidiary of Public Service Company of Colorado (now named Xcel Energy).
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
be removed by the board whenever in its judgement the best interests of the
Company will be served thereby without prejudice, however, to contractual
rights, if any, of the person so removed.
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.
33
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Market Information. St. Mary's common stock is traded on the Nasdaq
National Market System under the symbol MARY. The range of high and low prices
for the quarterly periods in 2001 and 2000, as reported by the Nasdaq National
Market System and adjusted for the two-for-one stock split which was distributed
on September 5, 2000 to shareholders of record as of the close of business on
August 21, 2000, is set forth below:
Quarter Ended High Low
------------- ---- ---
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
December 31, 2000 $34.31 $19.00
September 30, 2000 24.31 14.75
June 30, 2000 21.03 14.78
March 31, 2000 15.75 11.19
Holders. As of January 31, 2002, the number of record holders of St.
Mary's common stock was 214. 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 2001. 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 $2,795,000 in 2001 and $2,775,000 in
2000.
Restricted Shares. St. Mary issued 5,332,374 shares of its common stock
to the shareholders of King Ranch, Inc. for the acquisition of King Ranch
Energy, Inc. in December 1999. Those shares were subject to contractual
restrictions on transfer until March 31, 2001, and are now freely transferable.
We also issued 518,988 restricted shares of our common stock in connection with
the acquisition of Nance Petroleum Corporation in June 1999. Those shares are
restricted securities under federal securities laws and are also subject to
contractual restrictions on transfer, which expire in increments over a
three-year period from the date of acquisition. In addition, in connection with
our March 2002 issuance of 5.75% senior convertible notes, our executive
officers and directors entered into lock-up agreements under which they have
agreed not to offer or sell any shares of our common stock or similar securities
for a period of 90 days from March 7, 2002 without the prior written consent of
the initial purchasers of the notes.
34
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
financial statements included elsewhere in this report.
Years Ended December 31,
------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(In thousands, except per share data)
Income Statement Data:
Operating revenues:
Oil and gas production $ 203,973 $ 188,407 $ 73,387 $ 71,413 $ 76,603
Other 3,496 7,259 1,527 8,096 15,282
--------- --------- --------- --------- ---------
Total operating revenues 207,469 195,666 74,914 79,509 91,885
--------- --------- --------- --------- ---------
Operating expenses:
Oil and gas production 55,000 38,461 19,574 17,770 16,097
Depletion, depreciation & amortization 51,346 40,129 22,574 24,912 18,366
Exploration 19,518 9,633 11,593 11,705 6,847
Impairment of proved properties 820 4,449 3,982 17,483 5,202
Abandonment and impairment of
unproved properties 3,865 1,841 6,616 4,457 2,077
General and administrative 11,762 11,166 9,172 7,097 7,645
Unrealized derivative loss 1,573 - - - - - -
Other 1,673 1,437 1,802 9,304 606
--------- --------- --------- --------- ---------
Total operating expenses 145,557 107,116 75,313 92,728 56,840
--------- --------- --------- --------- ---------
Income (loss) from operations 61,912 88,550 (399) (13,219) 35,045
Non-operating (expense) income 376 737 75 (1,027) (99)
Income tax (expense) benefit (21,829) (33,667) 406 5,415 (12,325)
--------- --------- --------- --------- ---------
Income (loss) from continuing operations 40,459 55,620 82 (8,831) 22,621
Gain on sale of discontinued operations,
net of income taxes - - - 34 488
--------- --------- --------- --------- ---------
Net income (loss) $ 40,459 $ 55,620 $ 82 $ (8,797) $ 23,109
========= ========= ========= ========= =========
Basic net income (loss) per common share:
Income (loss) from continuing operations $ 1.45 $ 2.00 $ - $ (0.40) $ 1.07
Gain on sale of discontinued operations - - - - 0.02
--------- --------- --------- --------- ---------
Basic net income (loss) per share $ 1.45 $ 2.00 $ - $ (0.40) $ 1.09
========= ========= ========= ========= =========
Diluted net income (loss) per common share:
Income (loss) from continuing operations $ 1.42 $ 1.97 $ - $ (0.40) $ 1.05
Gain on sale of discontinued operations - - - - 0.02
--------- --------- --------- --------- ---------
Diluted net income (loss) per share $ 1.42 $ 1.97 $ - $ (0.40) $ 1.07
========= ========= ========= ========= =========
Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10
Basic weighted average common shares
outstanding 27,973 27,781 22,198 21,874 21,240
Diluted weighted average common shares
outstanding 28,555 28,271 22,329 21,874 21,506
35
Years Ended December 31,
------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(In thousands, except per share data)
Balance Sheet Data (end of period):
Working capital $ 34,000 $ 40,639 $ 13,440 $ 9,785 $ 9,618
Net property and equipment 358,930 252,411 180,664 143,825 157,481
Total assets 436,989 321,895 230,438 184,497 212,135
Long-term obligations 64,000 22,000 13,000 19,398 22,607
Total stockholders' equity 286,117 250,136 188,772 134,742 147,932
Other Data:
EBITDA (1) $ 113,258 $ 128,679 $ 22,175 $ 11,693 $ 53,411
Net Cash provided by (used in)
Operating activities 127,492 92,267 40,755 45,386 43,111
Investing activities (159,075) (112,868) (22,243) (36,982) (67,477)
Financing activities 29,080 13,025 (12,138) (7,695) 28,140
Capital and exploration expenditures, cash
and noncash 182,863 125,184 91,184 57,855 89,213
- ------------
(1) EBITDA is defined as earnings before interest income and expense,
income taxes, depreciation, depletion, amortization, and gain on sale
of discontinued operations. EBITDA is a financial measure commonly used
for St. Mary's industry and should not be considered in isolation or as
a substitute for net income, cash flow provided by operating activities
or other income or cash flow data prepared in accordance with generally
accepted accounting principles or as a measure of a company's
profitability or liquidity. Because EBITDA excludes some, but not all,
items that affect net income and may vary among companies, the EBITDA
presented above may not be comparable to similarly titled measures of
other companies.
36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
Overview
The year ended December 31, 2001 was volatile, not only for our
industry, but also for the country as a whole. Spot gas prices per MMBtu ranged
from $9.73 to $1.73. The NYMEX gas strip price fell by more than half. Oil
prices dropped from a per barrel high of $32.00 to $17.50. The economy entered a
recession that was further impacted by the events of September 11th and Enron's
collapse. In our industry, rig utilization moved to effective capacity and
resulted in substantial cost increases and diminished service quality. Operating
costs also increased dramatically. Higher drilling, completion and operating
costs and an overheated acquisition market made reserve additions costly.
Through this turbulent environment we modestly grew production and maintained a
strong balance sheet.
The industry enters 2002 with record gas in storage as well as excess
OPEC capacity and a weakened economy. This suggests to us that we will encounter
weaker prices in the near term. Subject to uncertainties specified in our
cautionary statement about forward looking statements we project that results of
operations for 2002 will reflect lower revenues and lower net income.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operation are
based upon the information reported in our consolidated financial statements.
The preparation of these 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 and Note 11 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 our 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 period we make
estimates of the amount of production delivered to the purchaser and
the price we received. We use our knowledge of our properties, their
historical performance, NYMEX and local spot market prices and other
factors as the basis for these estimates. Variances between our
estimates and the actual amounts received are recorded in the month
payment is received.
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 years from known reservoirs under existing
37
economic and operating conditions. Future cash inflows and future
production and development costs are determined by applying benchmark
prices and costs, including transportation 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 calculation 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 costs change. For any period, unknown circumstances
could have caused us to calculate more or less depletion, depreciation
or impairment. Changes in these 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. Each
company has its own criteria for acceptable internal rates of return,
and those criteria can change overtime. Different pricing assumptions
or discount rates would result in a different calculated impairment.
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. 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. 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.
The following analysis contains additional discussion of management and
accounting policies that are relevant to specific disclosures.
38
Results of Operations
The results of operations for 2000 include the full year impact of two
significant acquisitions made during 1999. On June 1, 1999 St. Mary acquired
Nance and Quanterra Alpha Limited Partnership and then acquired various other
Williston Basin properties later in 1999 and into 2000. On December 17, 1999
St. Mary acquired King Ranch Energy, Inc now named St. Mary Energy Company.
The following table sets forth selected operating data for the periods
indicated:
Years Ended December 31,
------------------------------
2001 2000 1999
---- ---- ----
(In thousands, except per volume data)
Oil and gas production revenues:
Gas production.............................................. $ 147,292 $ 131,979 $ 50,482
Oil production.............................................. 56,681 56,428 22,905
--------- --------- ---------
Total.................................................... $ 203,973 $ 188,407 $ 73,387
========= ========= =========
Net production:
Gas (MMcf).................................................. 39,491 38,346 22,805
Oil (MBbls)................................................. 2,434 2,398 1,383
MMCFE....................................................... 54,093 52,731 31,103
Average sales price (1):
Gas (per Mcf)............................................... $ 3.73 $ 3.44 $ 2.21
Oil (per Bbl)............................................... $ 23.29 $ 23.53 $ 16.56
Oil and gas production costs:
Lease operating expenses.................................... $ 40,505 $ 25,567 $ 13,641
Transportation costs........................................ 2,321 1,817 893
Production taxes............................................ 12,174 11,077 5,040
--------- --------- ---------
Total.................................................... $ 55,000 $ 38,461 $ 19,574
========= ========= =========
Additional per MCFE data:
Sales price (see Discussion under Accounting Matters)....... $ 3.77 $ 3.57 $ 2.36
Lease operating expenses.................................... (0.75) (0.48) (0.44)
Transportation costs........................................ (0.04) (0.04) (0.03)
Production taxes............................................ (0.23) (0.21) (0.16)
--------- --------- ---------
Operating margin......................................... $ 2.75 $ 2.84 $ 1.73
========= ========= =========
Depletion, depreciation and amortization.................... $ 0.95 $ 0.76 $ 0.73
Impairment of proved properties............................. $ 0.02 $ 0.08 $ 0.13
General and administrative.................................. $ 0.22 $ 0.21 $ 0.29
- ---------------
(1) Includes the effects of the Company's hedging activities.
