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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, 2000.
OR
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
Commission File Number 0-20872
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 41-0518430
(State or other jurisdiction (I.R.S. Employer 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
(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 27,342,705 shares of voting stock held
by non-affiliates of the Registrant, based upon the closing sale price of the
common stock on March 9, 2001 of $25.18 per share as reported on the Nasdaq
National Market System, was $688,708,054. 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 9, 2001, the registrant had 28,242,161 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 2001 annual meeting of stockholders to be filed within 120 days
from December 31, 2000.
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TABLE OF CONTENTS
ITEM PAGE
PART I
ITEM 1. BUSINESS.............................................................1
Background.......................................................1
Business Strategy................................................1
Significant Developments Since December 31, 1999.................3
Markets and Major Customers......................................3
Employees and Office Space.......................................3
Title to Properties..............................................4
Competition......................................................4
Government Regulations...........................................4
Risk Factors.....................................................6
Cautionary Statement about Forward-Looking Statements...........10
Glossary........................................................11
ITEM 2. PROPERTIES..........................................................13
Domestic Operations.............................................13
Acquisitions....................................................17
Reserves........................................................18
Production......................................................19
Productive Wells................................................19
Drilling Activity...............................................20
Domestic Acreage................................................21
Other Assets....................................................21
ITEM 3. LEGAL PROCEEDINGS...................................................22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................22
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT................................22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS.........................................24
ITEM 6. SELECTED FINANCIAL DATA.............................................25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................27
Overview........................................................27
Results of Operations...........................................28
Liquidity and Capital Resources.................................33
Accounting Matters..............................................38
Effects of Inflation and Changing Prices........................38
Environmental...................................................39
i
TABLE OF CONTENTS
(Continued)
ITEM PAGE
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.........................................................39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................40
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.................................40
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................40
ITEM 11. EXECUTIVE COMPENSATION..............................................41
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT......................................................41
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................41
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K.................................................41
ii
PART I
All references in this Form 10-K to "St. Mary", "the Company", "we",
"us" or "our" are to St. Mary Land & Exploration Company and its subsidiaries.
Throughout this document we make statements that are classified as
"forward-looking". Please refer to the "Forward-Looking Statements" section on
page 9 of this document for an explanation of these types of assertions.
Explanations of some commonly used oil and gas terms can be found under the
caption "Glossary" on page 11.
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 was incorporated in Delaware
in 1915. Our operations are focused in five core operating areas in the United
States: the Mid-Continent region; the ArkLaTex region; onshore Gulf Coast and
offshore Gulf of Mexico; the Williston Basin; and the Permian Basin. As of
December 31, 2000, we have estimated net proved reserves of approximately 21
MMBbls of oil and 226 Bcf of natural gas, or an aggregate of 352 BCFE (87%
proved developed, 64% gas) with a PV-10 value before tax of $1.2 billion.
From January 1, 1996 through December 31, 2000, we added estimated net
proved reserves of 449 BCFE at an average finding cost of $.93 per MCFE. Our
average annual production replacement was 265% during this five-year period.
In 2000 production increased 70% to a total of 52.7 BCFE, or average
daily production of 144.1 MMcf per day, as a result of successful acquisitions
and drilling in 1999. St. Mary's 2001 capital budget of approximately $155.0
million includes $95 million for ongoing development and exploration programs in
the core operating areas and $60 million for acquisitions of oil and gas
properties.
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 and the resulting increase in net
asset value per share, cash flow per share and earnings per share. A focused and
balanced program of low to medium-risk exploration and development and niche
acquisitions in each of our core operating areas is designed to provide the
foundation for steady growth while St. Mary's portfolio of higher-risk
exploration prospects has the potential to significantly increase our reserves
and production. All investment decisions are measured and ranked by their
risk-adjusted impact on per share value. We do not pursue growth solely for the
sake of growth.
As part of our strategy to grow value per share, we will pursue
opportunities to monetize selected assets at a premium and to repurchase shares
at attractive values in order to enhance the growth in St. Mary's per share
value. We will continue to focus our resources within selected basins in the
U.S. where our expertise in geology, geophysics and drilling and completion
techniques provides competitive advantages. We may also evaluate international
opportunities that look attractive.