39
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
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. Projections of pricing for oil and gas in
2002 lead us to believe that our average realized price for both gas and oil
will decrease in 2002. 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. It is possible with the contracts we
currently have in place and the December 31, 2001 projections of pricing for
natural gas and oil in 2002 that we will record increases in oil and gas
revenues attributable to hedging in 2002.
Oil and Gas Production Expenses. Oil and gas production expenses
consist of lease operating expenses, production taxes and transportation
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 non-recurring LOE 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 non-recurring LOE 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. This will be an area of concentration for us
in 2002 as we attempt to decrease oil and gas production expenses in total and
on a per MCFE basis.
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.
40
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.
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%
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. In 2002 we have budgeted for geological and geophysical
expenses and expect to incur overhead and other expenses in the pursuit of
exploration, but we generally explore with an expectation of success.
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.
41
2000 to 1999 Comparison
Oil and Gas Production Revenues. St. Mary experienced a record year in
2000 for growth in oil and gas production revenues. This amount increased $115.0
million, or 157% to $188.4 million in 2000 compared to $73.4 million in 1999.
Revenue from gas production increased $81.5 million or 161%. This increase was a
result of a gas production volume increase of 68% and a 56% increase in the
average realized gas price to $3.44 per Mcf in 2000. Revenue from oil production
increased $33.5 million or 146%. This increase resulted from an oil production
volume increase of 73% and a 42% increase in the average realized oil price to
$23.53 per Bbl in 2000. Average net daily production increased to a 12-month
record of 144.1 MMCFE in 2000 compared to 85.2 MMCFE in 1999. Our King Ranch
Energy acquisition and Williston Basin acquisitions since June 1999 have added
$97.0 million of revenue, not adjusted for hedge losses and average net daily
production of 57.7 MMCFE over the prior year. A positive response to a
waterflood at Parkway Delaware Unit combined with a successful gas well
completion and pricing changes in the Permian Basin added 4.6 MMCFE to average
net daily production and $10.9 million of revenue before hedge losses from 1999
to 2000.
St. Mary hedged approximately 55.4% or 1,329 MBbls of its oil
production for 2000 and realized a $13.2 million decrease in oil revenue
attributable to hedging compared to a $2.0 million decrease in 1999. Without
these contracts we would have received an average price of $29.01 per Bbl in
2000 compared to $18.01 per Bbl in 1999. St. Mary also hedged 44.1% of its 2000
gas production or 18.6 million MMBtu and realized a $20.5 million decrease in
gas revenue attributable to hedging compared to a $558,000 decrease in gas
revenues in 1999. Without these contracts we would have received an average
price of $3.97 per Mcf for 2000 compared to $2.19 per Mcf in 1999.
Gain (loss) on Sale of Proved Properties. Gain on sale of proved
properties increased to $3.4 million in 2000 from a loss of $55,000 in 1999. St.
Mary recognized a $1.8 million gain on the sale of shallow production from the
HJSA top lease to the previous operator, a $1.0 million gain from the sale of
various properties at auction and a $455,000 gain on the sale of our share of
the Rock Penn Unit in west Texas.
Gain on sale of KMOC Stock. In February 2000 St. Mary exercised its
option to convert its Khanty Mansiysk Oil Corporation production payment
receivable into common stock of KMOC. In July 2000 we 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 we sold 14,662 of
these shares and recognized a net gain of $2.2 million.
Oil and Gas Production Expenses. Total production costs increased $18.9
million, or 96% in 2000 to $38.5 million compared with $19.6 million in 1999.
The KRE acquisition and Williston Basin acquisitions since June 1999 have added
$15.3 million of production costs over 1999. These costs have also increased by
$2.4 million in the Permian Basin as a result of waterflood activities. Total
production costs per MCFE increased 16% to $0.73 for 2000 compared with $0.63 in
1999. We experienced a general $0.06 per MCFE increase in 2000 as a result of
increased production taxes from increased revenue and an increase in lease
operating costs. The additional $0.04 per MCFE increase was due to lease
operating expenses and increased production taxes on increased revenue in the
higher-cost Williston and Permian Basins.
Depreciation, Depletion, Amortization and Impairment. DD&A
increased $17.6 million or 78% to $40.1 million in 2000 compared with $22.6
million in 1999. DD&A expense per MCFE increased 5% to $0.76 in 2000
compared to $0.73 in 1999. During the first three quarters of 2000 we had
42
reported a decrease in the DD&A rate per MCFE. This decrease was the result
of a lower than average cost per unit from the KRE and Nance acquisitions, the
addition of lower cost reserves from 1999 drilling activities and the effect of
producing property impairments we recognized in the fourth quarter of 1999 and
the first quarter of 2000. In the fourth quarter of 2000 two factors occurred
that reversed this trend. First, we finalized the allocation of KRE acquisition
costs as allowed by accounting standards. Second, year-end downward reserve
adjustments for certain fields caused DD&A per MCFE to increase $0.08 for
the year.
St. Mary recorded a $4.4 million impairment of proved oil and gas
properties in 2000 compared with $4.0 million in 1999. Impairments in 2000
included a declining performance adjustment of $703,000 from the West Cameron
Block 39 prospect in the Gulf of Mexico. Marginal well impairments included
$656,000 from the Midland prospect in south Louisiana, $271,000 for the NE
Collins prospect in Mississippi, $269,000 for the Heil II prospect in Texas and,
in Oklahoma, $478,000 from the Buffalo Wallow prospect, $371,000 from the Boggy
Creek prospect and $490,000 from the SW Weatherford prospect.
Abandonment and impairment of unproved properties decreased $4.8
million or 72% to $1.8 million in 2000 compared to $6.6 million in 1999. This
decrease was due to a reduction in abandonment of expired leases in 2000 and the
1999 impairment of South Horseshoe Bayou.
Exploration. Exploration expense for 2000 decreased $2.0 million or 17%
to $9.6 million compared with $11.6 million in 1999. Percentages of total
exploration expense are as follows:
2000 1999
---- ----
o Geological and geophysical expenses 24% 12%
o Exploratory dry holes 21% 45%
o Overhead and other expenses 55% 43%
General and Administrative. General and administrative expenses
increased $2.0 million or 22% to $11.2 million in 2000 compared to $9.2 million
in 1999. Increases in general and administrative expenses resulting from the KRE
and Nance acquisitions and charitable contributions of $809,000 were partially
offset by a $2.8 million COPAS overhead reimbursement increase related to
operations of the KRE properties and assumption of Permian Basin operations.
Income Taxes. Income tax expense totaled $33.7 million in 2000
resulting in an effective tax rate of 37.7% compared to a net benefit in 1999 of
$406,000. The effective rate change from 1999 reflects a diminished effect from
alternative fuel credits allowed under Internal Revenue Code Section 29 due to
higher net income before tax, additional accrued state income taxes from income
generated by the properties acquired from KRE and an increase in deferred
federal income tax from a 1% rate increase to the highest federal marginal rate.
During 2000 St. Mary determined that it would be more beneficial to forego the
Section 29 credits generated from 1999 resulting in a net operating loss for
1999 that could be utilized in 2000 to reduce its current liability. This change
also impacted the effective rate for 2000.
Net Income. Net income increased to $55.6 million for 2000 compared to
$82,000 for 1999. A 56% increase in gas prices, a 42% increase in oil prices and
a 73% increase in oil production volumes and a 68% increase in gas production
volumes resulted in a record $115.0 million increase in oil and gas production
revenue. A $3.5 million increase in gain on the sale of proved properties and
the $2.2 million gain from the sale of KMOC stock contributed to the $120.8
million increase in total operating revenues. These revenue increases were
offset by corresponding increases in oil and gas production costs and DD&A
as well as a $34.1 million increase in income tax expense.
43
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 the
payment of 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
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.
Cash Flow. St. Mary's net cash provided by operating activities
increased $35.2 million or 38% 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.
St. Mary's net cash provided by operating activities increased $51.6
million or 127% to $92.3 million in 2000 compared to $40.8 million in 1999. The
increase reflects the effect of increases in oil and gas production and prices.
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 used in investing activities increased $90.7 million in 2000
to $112.9 million compared to $22.2 million in 1999. Total 2000 capital
expenditures for cash, including acquisitions of oil and gas properties,
increased $77.6 million or 192% to $117.9 million in 2000 compared to $40.3
million in 1999 due to an increase in drilling activity in 2000 and an increase
in cash expended for oil and gas property purchases.
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
44
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.
Net cash provided by financing activities increased $25.2 million to
$13.0 million in 2000 compared to cash used in financing activities of $12.1
million in 1999. The increase is due to a net $9.0 million increase in long-term
debt during 2000 compared to a $9.8 million decrease in 1999 and a $6.8 million
increase in proceeds received from the sale of common stock related to St.
Mary's stock option programs. Proceeds from stock option programs were used to
finance current operations and retire outstanding debt under the credit
facility. During 2000 cash flow from operations and stock option programs was
sufficient to reduce the outstanding debt balance to zero. The $22.0 million
balance in outstanding debt at December 31, 2000 was a result of the JN
acquisition.