1
Principal elements of St. Mary's strategy are as follows:
o Focused Geographic Operations. St. Mary focuses its exploration,
development and acquisition activities in five core operating areas
where it has built a balanced portfolio of proved reserves,
development drilling opportunities and higher-risk exploration
prospects. St. Mary believes that its extensive leasehold position is
a strategic asset. Since 1990 we have expanded our technical and
operating staff and increased our drilling, production and operating
capabilities. Senior technical managers, each possessing over 20 years
of experience, head up regional technical offices located near core
properties and are supported by centralized administration in St.
Mary's Denver office. We have knowledgeable and experienced
professionals at every level of the organization. St. Mary believes
that its long-standing presence, its established networks of local
industry relationships and its extensive acreage holdings in its core
operating areas provide a significant competitive advantage.
Additionally, we believe that we can continue to expand our operations
without the need to proportionately increase the number of employees.
o Exploitation and Development of Existing Properties. St. Mary uses its
comprehensive base of geological, geophysical, engineering and
production experience in each of its core operating areas to source
prospects for its ongoing, low to medium-risk development and
exploration programs. St. Mary conducts detailed geologic studies and
uses an array of technologies and tools including 3-D seismic imaging,
hydraulic fracturing and reservoir stimulation techniques, and
specialized logging tools to maximize the potential of its existing
properties. During 2000 St. Mary participated in 124 gross drilling
wells with an 82% success rate and 79 recompletions with an 80%
success rate.
o Higher Risk Exploration Projects. St. Mary generally invests
approximately 15% of its annual capital budget in higher-potential
higher-risk exploration projects, unconventional gas projects,
international and opportunistic acquisitions. Our strategy is to test
several of these ideas each year which in total have the potential, if
successful, to significantly increase our net reserves. St. Mary seeks
to invest in a diversified mix of exploration projects and generally
limits its capital exposure by participating with other experienced
industry partners. St. Mary plans to test several of these prospects
in the Gulf Region and Texas during 2001.
o Selective Acquisitions. St. Mary seeks to make selective niche
acquisitions of oil and gas properties that complement its existing
operations, offer economies of scale and provide further development
and exploration opportunities based on proprietary geologic concepts.
We believe that the focus on smaller, negotiated transactions where we
have specialized geologic knowledge or operating experience has
enabled us to acquire attractively priced and under-exploited
properties. In addition, St. Mary will pursue corporate acquisitions
if they can be made on an accretive basis. Examples of this type of
acquisition include the Nance Petroleum Corporation and King Ranch
Energy, Inc. acquisitions, both completed in 1999 for stock.
Our strong balance sheet positions us to exploit acquisition
opportunities in 2001 arising throughout the upstream oil and gas sector. Many
companies are expected to divest assets during the year as a result of
continuing consolidation within the industry and the strong oil and gas price
environment that currently exists. We plan to continue to emphasize smaller
niche acquisitions utilizing our technical expertise, financial flexibility and
structuring experience. Many attractive acquisition candidates are sourced in
cooperation with our regional offices where the local personnel have a detailed
insight into emerging opportunities and geologic potential. Additionally, St.
Mary will actively seek larger acquisitions of assets or companies that afford
opportunities to expand our existing core areas, acquire additional
geoscientists or gain a significant acreage and production foothold in a new
basin.
2
o Control of Operations. We believe it is increasingly important to
control geologic and operational decisions as well as the timing of
those decisions. In addition, St. Mary receives income in the form of
monthly COPAS overhead reimbursement as an operator. St. Mary plans to
operate approximately 65% of its capital budget in 2001.
o Financial Flexibility. A conservative use of financial leverage has
long been a cornerstone of our strategy. We believe that the
preservation of a strong balance sheet is a competitive advantage
because it enables us to act quickly and decisively to capture
opportunities and provides the financial resources to weather periods
of volatile commodity prices or escalating costs.
o Stock Repurchase Plan. In August 1998 St. Mary's board of directors
authorized a stock repurchase program whereby St. Mary may purchase
from time-to-time, in open market purchases or negotiated sales, up to
2,000,000 of its own common shares. St. Mary has repurchased a total
of 412,400 of its common shares, including repurchases subsequent to
year-end.