St. Mary had $4.1 million in cash and cash equivalents and had working
capital of $34.0 million as of December 31, 2001 compared to $6.6 million in
cash and cash equivalents and working capital of $40.6 million as of December
31, 2000.
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 1/2% contingent interest provision. We received net proceeds of
$96.7 million after deducting the initial purchasers' discount and estimated
offering expenses payable 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
requring 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. 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. 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 will use the remaining net proceeds to fund a portion of our 2002
capital budget.
Credit Facility. At December 31, 2001 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 depends upon a
borrowing base that the lenders periodically redetermine based on the value of
our oil and gas properties and other assets. As of December 31, 2001 the stated
total possible borrowing base was $170.0 million. However, since we pay
commitment fees based on the unused portion of the borrowing base we have
limited the borrowing base that we have accepted to correspond with our actual
funding requirements. The accepted borrowing base was $100.0 million at December
31, 2001. See discussion below regarding the March 4, 2002 amendment to the
credit facility. The facility has a maturity date of December 31, 2006, and
includes a revolving period that matures on June 30, 2003 at which time all
outstanding borrowings convert to a term loan payable in quarterly installments
through the facility maturity date. We must comply with certain covenants
including maintenance of stockholders' equity at a specified level, restrictions
on additional indebtedness, sales of oil and gas properties, activities outside
our ordinary course of business and certain merger transactions. Our next
borrowing base redetermination is scheduled to occur on or before April 15,
2002.
45
As of December 31, 2001 and 2000, $64.0 million and $22.0 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 (1) the higher of the federal funds
rate plus 1/2% or the prime rate, or (2) LIBOR plus 3/4% when our debt to total
capitalization is less than 30%, up to a maximum of either (a) the higher of the
federal funds rate plus 3/4% or the prime rate plus 1/4%, or (b) LIBOR plus
1-3/8% when our debt to total capitalization is equal to or greater than 50%. At
December 31, 2001 our debt to capitalization ratio as defined under the credit
agreement was 22.4%.
In conjunction with the sale of the Notes discussed above we negotiated
an amendment to the credit facility on March 4, 2002. This amendment sets the
maximum loan amount to $115.0 million. Pursuant to the amendment, during the
revolving period of the loan, loan balances will accrue interest at our option
of either (1) the higher of the federal funds rate plus 1/2% or the prime rate,
plus an additional 1/4% when our debt to capitalization ratio is greater than
50%, or (2) the LIBOR rate plus (a) 1% when our debt to total capitalization
ratio is less than 30%, (b) 1 1/4% when our debt to capitization ratio is
greater than or equal to 30% but less than 40%, (c) 1 3/8% when our debt to
capitalization ratio is greater than or equal to 40% but less than 50%, or (d) 1
5/8% when our debt to capitalization ratio is greater than 50%. Proceeds from
the Notes were used to repay the outstanding balance under the credit facility.
Amounts repaid under the revolving loan provision of the credit facility will be
available for reborrowing, subject to borrowing base limitations until June 30,
2003. Within 30 days after the closing of the Notes we must provide a pledge of
collateral in favor of the banks to secure repayment of any future borrowings
under the facility. Such collateral will consist primarily of security interests
in the oil and gas properties of St. Mary and its subsidiaries.
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 July 2000 our 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.
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 13,
2002 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.
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.
46
Capital and Exploration Expenditures
------------------------------------
For the Years Ended
December 31,
-------------------
2001 2000 1999
---- ---- ----
(In thousands)
Development $ 98,617 $ 48,996 $ 22,166
Exploration 24,506 17,012 20,809
Acquisitions:
Proved 41,188 53,482 33,080
Unproved 18,552 5,694 15,129
-------- -------- --------
Total $182,863 $125,184 $ 91,184
======== ======== ========
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 or to gain a significant acreage and
production foothold in a new basin.
St. Mary's total costs incurred for capital and exploration activities
in 2001 increased $57.7 million or 46% compared to 2000. We spent $141.7 million
in 2001 for unproved property acquisitions and domestic exploration and
development compared to $71.7 million for the comparable period in 2000.
Unproved property acquisitions increased by $12.9 million as a result of general
leasing activity and our acquisition of coalbed methane development leases in
the Hanging Woman Basin of Montana and Wyoming. We have drilled an 18-well pilot
program and are evaluating its results. We are also currently investigating
permitting and environmental issues related to the development. We will be
unable to determine the future potential of this development until we have
completed the evaluation of our pilot program and have resolved all permitting
and environmental issues related to the development. 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 46,000 of our 115,000 leased acres. We will
monitor this lawsuit as part of our investigation of environmental issues
related to these prospects.
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. The net interests we acquired were producing an estimated 1,200 Bbls of
oil and 4,600 Mcf of gas per day when the acquisition was completed.
47
Capital Expenditure Budget. The 2002 capital expenditure budget is $164
million, of which $60 million is allocated for acquisitions. Budgeted ongoing
exploration and development expenditures in 2002 for each of our core areas is
as follows (in millions):
o Mid-Continent region $ 33.0
o Gulf Coast and Gulf of Mexico region $ 18.0
o ArkLaTex region $ 14.0
o Williston Basin $ 22.0
o Permian Basin $ 9.0
o Other $ 8.0
------
Total $104.0
======
We believe that the amount not funded from our internally generated
cash flow in 2002 can be funded from our existing cash, the net proceeds from
the sale of the Notes 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.
Natural Gas and Oil Hedging. 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 $2.75 per Mcf and an oil price in excess of
$22.00 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 35% of total
production but will hedge up to 50% 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.
Including hedges entered into since December 31, 2001 we have the following
swaps in place:
Average Quantity Average
Product Volumes/month Type Fixed price Duration
------- ------------- -------- ----------- --------
Natural Gas 1,467,000 MMBtu $ 2.84 01/02 - 12/02
Natural Gas 168,000 MMBtu $ 3.01 01/03 - 12/03
Natural Gas 59,000 MMBtu $ 3.04 01/04 - 12/04
Oil 88,400 Bbls $ 24.69 01/02 - 12/02
Oil 49,800 Bbls $ 22.67 01/03 - 12/03
The above schedule excludes commodity positions with Enron North
America Corp, which filed for bankruptcy protection in December 2001. Our
unrealized discounted hedge gain due from Enron had grown to $4.5 million at the
end of November 2001. Accounting rules require us to record the ineffective
portion of our hedges in operations. We believe the Enron contracts we owned
became ineffective, due to a change in counterparty risk as of November 13,
2001. Accordingly, we adjusted the fair value downward to the reduced estimated
48
fair value as of that date. A net non-cash loss of $1.6 million was recorded in
the fourth quarter of 2001. The portion of the hedge that had been deferred in
accumulated other comprehensive income immediately prior to the loss of
effectiveness will be recognized as non-cash revenue over the next two years
based on the originally scheduled settlement dates. We have estimated that 80%
of the revenue will be realized in 2002 and 20% will be realized in 2003. We
took all legal steps to preserve our rights under these contracts and sold our
claim at a discounted price in February 2002. Both parties have agreed that any
events resulting in an adjustment in the amount of the claim, as contrasted with
the amount collected, will cause a proportional reimbursement from one party to
the other.
Since the Enron bankruptcy filing, we have further diversified our
hedge positions with various counterparties and require that such counterparties
have clear indications of current financial strength.
KMOC Stock. In January 2002 we sold our remaining KMOC common stock
resulting in a gain of $838,000.
Accounting Matters
On January 1, 2001 we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The adoption of SFAS No. 133 resulted in St. Mary recording a
liability of $45.7 million for the fair value of the derivative instruments at
January 1, 2001. The adoption entry resulted in deferral of the recognition of
this liability to accumulated other comprehensive loss of $28.6 million at
January 1, 2001. For 2001 we recognized a $1.6 million net hedge loss from hedge
ineffectiveness on derivative instruments that were designated and qualified as
cash flow hedging instruments comprised primarily of the loss of effectiveness
on Enron North America Corp. hedge contracts. We anticipate that all hedge
transactions will occur as expected.
In June 2001 the Financial Accounting Standards Board issued SFAS No.
141, "Business Combinations." Under this statement all business combinations
must be accounted for under the purchase method. The pooling method is no longer
allowed. The statement also establishes criteria to assess when to recognize
intangible assets separately from goodwill. SFAS No. 141 is effective for
business combinations initiated after June 30, 2001 and for all business
combinations using the purchase method for which the date of acquisition is
after June 30, 2001. At this time we have no pending business combinations that
would be affected by the adoption of this statement.
In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement addresses the accounting for goodwill and
other intangible assets and provides specific guidance for testing goodwill and
other intangible assets for impairment. This statement is effective for fiscal
years beginning after December 15, 2001. The adoption of this statement did not
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.
49
In August 2001 the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement provides a single
accounting model for long-lived assets to be disposed of and changes the
criteria that would have to be met to classify an asset as held-for-sale. The
statement also requires expected future operating losses from discontinued
operations to be recognized in the periods in which the losses are incurred,
which is a change from the current requirement of recognizing such operating
losses as of the measurement date. The statement is effective January 1, 2002.
The adoption of the statement did not have a material effect on our financial
position or results of operations.
Effects of Inflation and Changing Prices
Within the United States in 2000 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 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. Declining natural gas prices
and volatile oil prices characterized most of 2001. The supply of drilling rigs,
personnel, supplies and services was tight through the first half of the year
and the cost of each of these items continued to increase as the service sector
ran at capacity. At the end of the year, record gas in storage, excess OPEC
capacity and a weakened economy resulted in a decrease in demand for these
services. In the near-term we expect decreased competition for these limited
resources to result in stabilization or decreases 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.
50
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
St. Mary holds derivative contracts and financial instruments that have
cash flow and net income exposure to changes in commodity prices or interest
rates. Financial and commodity-based derivative contracts are used to limit the
risks inherent in some crude oil and natural gas price changes that have an
effect on us. In prior years we have occasionally hedged interest rates, and may
do so in the future should circumstances warrant.
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 audit committee of our board of directors also periodically
reviews these programs.
Commodity Price Risk. St. Mary uses various hedging arrangements to
manage its 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 and
have been adjusted for our hedging of the basis differential accorded to the
pipelines relative to our areas of production.
A hypothetical $.10 change in our year-end market prices for natural
gas swaps and futures contracts on a notional amount of 20.3 million MMBtu would
have caused a potential $1.6 million change in net income (loss) before income
taxes for contracts in place on December 31, 2001. A hypothetical $1.00 change
in the year-end market prices for crude oil swaps and future contracts on a
notional amount of 1.7 MMBbls would have caused a potential $1.5 million
change in net income (loss) before income taxes for oil contracts in place on
December 31, 2001. 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, 2001 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, 2001, we had floating rate debt of $64.0 million and
had no 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 $640,000 before taxes. The results of operations impact
51
may 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 the 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
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item concerning St. Mary's directors
is incorporated by reference to the information provided in St. Mary's
definitive proxy statement for the 2002 annual meeting of shareholders to be
filed within 120 days from December 31, 2001. The information required by this
Item concerning St. Mary's executive officers is included in Part I--Item
4A--Executive Officers of the Registrant.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to
the information provided in St. Mary's definitive proxy statement for the 2002
annual meeting of shareholders to be filed within 120 days from December 31,
2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by this Item is incorporated by reference to
the information provided in St. Mary's definitive proxy statement for the 2002
annual meeting of shareholders to be filed within 120 days from December 31,
2001.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference to
the information provided in St. Mary's definitive proxy statement for the 2002
annual meeting of shareholders to be filed within 120 days from December 31,
2001.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
52
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
Report of Independent Public Accountants...............................F-1
Consolidated Balance Sheets............................................F-2
Consolidated Statements of Operations..................................F-3
Consolidated Statements of Stockholders' Equity and Comprehensive
Income............................................................... F-4
Consolidated Statements of Cash Flows..................................F-5
Notes to Consolidated Financial Statements.............................F-7
All other schedules are omitted because the required information is not
applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.
(b) Reports on Form 8-K. One report on Form 8-K dated December 10, 2001 was
filed during the last quarter of 2001. This report on Form 8-K included Item 2
and Item 7 regarding the acquisition of oil and gas properties from Choctaw II
Oil & Gas, LTD.
(c) Exhibits. The following exhibits are filed with or incorporated by
reference into this report on Form 10-K:
Exhibit
Number Description
------- -----------
2.1 Agreement and Plan of Merger dated July 27, 1999 among St. Mary
Land & Exploration Company, St. Mary Acquisition
Corporation, King Ranch, Inc. and King Ranch Energy, Inc. as
amended by Amendment No. 1 and Amendment No. 2 to Agreement
and Plan of Merger dated November 8, 1999 (included as Annex A
to the joint proxy/consent statement and prospectus contained
in the registrant's Amendment 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)
53
Exhibit
Number Description
------- -----------
4.1 St. Mary Land & Exploration Company Shareholder Rights Plan
adopted on July 15, 1999 (filed as Exhibit 4.1 to the
registrant's Quarterly Report on Form 10-Q/A (File No. 0-20872)
for the quarter ended June 30, 1999 and incorporated herein by
reference)
4.2* First Amendment to Shareholder Rights Plan dated March 15, 2002,
as adopted by the Board of Directors on July 19, 2001.
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)
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 25, 1999 (filed as Exhibit 10.2 to registrant's
Quarterly Report on Form 10-Q (File No. 0-20872) for the quarter
ended March 31, 1999 and incorporated herein by reference)
10.9 St. Mary Land & Exploration Company Incentive Stock Option
Plan, As Amended on March 25, 1999 (filed as Exhibit 10.1 to
registrant's Quarterly Report on Form 10-Q (File No. 0-20872)
for the quarter ended March 31, 1999 and incorporated herein by
reference)
10.10 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 10.13 to the registrant's Registration
Statement on Form S-1 (Registration No. 33-53512) and
incorporated herein by reference)
54
Exhibit
Number Description
------- -----------
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
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)
55
Exhibit
Number Description
------- -----------
10.25* Registration Rights Agreement between St. Mary Land &
Exploration Company and Bear, Stearns & Co. Inc., et al
dated March 13, 2002
10.26* St. Mary Land & Exploration Company 5.75% Senior Convertible
Notes Due 2022 Indenture dated March 13, 2002
10.27* First Amendment to Credit Agreement dated December 22, 1998
10.28* Fourth Amendment to Credit Agreement dated March 4, 2002
21.1* Subsidiaries of Registrant
23.1* Consent of Arthur Andersen LLP
23.2* Consent of Ryder Scott Company, L.P.
24.1* Power of Attorney (included on signature page of this document)
- --------------------
* Filed with this Form 10-K.
(d) Financial Statement Schedules. See Item 14(c) above.
56
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.
F-1
ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY DATA
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
ASSETS December 31,
------------------------
2001 2000
------ ------
Current assets:
Cash and cash equivalents $ 4,116 $ 6,619
Accounts receivable 46,484 55,068
Prepaid expenses and other 2,337 2,134
Accrued derivative asset 8,194 -
Refundable income taxes 11,090 -
Deferred income taxes - 163
----------- -----------
Total current assets 72,221 63,984
----------- -----------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 518,912 385,076
Less accumulated depletion, depreciation and amortization (216,288) (171,412)
Unproved oil and gas properties, net of impairment allowance
of $8,908 in 2001 and $7,956 in 2000 53,054 35,497
Other property and equipment, net of accumulated depreciation of $3,120
in 2001 and $3,600 in 2000 3,252 3,250
----------- -----------
358,930 252,411
----------- -----------
Other assets:
Khanty Mansiysk Oil Corporation stock 1,651 1,651
Other assets 4,187 3,849
----------- -----------
5,838 5,500
----------- -----------
$ 436,989 $ 321,895
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 34,858 $ 23,345
Deferred tax liability 3,363 -
----------- -----------
Total current liabilities 38,221 23,345
----------- -----------
Long-term liabilities:
Long-term debt 64,000 22,000
Deferred income taxes 47,685 24,820
Other noncurrent liabilities 255 987
----------- -----------
111,940 47,807
----------- -----------
Commitments and contingencies (Notes 1,6,7,8,10)
----------- -----------
Minority interest 711 607
----------- -----------
Stockholders' equity:
Common stock, $0.01 par value: authorized - 100,000,000 shares; issued and
outstanding - 28,779,808 shares in 2001 and 28,553,826 shares in 2000 288 286
Additional paid-in capital 137,384 132,973
Treasury stock - at cost: 1,009,900 shares in 2001 and 395,600 shares in 2000 (16,210) (3,339)
Retained earnings 157,739 120,075
Accumulated other comprehensive income 6,916 141
----------- -----------
Total stockholders' equity 286,117 250,136
----------- -----------
$ 436,989 $ 321,895
=========== ===========
The accompanying notes are an integral part
of these consolidated financial statements.
F-2
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
-----------------------------------
2001 2000 1999
------ ------ ------
Operating revenues:
Oil and gas production $ 203,973 $ 188,407 $73,387
Gain (loss) on sale of proved properties 367 3,404 (55)
Other oil and gas revenue 2,166 1,421 1,166
Gain on sale of KMOC stock - 2,156 -
Other revenues 963 278 416
-------- -------- --------
Total operating revenues 207,469 195,666 74,914
-------- -------- --------
Operating expenses:
Oil and gas production 55,000 38,461 19,574
Depletion, depreciation and amortization 51,346 40,129 22,574
Exploration 19,518 9,633 11,593
Impairment of proved properties 820 4,449 3,982
Abandonment and impairment of unproved properties 3,865 1,841 6,616
General and administrative 11,762 11,166 9,172
Unrealized derivative loss 1,573 - -
Other 1,673 1,437 1,802
-------- -------- --------
Total operating expenses 145,557 107,116 75,313
-------- -------- --------
Income (loss) from operations 61,912 88,550 (399)
Nonoperating income (expense):
Interest income 466 897 1,008
Interest expense (90) (160) (933)
-------- -------- --------
Income (loss) before income taxes 62,288 89,287 (324)
Income tax expense (benefit) 21,829 33,667 (406)
-------- -------- --------
Net income $ 40,459 $ 55,620 $ 82
======== ======== ========
Basic net income per common share $ 1.45 $ 2.00 $ -
======== ======== ========
Diluted net income per common share $ 1.42 $ 1.97 $ -
======== ======== ========
Basic weighted average shares outstanding 27,973 27,781 22,198
======== ======== ========
Diluted weighted average shares outstanding 28,555 28,271 22,329
======== ======== ========
The accompanying notes are an integral part
of these consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share amounts)
Accumulated
Additional Other Total
Common Stock Paid-in Retained Treasury Stock Comprehensive Stockholders'
------------------ ---------------------
Shares Amount Capital Earnings Shares Amount Income Equity
---------- --------- ---------- ---------- ---------- ---------- ------------ ----------
Balance, December 31, 1998 21,984,894 $ 220 $ 67,651 $ 69,341 (295,600) $ (2,470) $ - $ 134,742
Comprehensive income:
Net Income - - - 82 - - - 82
Unrealized net gain on marketable
equity securities available for sale - - - - - - 284 284
----------
Total comprehensive income 366
----------
Cash dividends, $ 0.10 per share - - - (2,193) - - - (2,193)
Treasury stock purchases - - - - (70,000) (525) - (525)
Issuance for Employee Stock
Purchase Plan 32,794 - 258 - - - - 258
Employee Stock Purchase Plan
disqualified distributions - - 20 - - - - 20
Sale of common stock, including income
tax benefit of stock option exercises 17,660 - 123 - - - - 123
Directors' stock compensation 7,200 - 57 - - - - 57
Issuance for Acquisition of Nance
Petroleum Corporation 518,988 6 3,086 - - - - 3,092
Issuance for Acquisition of King
Ranch Energy, Inc. 5,332,374 53 52,779 - - - - 52,832
---------- --------- --------- -------- --------- -------- ---------- ---------
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
Employee Stock Purchase Plan
disqualified distributions - - 3 - - - - 3
Sale of common stock, including income
tax benefit of stock option exercise 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)
Cumulative effect of adoption of
accounting principle - - - - - - (28,587) (28,587)
Change in derivative instrument fair value - - - - - - 35,494 35,494
---------
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 exercise 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
========== ======== ========== ========= ========== ========== ========== ===========
The accompanying notes are an integral part
of these consolidated financial statements.