Significant Developments Since December 31, 1999
o Acquisitions of Oil and Gas Properties. St. Mary completed
acquisitions in each of its five core areas in 2000 totaling $53.5
million. In the Williston Basin we completed five separate
acquisitions for a total of $13.3 million. In December 2000 St. Mary
closed a $32 million acquisition of Oklahoma properties from JN
Exploration and affiliates. The remaining $8.2 million was comprised
of niche acquisitions made in the ArkLaTex region, the Gulf Coast and
Gulf of Mexico region and the Permian Basin.
o Increase in Year-End Reserves. As of December 31, 2000, net proved
reserves increased 10% to 352 BCFE. St. Mary added 40.6 BCFE through
acquisitions for cash and 47.9 BCFE from drilling activities. There
were no net revisions of previous reserves since higher year-end 2000
pricing was offset by negative performance revisions.
o Sale of Khanty Mansiysk Oil Corporation Shares. St. Mary sold 14,662
shares of KMOC stock in December 2000 for $7.0 million, realizing a
$2.2 million gain.
Markets and Major Customers
During 2000 sales to BP Amoco accounted for 22.3% of St. Mary's total
oil and gas production revenue. For 1999 sales to Transok Gas Company, Inc.
accounted for 13.3% of our total oil and gas production revenue.
Employees and Office Space
As of December 31, 2000, St. Mary had 157 full-time employees. None of
St. Mary's employees are subject to a collective bargaining agreement. We
consider our relations with our employees to be good. St. Mary leases
approximately 37,700 square feet of office space in Denver, Colorado for its
executive and administrative offices, of which 7,200 square feet is subleased.
We also lease approximately 15,000 square feet of office space in Tulsa,
Oklahoma, approximately 7,300 square feet of office space in Shreveport,
Louisiana, approximately 7,500 square feet in Lafayette, Louisiana and
approximately 10,900 square feet in Billings, Montana. We are currently
negotiating the renewal and expansion of our Denver office space to provide for
adequate future growth.
3
Title to Properties
Substantially all of St. Mary's working interests are held pursuant to
leases from third parties. A title opinion is usually obtained prior to the
commencement of drilling operations on properties. St. Mary has obtained title
opinions or conducted a thorough title review on substantially all of its
producing properties and believes that it has satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. 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. St. Mary performs only a
minimal title investigation before acquiring undeveloped properties.
Competition
The oil and gas industry is intensely competitive. Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and gas reserves. St. Mary's competitive position depends on
our geological, geophysical and engineering expertise, our financial resources,
and our ability to select, acquire and develop proved reserves. St. Mary
believes that the locations of its leasehold acreage, its exploration, drilling
and production capabilities and the experience of its management and that of its
industry partners generally enable it to compete effectively in its core
operating areas. However, we compete with a substantial number of major and
independent oil and gas companies having larger technical staffs and greater
financial and operational resources. Many of those companies not only engage in
the acquisition, exploration, development and production of oil and natural gas
reserves, but also have refining operations, generate electricity and market
refined products. St. Mary also competes 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, St. Mary may be subject to liability or may lose
substantial portions of its properties in the event of certain environmental
damages. St. Mary could incur substantial costs to comply with environmental
laws and regulations.
4
Certain operations St. Mary conducts 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 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,
o removal of facilities.
To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met. The cost of such bonds or other
surety can be substantial, and we cannot assure that St. Mary can continue to
obtain bonds or other surety in all cases. Under certain circumstances the MMS
may require any Company operations on Federal leases to be suspended or
terminated.
The Oil Pollution Act of 1990 imposes a variety of regulations on
"responsible parties" related to the prevention of oil spills. The
implementation of new, or the modification of existing, environmental laws or
regulations, including regulations promulgated under the Oil Pollution Act of
1990, could have a material adverse impact on St. Mary.
The recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. Initiatives to further
regulate the disposal of oil and gas wastes at the federal, state and local
level could have a material impact on St. Mary.