F-4
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
---------------------------------------
2001 2000 1999
------ ------ ------
Reconciliation of net income to net cash provided
by operating activities:
Net income $ 40,459 $ 55,620 $ 82
Adjustments to reconcile net income to net
cash provided by operating activities:
Gain on sale of KMOC stock - (2,156) -
(Gain) loss on sale of proved properties (367) (3,404) 55
Unrealized derivative loss 1,573 - -
Depletion, depreciation and amortization 51,346 40,129 22,574
Impairment of proved properties 820 4,449 3,982
Exploratory dry hole expense 9,028 789 4,759
Abandonment and impairment of unproved properties 3,865 1,841 6,616
Deferred income taxes 23,726 21,348 (898)
Minority interest and other (1,327) 1,260 29
-------- -------- --------
129,123 119,876 37,199
Changes in current assets and liabilities:
Accounts receivable (629) (23,138) 4,983
Prepaid expenses and other (11,754) 254 1,118
Accounts payable and accrued expenses 10,752 (4,652) (2,580)
Other - (73) 35
-------- -------- --------
Net cash provided by operating activities 127,492 92,267 40,755
-------- -------- --------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 4,771 3,573 1,056
Capital expenditures (131,680) (65,241) (34,994)
Acquisition of oil and gas properties (39,124) (52,076) (5,294)
Proceeds from distribution of KMOC stock 6,960 - -
Sale of Chelsea Corporation - - 2,066
Receipts from restricted cash - - 720
Investment in St. Mary Energy Company - (420) 12,068
Other (2) 1,296 2,135
-------- -------- --------
Net cash used in investing activities (159,075) (112,868) (22,243)
-------- -------- --------
Cash flows from financing activities:
Proceeds from long-term debt 147,050 45,050 29,750
Repayment of long-term debt (105,050) (36,050) (39,537)
Proceeds from sale of common stock 2,746 7,143 311
Repurchase of common stock (12,871) (344) (525)
Dividends paid (2,795) (2,775) (2,193)
Other - 1 56
-------- -------- --------
Net cash provided by (used in) financing activities 29,080 13,025 (12,138)
-------- -------- --------
Net change in cash and cash equivalents (2,503) (7,576) 6,374
Cash and cash equivalents at beginning of period 6,619 14,195 7,821
-------- -------- --------
Cash and cash equivalents at end of period $ 4,116 $ 6,619 $ 14,195
======== ======== ========
The accompanying notes are an integral part
of these consolidated financial statements.
F-5
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Supplemental schedule of additional cash flow information and noncash
activities:
For the Years Ended December 31,
----------------------------------------
2001 2000 1999
------ ------ ------
(in thousands)
Cash paid for interest $ 539 $ 764 $ 916
Cash paid for income taxes 10,355 11,205 92
Cash paid for exploration expenses 19,518 9,032 11,826
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.
In December 1999 the Company acquired St. Mary Energy Company (formerly
known as King Ranch Energy, Inc.) for 5,332,374 shares of the Company's
common stock valued at $52,832,000. The acquisition was accounted for as a
purchase.
Following is a table of the noncash items acquired in the 1999 purchases
of Nance Petroleum Corporation and King Ranch Energy, Inc. (in thousands):
Nance King Ranch
Petroleum Energy
--------- ----------
Accounts receivable & other assets $ 789 $ 9,772
Property & equipment 6,365 25,056
Accounts payable (642) (4,490)
Deferred income taxes (667) 10,426
Long-term debt (3,389) -
In June 1999 the Company acquired Nance Petroleum Corporation and
Quanterra Alpha Limited Partnership for 518,988 shares of the Company's
common stock valued at $3,091,000 together with the assumption of
$3,389,000 of Nance Petroleum Corporation debt. The acquisition was
accounted for as a purchase.
In January 1999 the Company issued 7,200 shares of common stock to its
directors and recorded compensation expense of $54,612.
The accompanying notes are an integral part
of these consolidated financial statements.
F-6
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001
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:
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.
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. Subsidiaries that are not
wholly-owned are accounted for using full consolidation with minority interest
or by the equity or cost method as appropriate. All significant intercompany
accounts and transactions have been eliminated.
The Company accounts for its investment in Summo Minerals Corporation
("Summo") under the cost method of accounting. The accounting for this
investment was changed from the equity method to the cost method in June 1999
after a transfer of common shares that reduced the Company's ownership
percentage below 20%. The Company's interests in other oil and gas ventures and
partnerships are accounted for using full consolidation with minority interest,
including its 58% investment in Box Church Gas Gathering, LLC. The Company's 90%
interest in Roswell, LLC was accounted for using full consolidation with
minority interest until December 2000 when the remaining 10% interest was
purchased. The Company's 74% investment in Panterra Petroleum ("Panterra") was
proportionately consolidated until June 1999 when the remaining 26% was acquired
through the purchase of Nance Petroleum Corporation ("Nance").
Cash and Cash Equivalents:
The Company considers all highly liquid investments purchased with an
initial maturity of three months or less to be cash equivalents. The carrying
value of cash and cash equivalents approximates fair value because the
instruments have maturity dates of three months or less.
Concentration of Credit Risk:
Substantially all of the Company's receivables are within the oil and
gas industry, primarily from purchasers of oil and gas and from joint interest
owners. Although diversified within many companies, collectability is dependent
upon the general economic conditions of the industry. The receivables are not
collateralized, and to date the Company has had minimal bad debts.
The Company has accounts with separate banks in Denver, Colorado;
Shreveport, Louisiana; Tulsa, Oklahoma; Lafayette, Louisiana; and Billings,
F-7
Montana. At December 31, 2001 and 2000, the Company had $6,576,000 and
$11,093,000 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 $9,500,000 as of December 31, 2001 based on total
expected abandonment costs of $10,251,000 and a liability of $9,500,000 as of
December 31, 2000 based on total expected abandonment costs of $10,611,000. This
liability is included in accumulated DD&A on the consolidated balance
sheets. The Company recorded $313,000, $1,988,000 and $34,000 of offshore
abandonment liability accretion as part of DD&A expense in the consolidated
statements of operations for the years ended December 31, 2001, 2000 and 1999,
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 2001, 2000 and 1999 the Company recorded impairment charges for
proved properties of $820,000, $4,449,000 and $3,982,000, 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.
F-8
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 $984,000 at December 31, 2001
and $1,035,000 at December 31, 2000 are included in other assets in the
accompanying balance sheets. The Company also reduces revenue for gas sold by
the Company that cannot be volumetrically balanced in the future due to
insufficient remaining reserves. Related payables totaling $353,000 at December
31, 2001 and $335,000 at December 31, 2000 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).
Financial Instruments:
Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," was 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 31, 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.
The Company seeks to protect its rate of return on acquisitions of
producing properties or drilling prospects by hedging cash flow when the
economic criteria from its evaluation and pricing model indicate it would be
appropriate. The derivative instruments used for this purpose are designated and
qualify as cash flow hedging instruments under SFAS No. 133. Management's
strategy is to hedge cash flows from investments currently requiring a gas price
in excess of $2.75 per Mcf and an oil price in excess of $22.00 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 35% of its total production but will hedge up to
50% 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 for additional discussion
of derivatives.
F-9
Income Taxes:
Deferred income taxes are provided on the difference between the tax
basis of an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively.
Earnings Per Share:
Basic net income per common share of stock is calculated by dividing
net income by the weighted average of common shares outstanding during each
year. Diluted net income per common share of stock is calculated by dividing net
income by the weighted average of common shares outstanding and other dilutive
securities. Dilutive securities of the Company consist entirely of outstanding
options to purchase the Company's common stock. The outstanding dilutive
securities for the years ended December 31, 2001, 2000 and 1999 were 582,313,
490,288 and 131,356, respectively. Antidilutive options not considered in the
diluted net income per share calculation were 625,492, 0 and 513,855 for the
years ended December 31, 2001, 2000 and 1999.
Stock-Based Compensation:
The Company accounts for stock-based compensation using the intrinsic
value method prescribed in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB No. 25") and related
interpretations. Compensation expense for stock options, if any, is measured as
the excess of the quoted market price of the Company's stock at the date of
grant over the amount an employee must pay to acquire the stock.
SFAS No. 123, "Accounting for Stock-Based Compensation," established
accounting and disclosure requirements using a fair-value-based method of
accounting for stock-based employee compensation plans. The Company has elected
to remain on its current method of accounting as described above, and has
adopted the disclosure requirements of SFAS No. 123.