5
Risk Factors
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 gas prices fluctuate widely, and low prices for an extended period of
time would likely have a material adverse impact on our business.
Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas. These prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under our credit facility is
subject to periodic redetermination based in part on changing expectations of
future prices. Lower prices may also reduce the amount of oil and gas that we
can economically produce.
Prices for oil and gas fluctuate widely. Today oil and gas prices are
at very high levels as a result of favorable supply and demand conditions.
However, oil and gas prices declined significantly in 1998 and, for an extended
period of time, remained substantially below prices received in recent years.
Among the factors that can cause fluctuations are:
o the domestic and foreign supply of oil and natural gas,
o the price of foreign imports,
o world-wide economic conditions,
o political conditions in oil and gas producing regions,
o the level of demand,
o weather conditions,
o domestic and foreign governmental regulations and
o the price and availability of alternative fuels.
We often use hedging transactions with respect to a portion of our oil
and gas production to achieve more predictable cash flow and to reduce our
exposure to price fluctuations. While the use of hedging transactions limits the
downside risk of price declines, their use may also limit future revenues from
price increases.
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, 2000,
our proved reserves, if produced constantly at the then current rate of
production, would produce for approximately 6.5 years. 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. We cannot assure you that we will
be able to find and develop or acquire additional reserves at an acceptable
cost.
6
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 gas reserves. Our capital expenditures for
oil and gas properties were $125.2 million for 2000 and $91.2 million during
1999. We plan to incur total capital expenditures of $155 million in 2001. We
believe that we will have sufficient cash provided by operating activities and
borrowings under our credit facility to fund planned capital expenditures in
2001. However, if oil and gas prices decrease or we encounter operating
difficulties that result in our cash flow from operations being less than
expected it may 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 meet these requirements.
If oil and gas prices decrease or exploration efforts are unsuccessful, we may
be required to take additional writedowns or may incur higher exploration
expense.
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 the well has found proved
reserves. If an exploratory well has not found proved reserves, 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 the costs of each such field down to fair market value using a
15% discounted present 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
$6.3 million and $10.6 million in 2000 and 1999, respectively.
Reserve estimates are inherently uncertain and depend on many assumptions that
may turn out to be inaccurate.
Estimating oil and gas reserves is a complex and inexact science
because of the numerous uncertainties inherent in the process. The process
relies on interpretations of available geologic, geophysical, engineering and
production data. The extent, quality and reliability of this technical data can
vary. The process also requires certain economic assumptions, some of which are
mandated by the SEC, such as oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The accuracy of
a reserve estimate is a function of:
o the quality and quantity of available data,
o the interpretation of that data,
o the accuracy of various mandated economic assumptions, and
o the judgment of individuals preparing the estimate.
7
The proved reserve information included in this Form 10-K is based on
estimates prepared by us and evaluated by Ryder Scott Company. Estimates
prepared by others might differ from our estimates.
Actual future production, oil and gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves most likely will vary from our estimates. Any significant
variance could materially affect the quantities and present value of our
reserves. In addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development and prevailing oil
and gas prices. Our reserves may also be susceptible to drainage by operators on
adjacent properties.
You should not assume that the present value of future net cash flows
included in this annual report is the current market value of our estimated
proved oil and gas reserves. In accordance with SEC requirements, we generally
base the estimated discounted future net cash flows from proved reserves on
prices and costs on the date of the estimate. Actual future prices and costs may
be materially higher or lower than the prices and costs as of the date of the
estimate.
We may be subject to risks in connection with future acquisitions.
The successful acquisition of producing properties requires an
assessment of several factors, including:
o recoverable reserves;
o future oil and gas prices;
o operating costs; and
o potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In
connection with these assessments, we perform a review of the subject properties
that we believe to be generally consistent with industry practices, which
usually includes on-site inspections and the review of reports filed for
environmental compliance. Our review will not reveal all existing or potential
problems nor will it permit us to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities. Inspections may
not always be performed on every well, and structural and environmental problems
are not necessarily observable even when an inspection is undertaken. Even when
problems are identified, the seller may be unwilling or unable to provide
effective contractual protection against all of the problems. We generally have
limited contractual indemnification for environmental liabilities but we can
still be subject to material unforeseen liability.