Comprehensive Income:
Comprehensive income consists of net income and unrealized gains and
losses on marketable equity securities held for sale and the effective component
of derivative instruments (net of tax) classified as cash flow hedges.
Comprehensive income is presented in the consolidated statements of
stockholders' equity and comprehensive income.
Major Customers:
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
individually accounted for 22.3% of the Company's total oil and gas production
revenue. During 1999 one customer individually accounted for 13.3% 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-10
Use of Estimates in the Preparation of Financial Statements:
The preparation of financial statements in conformity with accounting
principles generally accepted in the United Stated 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.
Reclassifications:
Certain amounts in the 2000 and 1999 consolidated financial statements
have been reclassified to correspond to the 2001 presentation.
Recently Issued Accounting Standards:
In June 2001 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations." Under this statement all business
combinations must be accounted for under the purchase method. The pooling method
is no longer allowed. The statement also establishes criteria to assess when to
recognize intangible assets separately from goodwill. SFAS No. 141 is effective
for business combinations initiated after June 30, 2001 and for all business
combinations using the purchase method for which the date of acquisition is
after June 30, 2001. At this time we have no pending business combinations that
would be affected by the adoption of this statement.
In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement addresses the accounting for goodwill and
other intangible assets and provides specific guidance for testing goodwill and
other intangible assets for impairment. This statement is effective for fiscal
years beginning after December 15, 2001. The adoption of this statement did not
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.
In August 2001 the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement provides a single
accounting model for long-lived assets to be disposed of and changes the
criteria that would have to be met to classify an asset as held-for-sale. The
statement also requires expected future operating losses from discontinued
operations to be recognized in the periods in which the losses are incurred,
which is a change from the current requirement of recognizing such operating
losses as of the measurement date. The statement is effective January 1, 2002.
The adoption of the statement did not have a material effect on our financial
position or results of operations.
F-11
2. Accounts Receivable:
Accounts receivable are composed of the following:
December 31,
-------------------------------------------
2001 2000
------------------- -----------------
(In thousands)
Accrued oil and gas sales $ 29,041 $ 38,159
Due from joint interest owners 17,042 6,497
Receivable for sale of KMOC stock - 7,009
Other 401 3,403
------------------- -----------------
Total accounts receivable $ 46,484 $ 55,068
=================== =================
3. Acquisitions
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
in cash after normal purchase price adjustments. The Company utilized cash on
hand and a portion of its existing credit facility with Bank of America to fund
the acquisition. The transaction was accounted for as a purchase.
On December 17, 1999 the Company completed the purchase of King Ranch
Energy, Inc. ("KRE") for 5,332,374 shares of common stock valued at $52,832,000
together with transaction costs of $2,339,000. After the acquisition KRE's name
was changed to St. Mary Energy Company. The acquired properties are located
primarily in the Gulf of Mexico and the onshore Gulf Coast. The KRE acquisition
has been accounted for by the purchase method of accounting and, accordingly,
the results of operations of KRE beginning December 17, 1999 are included in the
accompanying consolidated financial statements.
On June 1, 1999 the Company completed the purchase of Nance Petroleum
Corporation and Quanterra Alpha Limited Partnership for 518,988 shares of the
Company's common stock valued at $3,091,000 together with transaction costs of
$56,000 and the assumption of $3,189,000 of Nance debt. The acquisition included
the 26% of Panterra the Company did not previously own, as well as certain other
properties. The properties acquired are located in the Williston Basin of
Montana and North Dakota. The acquisition was accounted for as a purchase.
F-12
4. Income Taxes:
The provision for income taxes consists of the following:
For the Years Ended December 31,
-------------------------------------------
2001 2000 1999
--------- --------- ---------
(In thousands)
Current taxes:
Federal $ 1,114 $ 11,194 $ 219
State 620 1,181 315
Deferred taxes 20,095 21,292 (940)
--------- ---------- ---------
Total income tax expense (benefit) $ 21,829 $ 33,667 $ (406)
========= ========== =========
The above taxes are net of alternative fuels credits (Internal Revenue
Code Section 29) of $185,000 in 2001, $79,000 in 2000, and $283,000 in 1999.
Additionally, current federal tax does not reflect the tax benefit for
deductions from stock option exercises of $930,000 in 2001, $1,771,000 in 2000
and $36,000 in 1999. Net federal taxes payable for the years ended December 31,
2001, 2000 and 1999 were $184,000, $9,423,000 and $183,000, respectively, and
have been reduced by the tax benefit of stock option exercises.
The components of the net deferred tax liability are as follows:
December 31,
--------------------------------
2001 2000
--------- ---------
(In thousands)
Deferred tax liabilities:
Oil and gas properties $ 54,104 $ 32,031
Derivative instruments 3,903 -
Other 147 282
--------- ---------
Total deferred tax liabilities 58,154 32,313
--------- ---------
Deferred tax assets:
Other, primarily employee benefits 1,716 5,005
State tax net operating loss carryforward 1,915 1,006
State and federal income tax benefit 3,497 1,817
Alternative minimum tax credit carryforward 184 -
--------- ---------
Total deferred tax assets 7,312 7,828
Valuation allowance (206) (172)
--------- ---------
Net deferred tax assets 7,106 7,656
--------- ---------
Total net deferred tax liabilities 51,048 24,657
Current deferred income tax assets (liabilities) (3,363) 163
--------- ---------
Non-current net deferred tax liabilities $ 47,685 $ 24,820
========= =========
Current refundable income taxes
(current income taxes payable) $ 11,090 $ (1,162)
========= =========
In accordance with SFAS No. 109, "Accounting for Income Taxes," 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 stock acquisition and recorded a $10,426,000 decrease for
F-13
its KRE stock acquisition, as Nance's book basis was greater than its tax basis,
and KRE's tax basis was greater than its book basis. During 2000 the Company
recorded a $2,972,000 increase in the KRE adjustment to reflect the utilization
of additional tax benefits of KRE by King Ranch, Inc on its 1999 federal
consolidated income tax return. There were no purchase adjustments to the
Company's long-term deferred income tax liability accounts in 2001.
At December 31, 2001, the Company had state net operating loss
carryforwards of approximately $40,300,000 that expire between 2002 and 2017.
The Company's valuation allowance relates in part to its state net operating
loss carryforwards, since the Company anticipates that a portion of the
carryovers from prior years will expire before they can be utilized, and in part
to a portion of the anticipated state benefit from federal income tax expense
incurred as the Company's existing taxable temporary differences reverse. The
net change in valuation allowance in 2001 results from the state benefit of
federal income tax that is now offset by reversing state temporary differences.
Income tax expense and benefit differs from the amount that would be
provided by applying the statutory federal income tax rate to income before
income taxes for the following reasons:
For the Years Ended December 31,
--------------------------------
2001 2000 1999
--------- --------- ---------
(In thousands)
Federal statutory taxes $ 20,420 $ 30,267 $ (137)
Increase (decrease) in taxes resulting from:
State taxes (net of federal benefit) 2,017 4,342 105
Statutory depletion (238) (71) (110)
Alternative fuels credits (Section 29) (185) (79) (283)
Change in valuation allowance 34 (826) (17)
Other (219) 34 36
--------- --------- ---------
Income tax expense (benefit) from
continuing operations $ 21,829 $ 33,667 $ (406)
========= ========= =========
5. Long-term Debt and Notes Payable:
On March 4, 2002 St. Mary entered into an agreement to amend the
existing long-term revolving credit agreement that set the maximum loan amount
at $115.0 million (unaudited). 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 $100.0 million at
December 31, 2001. 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. As of December 31, 2001 and 2000, $64.0 million and
$22.0 million, respectively, was outstanding under this credit agreement. These
outstanding balances accrue interest at rates determined by St. Mary's debt to
total capitalization ratio. During the revolving period of the loan, loan
balances accrue interest at the Company's option of either (1) the higher of the
federal funds rate plus 1/2% or the prime rate, plus an additional 1/4% when the
Company's debt to capitalization ratio is greater than 50%, or (2) the LIBOR
rate plus (a) 1% when the Company's debt to toatl capitalization ratio is less
than 30%, (b) 1 1/4% when the Company's debt to capitalization ratio is greater
than or equal to 30% but less than 40%, (c) 1 3/8% when the Company's debt to
capitalization ratio is greater than or equal to 40% but less than 50%, or (d) 1
5/8% when the Company's debt to capitalization ratio is greater than 50%.The
debt to total capitalization ratio as defined under the agreement was 22.4% as
F-14
of December 31, 2001. The weighted average interest rate paid in 2001 was 5.9%
including commitment fees paid on the unused portion of the borrowing base.
The carrying value of long-term debt approximates fair value because
the debt is variable rate and reprices in the short term.
The Company's estimated annual principal payments under the credit
agreement for the next five years are as follows:
Years Ending
December 31, (In thousands)
----------------------- ------------------
2002 $ -
2003 6,400
2004 12,800
2005 12,800
2006 32,000
---------
Total $ 64,000
=========
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 noncancelable annual
subleases with affiliates of approximately $122,016 for the same term as the
Company's primary office lease. Rent expense, net of sublease income, was
$839,000, $782,000 and $611,000 in 2001, 2000 and 1999, 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)
------------------ ------------------
2002 $ 931
2003 1,129
2004 866
2005 743
2006 743
Thereafter 3,502
-----
Total $ 7,914
=====
7. Compensation Plans:
In January 1992 the Company adopted two compensation plans for key
employees. A cash bonus plan allows participants to receive up to 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 $170,000
for cash bonuses in 2001 that will be paid in 2002, $1,957,000 for cash bonuses
in 2000 that were paid in 2001, and $2,293,000 for cash bonuses in 1999 that
were paid in 2000. A net profits interest bonus plan allows participants to
receive an aggregate 10% net profits interest after the Company has recovered
100% of its investment in various pools of oil and gas wells completed or
acquired during a given year. This interest increases to 20% after the Company
recovers 200% of its investment. The Company records compensation expense once
it recovers its investment and net profits attributable to the properties are
payable to the employees. The Company recorded compensation expense of
$5,259,000 in 2001, $877,000 in 2000 and $574,000 in 1999 relating to the net
profits interest bonus plan.
F-15
In March 1992 the Company adopted a stock appreciation rights ("SAR")
plan for officers and directors. SARs vest over a four-year period, with payment
occurring five years after the date of grant. Between 1993 and 1996 the Company
awarded a total of 342,824 share rights with values ranging from $5.75 to $7.00
per share. Compensation expense recognized under the SAR plan was $12,000 in
2000 and $280,000 in 1999. In November 1996 the Company terminated future awards
under the Company's SAR plan and capped the value of the share rights under the
SAR plan at the then fair market value of the Company's common stock of $10.25
per share. SAR compensation expense recorded after the termination of future
awards related to the vesting of SARs outstanding at the time of the termination
of future awards and to the fluctuation of the stock price below the capped
price. The final SAR payments were made in February 2001. No compensation
expense was recognized under the SAR plan in 2001.
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 9% of their base
salaries. The Company matches each employee's contributions up to 6% of the
employee's base salary and also may make additional contributions at its
discretion. The Company's contributions to the 401(k) Plan were $559,000,
$412,000, and $288,000 for the years ended December 31, 2001, 2000, and 1999,
respectively.
In September 1997 the Board of Directors approved the St. Mary Land
& Exploration Company Employee Stock Purchase Plan ("Stock Purchase Plan"),
which became effective January 1, 1998. Under the Stock Purchase Plan eligible
employees may purchase shares of the Company's common stock through payroll
deductions of up to 15% of eligible compensation. The purchase price of the
stock is 85% of the lower of the fair market value of the stock on the first or
last day of the purchase period. The Stock Purchase Plan is intended to qualify
under Section 423 of the Internal Revenue Code. The Company has set aside
1,000,000 shares of its common stock to be available for issuance under the
Stock Purchase Plan. In 2001, 2000 and 1999 shares issued under the Stock
Purchase Plan totaled 29,772, 32,296 and 32,794, respectively. Total proceeds to
the Company for the issuance of these shares were $575,000, $311,000 and
$258,000 in 2001, 2000 and 1999, respectively. The Company recorded compensation
expense of $20,000, $3,000 and $20,000 in 2001, 2000 and 1999, respectively, due
to nonqualified dispositions of stock acquired by employees under the Stock
Purchase Plan.
In 1990 and 1991 the Company granted certain officers options to
acquire 109,228 shares of common stock at an exercise price of $1.65 per share.
All of these options had been exercised by December 31, 2000.
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. In 1999 the Company granted 623,492
options at an exercise price of $12.38 per share, and 7,660 options were
exercised under the Option Plans. In 2000 the Company granted 653,848 options at
an exercise price of $33.31 per share, and 589,220 options were exercised under
the Option Plans. In 2001 the Company granted 175,729 options at an exercise
price of $15.93 per share and 221,280 options at an exercise price of $21.19 per
share. During 2001 190,289 options were exercised under the Option Plans. All
options granted to date under the Option Plans have been granted at exercise
prices equal to the respective market prices of the Company's common stock on
the grant dates.
F-16
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,
------------------------------------------------------------------------------
2001 2000 1999
-------------------------- ------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------- ------------ ------------ ------------ ------------ ------------
Outstanding at beginning of year 1,986,124 $ 18.95 1,998,254 $ 11.63 1,442,436 $ 11.28
Granted 397,009 18.86 653,848 33.31 623,492 12.38
Exercised 187,810 11.57 619,220 11.05 17,660 4.95
Forfeited 43,648 26.00 46,758 11.74 50,014 13.21
------------ ----------- -----------
Outstanding at end of year 2,151,675 19.42 1,986,124 18.95 1,998,254 11.63
============ =========== ===========
Options exercisable at year end 1,418,404 17.09 1,150,196 15.00 651,876 10.36
============ =========== ===========
Weighted average fair value of
options granted during the year $ 8.36 $ 14.75 $ 5.13
============ =========== ===========
A summary of additional information related to the options outstanding
as of December 31, 2001 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 - $ 10.25 431,740 5.3 years $ 9.63 431,740 $ 9.63
12.38 - 14.69 585,311 7.6 years 12.56 462,543 12.61
15.93 - 21.19 509,132 9.0 years 18.56 211,375 18.14
33.31 - 33.31 625,492 9.0 years 33.31 312,746 33.31
----------------- ---------------
Total 2,151,675 7.9 years 19.42 1,418,404 17.09
================= ===============
SFAS No. 123 establishes a fair value method of accounting for
stock-based compensation plans either through recognition or disclosure. The
Company accounts for stock-based compensation under APB No. 25 and has elected
to adopt SFAS No. 123 through compliance with the disclosure requirements set
forth in the Statement. Because the exercise price of the Company's employee
stock options equals the market price of the underlying stock on the date of
grant, no compensation expense is recognized under APB No. 25. Pro forma
information regarding net income and earnings per share is required by SFAS No.
123 and has been determined as if the Company had accounted for its employee
stock options under the fair value method of that Statement.
F-17
The fair value of options is measured at the date of grant using the
Black-Scholes option-pricing model. The fair value of options granted in 2001
was estimated using the following weighted-average assumptions: risk-free
interest rate of 4.35%; dividend yield of 0.53%; volatility factor of the
expected market price of the Company's common stock of 49.79%; and expected life
of the options of 4.8 years. The fair value of options granted in 2000 was
estimated using the following weighted-average assumptions: risk-free interest
rate of 5.14%; dividend yield of 0.32%; volatility factor of the expected market
price of the Company's common stock of 47.11%; and expected life of the options
of 4.8 years. The fair value of the options granted in 1999 was estimated using
the following weighted-average assumptions: risk-free interest rate of 6.42%;
dividend yield of 0.82%; volatility factor of the expected market price of the
Company's common stock of 41.52%; and expected life of the options of 4.8 years.
The 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.
For purposes of pro forma disclosures, the estimated fair values of the
options is amortized to expense over the options' vesting periods. Had
compensation cost been determined based on the fair value at grant dates for
stock option awards consistent with SFAS No. 123, the Company's net income
(loss) and earnings (loss) per share would have been reduced to the pro forma
amounts indicated below:
Pro Forma for the Years
Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(In thousands, except
per share amounts)
Net income (loss) As reported $ 40,459 $ 55,620 $ 82
Pro forma $ 37,569 $ 52,515 $ (1,530)
Basic earnings (loss) per share As reported $ 1.45 $ 2.00 $ -
Pro forma $ 1.34 $ 1.89 $ (0.07)
Diluted earnings (loss) per share As reported $ 1.42 $ 1.97 $ -
Pro forma $ 1.32 $ 1.86 $ (0.07)
The effects of applying SFAS No. 123 in the pro forma disclosure are
not necessarily indicative of actual future amounts, and SFAS No. 123 does not
apply to awards granted prior to 1995. Additional awards in future years are
anticipated.
F-18
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,
2001 2000
---- ----
(In thousands)
Change in benefit obligations:
Benefit obligation at beginning of year $ 3,054 $ 2,588
Service Cost 323 257
Interest Cost 317 193
Actuarial gain 1,485 190
Benefits paid (81) (174)
-------- --------
Benefit obligation at end of year $ 5,098 $ 3,054
======== ========
Change in plan assets:
Fair value of plan assets at beginning of year $ 1,775 $ 1,592
Actual return on plan assets (13) (1)
Employer contribution 361 358
Benefits paid (81) (174)
-------- --------
Fair value of plan assets at end of year $ 2,042 $ 1,775
======== ========
Funded Status $(3,056) $(1,279)
Unrecognized net actuarial gain 2,326 888
Unrecognized prior service cost (20) (28)
-------- --------
Accrued benefit cost $ (750) $ (419)
======== ========
The Company's Nonqualified Pension Plan was the only pension plan with
an accumulated benefit obligation in excess of plan assets. The plan's
accumulated benefit obligation was $685,000 at December 31, 2001, and $357,000
at December 31, 2000. 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,
--------------------------------
2001 2000
---- ----
Weighted-average assumptions:
Discount rate 7.25% 7.5%
Expected return on plan assets 8.0% 8.0%
Rate of compensation increase 5.0% 5.0%
F-19
For the Years Ended December 31,
--------------------------------
2001 2000 1999
---- ---- ----
(In thousands)
Components of net periodic benefit cost:
Service cost $ 323 $ 257 $ 178
Interest cost 317 193 172
Expected return on plan assets (129) (119) (88)
Amortization of prior service cost (8) (7) (7)
Amortization of net actuarial loss 188 36 90
------- ------- -------
Net periodic benefit cost $ 691 $ 360 $ 345
======= ======= =======
F-19
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.
Subsequent to December 31, 2001 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 Instruments
The Company realized a net loss of $21,102,000 from derivative
contracts for the year ended December 31, 2001, a net loss of $33,641,000 for
the year ended December 31, 2000 and a net gain of $2,561,000 for the year ended
December 31, 1999. All of these amounts are included in oil and gas production
operating revenues in the consolidated statement of operations.