Competitive industry conditions may negatively affect our ability to conduct
operations.
Competition in the oil and gas industry is intense, particularly with
respect to the acquisition of producing properties and proved undeveloped
acreage. Major and independent oil and gas companies actively bid for desirable
oil and gas properties, as well as for the equipment and labor required to
operate and develop these properties. Many of our competitors have financial
resources that are substantially greater than ours, which may adversely affect
our ability to compete with these companies.
8
Drilling is a high-risk activity.
Our future success will depend on the success of our drilling program.
In addition to the numerous operating risks described in more detail below,
these activities involve the risk that no commercially productive oil or gas
reservoirs will be discovered through the drilling of a particular well. In
addition, we often are uncertain as to the future cost or timing of drilling,
completing and producing wells. Furthermore, our drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including:
o unexpected drilling conditions,
o pressure or irregularities in formations,
o equipment failures or accidents,
o adverse weather conditions,
o compliance with governmental requirements, and
o shortages or delays in the availability of drilling rigs and the
delivery of equipment.
The oil and gas business involves many operating risks that can cause
substantial losses and insurance may not protect us against all these risks.
These operating risks include:
o fires,
o explosions,
o blow-outs,
o uncontrollable flows of oil, gas, formation water or drilling fluids,
o natural disasters,
o pipe or cement failures,
o casing collapses,
o embedded oilfield drilling and service tools,
o abnormally pressured formations, and
o environmental hazards such as oil spills, natural gas leaks, pipeline
ruptures and discharges of toxic gases.
If any of these events occur, we could incur substantial losses as a
result of:
o injury or loss of life,
o severe damage to and destruction of property, natural resources and
equipment,
o pollution and other environmental damage,
o clean-up responsibilities,
o regulatory investigation and penalties,
o suspension of our operations, and
o repairs to resume operations.
If we experience any of these problems, our ability to conduct
operations could be adversely affected.
St. Mary maintains 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.
9
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.
We are subject to complex laws that can affect the cost, manner or feasibility
of doing business.
Exploration, development, production and sale of oil and gas are
subject to extensive federal, state, local and international regulation. We may
be required to make large expenditures to comply with environmental and other
governmental regulations. Please see the discussion above under the caption
"Government Regulations" on page 4 for a discussion of some of the regulations
to which we are subject.
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
management expects, believes or anticipates will or may occur in the future are
forward looking statements. Examples of forward-looking statements may include
discussion of such matters as:
o The amount and nature of future capital, development and exploration
expenditures,
o The drilling of wells,
o Reserve estimates and the estimates of both future net revenues and
the present value of future net revenues that are included in their
calculation,
o Future oil and gas production estimates,
o Repayment of debt,
o Business strategies,
o Expansion and growth of operations, and
o Other similar matters such as those discussed in the "Outlook" section
on 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" beginning on page 6, 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.
10
Glossary
The terms defined in this section are used throughout this Form 10-K.
2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a
two-dimensional cross-section of the subsurface.
3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used herein in reference to natural gas.
BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using
the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Behind pipe reserves. Estimated net proved reserves in a formation in which
production casing has already been set in the wellbore but has not been
perforated and production tested.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio
of six Mcf of gas (including gas liquids) to one Bbl of oil.
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.
11
Gross well. A well in which a working interest is owned.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture
of fluid and proppant (usually sand) into the formation under high pressure.
This creates artificial fractures in the reservoir rock, which increases
permeability and porosity.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
Mcf. One thousand cubic feet.
MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMcf. One million cubic feet.
MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined
using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the heat
required to raise the temperature of a one-pound mass of water one degree
Fahrenheit.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net asset value per share. The result of the fair market value of total assets
less total liabilities, divided by the total number of outstanding shares of
common stock.
PV-10 value. The present value of estimated future gross revenue to be generated
from the production of estimated net proved reserves, net of estimated
production and future development costs, using prices and costs in effect as of
the date indicated (unless such prices or costs are subject to change pursuant
to contractual provisions), without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
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.