Including hedges entered into since December 31, 2001 the Company has
the following commodity swap contracts in place to hedge cash flow and reduce
the impact of oil and gas price fluctuations:
Average
Product Volumes/month Quantity Type Fixed Price Duration
------- ------------- ------------- ------------ --------
Natural Gas 1,467,000 MMBtu $ 2.84 01/02 - 12/02
Natural Gas 168,000 MMBtu $ 3.01 01/03 - 12/03
Natural Gas 59,000 MMBtu $ 3.04 01/04 - 12/04
Oil 88,400 Bbls $ 24.69 01/02 - 12/02
Oil 49,800 Bbls $ 22.67 01/03 - 12/03
This table excludes commodity positions with Enron North America Corp,
which filed for bankruptcy protection in December 2001. The Company's unrealized
discounted hedge gain due from Enron had grown to $4,473,000 at the end of
November 2001. As of November 13, 2001, the Company believed the Enron contracts
it owned became ineffective under SFAS No. 133 due to lack of correlation for
counterparty risk. Accordingly, the Company adjusted the fair value downward to
the reduced estimated fair value. A net non-cash loss of $1,779,000 from
counterparty ineffectiveness was offset by a $45,000 gain from hedge
ineffectiveness and $161,000 of amortization of other comprehensive income from
the Enron contracts. The net amount is the activity recorded for the year ended
December 31, 2001 and is reported as unrealized derivative loss in the
consolidated statement of operations. The Company will amortize the unrealized
hedge gain from these Enron contracts over the next two years. Unrealized
derivative gain in the consolidated statements of operations will reflect
amortization of $2,786,000 over the next twelve months offset by a deferred tax
provision. The Company took all legal steps to preserve its rights under these
contracts and sold its claim at a discounted price in February 2002.
F-20
As noted in the table above, the last of these contracts will expire by
December 31, 2004. On December 31, 2001 the estimated fair value of contracts
designated and qualifying as cash flow hedges under SFAS No. 133 was an asset of
$8,119,000. 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 gain as of December 31, 2001 to be reclassified to oil and gas
production operating revenues in the next twelve months would be $7,076,000. The
Company anticipates that all original forecasted transactions will occur by the
end of the originally specified time periods.
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,
---------------------------------
2001 2000 1999
---- ---- ----
(In thousands)
Development costs $ 98,617 $ 48,996 $ 22,166
Exploration 24,506 17,012 20,809
Acquisitions:
Proved 41,188 53,482 33,080
Unproved 18,552 5,694 15,129
--------- --------- ---------
Total $ 182,863 $ 125,184 $ 91,184
========= ========= =========
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 2001, 2000, and 1999 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-21
Presented below is a summary of the changes in estimated domestic
reserves of the Company:
For the Years Ended December 31,
--------------------------------
2001 2000 1999
---- ---- ----
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 20,950 225,975 18,900 207,642 8,614 132,605
Revisions of previous estimates (1,334) (16,421) 210 (1,172) 3,308 (10,445)
Discoveries and extensions 3,131 59,830 1,707 37,702 2,062 43,501
Purchases of minerals in place 3,774 13,086 3,149 21,689 6,323 65,129
Sales of reserves (418) (1,748) (618) (1,540) (24) (343)
Production (2,434) (39,491) (2,398) (38,346) (1,383) (22,805)
------- ------- ------- -------- ------- --------
End of year (a) 23,669 241,231 20,950 225,975 18,900 207,642
======= ======= ======= ======== ======= ========
Proved developed reserves:
Beginning of year 19,006 192,472 16,688 169,379 7,723 112,189
======= ======= ======= ======= ======= ========
End of year 20,679 205,637 19,006 192,472 16,688 169,379
======= ======= ======= ======= ======= ========
- ------------------
(a) At December 31, 2001, 2000, and 1999, includes approximately 869, 1,199 and
1,802 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 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 and basis differentials, were used in the
calculation of the standardized measure:
F-22
For the Years Ended December 31,
--------------------------------
2001 2000 1999
---- ---- ----
Gas (per Mcf) $ 2.502 $ 8.857 $ 2.186
Oil (per Bbl) $ 18.113 $ 25.439 $ 23.847
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,
--------------------------------
2001 2000 1999
---- ---- ----
(In thousands)
Future cash inflows $1,020,948 $2,648,108 $ 900,199
Future production and
development costs (444,608) (570,711) (344,350)
Future income taxes (140,271) (727,929) (150,239)
--------- --------- ---------
Future net cash flows 436,069 1,349,468 405,610
10% annual discount (154,192) (630,984) (144,296)
--------- --------- ---------
Standardized measure of
discounted future net cash flows $281,877 $718,484 $ 261,314
========= ========= =========
The principle sources of change in the standardized measure of
discounted future net cash flows are as follows:
For the Years Ended December 31,
--------------------------------
2001 2000 1999
---- ---- ----
(In thousands)
Standardized measure, beginning of year $ 718,484 $ 261,314 $ 101,946
Sales of oil and gas produced,
net of production costs (170,074) (183,586) (53,814)
Net changes in price and production costs (820,253) 772,910 82,976
Extensions, discoveries and other,
net of production costs 71,265 203,786 76,198
Purchase of minerals in place 29,267 104,883 105,728
Development costs incurred during the year 35,736 12,436 5,816
Changes in estimated future development costs (8,370) 351 (25,281)
Revisions of previous quantity estimates (17,593) 306 10,976
Accretion of discount 109,912 33,871 11,474
Sales of reserves in place (10,548) (3,329) (542)
Net change in income taxes 298,717 (357,780) (76,907)
Other 45,334 (126,678) 22,744
--------- ---------- ----------
Standardized measure, end of year $ 281,877 $ 718,484 $ 261,314
========= ========== ==========
F-23
12. Quarterly Financial Information (Unaudited):
The Company's quarterly financial information for fiscal 2001 and 2000
is as follows:
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
(in thousands, except per share data)
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
Year Ended December 31, 2000:
Total revenue $ 37,411 $ 46,822 $ 54,314 $ 57,119
Less: costs and expenses 25,201 22,996 26,151 32,768
----------- ----------- ----------- -----------
Operating income $ 12,210 $ 23,826 $ 28,163 $ 24,351
Income before income taxes $ 12,350 $ 23,966 $ 28,390 $ 24,581
Net income $ 7,886 $ 14,597 $ 17,139 $ 15,998
Net income per common share:
Basic $ 0.29 $ 0.53 $ 0.61 $ 0.57
Diluted $ 0.29 $ 0.52 $ 0.60 $ 0.56
Dividends paid per share $ 0.025 $ 0.025 $ 0.025 $ 0.025
13. Subsequent Events (Unaudited) :
In March 2002 the Company issued in a private placement a total of
$100,000,000 of its 5.75% senior convertible notes due 2022 (the "Notes") with a
1/2% contingent interest provision. The Company received net proceeds of
$96,700,000 after deducting the initial purchasers' discount and estimated
offering expenses payable by the Company. The notes are general unsecured
obligations and rank on a parity in right of payment with all existing and
future senior indebtedness and other general unsecured obligations. They are
senior in right of payment with 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 beginning on March 20, 2007. The note holders have
the option of redeeming the Notes for cash at 100% of the principal amount plus
accrued and unpaid interest upon (1) a change in control or (2) on March 20,
2007, March 15, 2012 and March 15, 2017. On March 20, 2007 the Company may pay
the repurchase price with cash, shares of its common stock or any combination of
cash and its common stock. St. Mary is not restricted from paying dividends,
incurring debt, or issuing or repurchasing its securities under the indenture.
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 will
use the remaining net proceeds to fund a portion of its 2002 capital budget.
F-24
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 18, 2002 By: /s/ MARK A. HELLERSTEIN
---------------------------------
Mark A. Hellerstein
President, Chief Executive Officer
and Director
GENERAL POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Thomas E. Congdon and Mark A.
Hellerstein, and each of them, his true and lawful attorney-in-fact and agents
with full power of substitution and resubstitution, for him and in his name,
place and stead, in any and all capacities, to sign any amendments to this
report on Form 10-K, and to file the same, with exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission,
hereby ratifying and confirming all that each of said attorneys-in-fact, or his
substitute or substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
/s/ THOMAS E. CONGDON
- ---------------------- Chairman of the Board of Directors March 18, 2002
Thomas E. Congdon
and Director
/s/ MARK A. HELLERSTEIN
- ----------------------- President, Chief Executive Officer March 18, 2002
Mark A. Hellerstein and Director
/s/ RONALD D. BOONE
- ---------------------- Executive Vice President, Chief March 18, 2002
Ronald D. Boone Operating Officer and Director
/s/ RICHARD C. NORRIS
- ---------------------- Vice President - Finance, March 18, 2002
Richard C. Norris Secretary and Treasurer
/s/ GARRY A. WILKENING
- ---------------------- Vice President - Administration March 18, 2002
Garry A. Wilkening and Controller
/s/ LARRY W. BICKLE
- ---------------------- Director March 18, 2002
Larry W. Bickle
Signature Title Date
- --------- ----- ----
/s/ DAVID C. DUDLEY
- ---------------------- Director March 18, 2002
David C. Dudley
/s/ ROBERT L. NANCE
- ---------------------- Director March 18, 2002
Robert L. Nance
/s/ AREND J. SANDBULTE
- ---------------------- Director March 18, 2002
Arend J. Sandbulte
/s/ JOHN M. SEIDL
- ---------------------- Director March 18, 2002
John M. Seidl
/s/ WILLIAM J. GARDINER
- ----------------------- Director March 18, 2002
William J. Gardiner
/s/ JACK HUNT
- ---------------------- Director March 18, 2002
Jack Hunt