12
Reserve life. Expressed in years, represents the estimated net proved reserves
at a specified date divided by forecasted production for the following 12-month
period.
Royalty. The interest paid to the owner of mineral rights expressed as a
percentage of gross income from oil and gas produced and sold unencumbered by
expenses.
Royalty interest. An interest in an oil and gas property entitling the owner to
shares of oil and gas production free of costs of exploration, development and
production. Royalty interests are approximate and are subject to adjustment.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether such acreage contains estimated net proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to share in
the production.
ITEM 2. PROPERTIES
Domestic 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 net proved reserves as of December 31, 2000, is shown below.
Oil Gas MMCFE PV-10 Value
(MBbls) (MMcf) Amount Percent (In thousands) Percent
------- ------ ------ ------- -------------- -------
Mid-Continent Region............ 1,766 110,033 120,627 34.3% $ 496,091 43.0%
ArkLaTex Region................. 1,510 42,689 51,749 14.7% 189,602 16.4%
Gulf Coast and Gulf of Mexico... 1,168 46,087 53,094 15.1% 248,391 21.5%
Williston Basin................. 12,339 14,105 88,137 25.1% 134,520 11.7%
Permian Basin................... 4,167 13,061 38,066 10.8% 85,059 7.4%
------ ------- ------- ------ ---------- ------
Total 20,950 225,975 351,673 100.0% $1,153,663 100.0%
====== ======= ======= ====== ========== ======
Mid-Continent Region. Since 1973 St. Mary has been active in the
Mid-Continent region, where operations are managed by our 30-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 34%
of our estimated net proved reserves as of December 31, 2000, or 110.0 BCFE (84%
proved developed and 91% gas). St. Mary participated in 63 gross wells and
recompletions in this region in 2000, including 22 Company-operated wells.
St. Mary's development and exploration budget in the Mid-Continent
region for 2001 totals $27 million. We plan to operate 32 drilling wells in the
Mid-Continent region during 2001 and to utilize three to four drilling rigs
throughout the year. We also expect to participate in an additional 10 to 15
wells to be operated by other entities.
13
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 a continuing
consolidation of operators in the basin. St. Mary periodically seizes attractive
opportunities to acquire properties from companies that have elected to
discontinue operations in the basin. The $32 million acquisition of properties
from JN Exploration and affiliates that closed in December 2000 is a good
example of this type of opportunity.
St. Mary works aggressively to control its operating costs and to
enhance its full cycle economics. In December 1998 we realized net proceeds of
$22 million on the sale of our interests in eight fields in the Anadarko Basin.
This sale was part of our ongoing strategy to enhance the return on our
portfolio of assets through the opportunistic sale of non-strategic properties
during periods in the market when such properties command premium valuations.
Drilling activities for 2001 will be focused on lower to medium-risk
prospects in the Granite Wash, Osborne and Red Fork formations. In addition, St.
Mary plans to devote approximately 22% of its 2001 Mid-Continent capital budget
to deeper, higher potential development wells in the lower Morrow formation
below 19,000 feet at the NE Mayfield Field and in various other fields within
the Morrow and Springer formations at depths between 10,000 and 16,000 feet.
Carrier Prospect. Within its inventory of large exploration prospects,
St. Mary holds an aggregate 11.2% working interest in 25,800 acres in Leon
County, Texas in the Cotton Valley reef play. Our Carrier Prospect acreage is
located approximately nine miles east of the trend of the industry's initial
prolific reef discoveries, and targets potentially larger reefs that are
postulated to have developed in the deeper waters of the basin during the
Jurassic period. St. Mary and its partners completed a 52 square mile 3-D
seismic survey in 1997. We are currently soliciting partner and industry
participation for an initial test well.
Constitution / China Beach Prospects. The successful fracture
stimulation in 1999 has led to additional drilling at this prospect. St. Mary
participated in the drilling of the Apache Gas Unit #1 in 2000 where three Yegua
sands were encountered, and the well was completed at 3,700 MCFE per day. Three
additional wells are planned to be drilled in the Constitution field for 2001
that will test multiple Yegua sand objectives.
Gulf Coast and Gulf of Mexico Region. St. Mary's presence in south
Louisiana dates to the early 1900's when St. Mary's founders acquired a
franchise property in St. Mary Parish on the shoreline of the Gulf of Mexico.
These 24,900 acres of fee lands yielded more than $7 million of gross oil and
gas royalty revenue in 2000. St. Mary's onshore Gulf Coast and Gulf of Mexico
presence increased dramatically in 1999 with the acquisition of King Ranch
Energy and is expected to be a major growth area in 2001 and beyond. This
acquisition included 260,000 gross undeveloped acres (81,000 net acres) and
1,538 square miles of 3-D seismic data. The Gulf Coast and Gulf of Mexico region
accounted for 15% of St. Mary's estimated net proved reserves as of December 31,
2000, or 53.1 BCFE (82% proved developed and 87% gas).
St. Mary's diverse activities in the onshore Gulf Coast and Gulf of
Mexico are managed by its recently expanded 18-person regional office in
Lafayette, Louisiana, and include ongoing development and exploration programs
in Point Coupee, Cameron, Lafourche, Jefferson Davis, Vermilion and Calcasieu
parishes as well as several offshore Gulf of Mexico blocks. Advanced 3-D seismic
imaging and interpretation techniques are revitalizing exploration and
development activities in the Miocene trend along the Gulf Coast. St. Mary is
applying the latest technologies to unravel the region's complex geology and to
extend exploratory drilling into deeper untested formations. Our exploration and
development budget in the Gulf Coast and Gulf of Mexico region for 2001 is $37.5
million.
14
The Judge Digby Field is the largest field acquired in the King Ranch
Energy acquisition and is located outside Baton Rouge in Point Coupee Parish.
St. Mary has an 11.5% to 20% working interest in eight wells currently producing
185 MMcf per day. This ultra deep field produces from multiple Tuscaloosa
reservoirs between 19,000 and 24,000 feet. The Parlange #11 was drilled to
23,480 feet and initially produced at 92,000 Mcf per day, the highest rate ever
recorded for onshore Louisiana. This well is currently producing 55,000 Mcf per
day. During late 2000 the J. Wuertelle #1 was drilled to a total depth of 22,200
feet and was completed in early 2001 at a rate of 25,000 Mcf per day. This well
is currently producing 35-40,000 Mcf per day. We are currently participating in
the drilling of the Parlange #12 which is scheduled to be drilled to 23,100 feet
and test the C-4 and C-5 sands, which have never been tested at a structurally
favorable position in the field. This well has already logged over 200 feet of
pay and is currently drilling ahead to the C-4 and C-5 sands.
St. Mary and its partners are continuing to evaluate the 30 square
mile 3-D survey on the western and northern flanks of the Edgerly salt dome in
Calcasieu Parish, Louisiana where a 16,000-acre leasehold position has been
assembled. The Collingwood #24-1 was completed in 2000 for 2,700 Mcf and 425 Bbl
per day. We have identified a number of other promising anomalies on the 3-D
survey and expect to test two Hackberry prospects at shallow depths between
10,000 and 13,000 feet in 2001. St. Mary has an approximate 35% working interest
in the Edgerly prospect.
St. Mary's acquisition of King Ranch Energy, its historical presence
in southern Louisiana, its established network of industry relationships and its
extensive technical database on the area have enabled us to assemble an
inventory of prospects in the onshore Gulf Coast and Gulf of Mexico region.
In the Gulf of Mexico, St. Mary plans to test a large 3-D target at
Matagorda 701 during 2001. 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 2001.
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. Since the initial discovery on St. Mary's fee lands in 1938,
cumulative oil and gas revenues, primarily landowners' royalties, to St. Mary
from the Bayou Sale, Horseshoe Bayou and Belle Isle fields on its fee lands have
exceeded $230 million. St. Mary currently leases 11,784 acres of its fee lands
and has an additional 13,130 acres that are presently unleased. Our principal
lessees are Vastar, Cabot, ExxonMobil, Badger and Sam Gary Jr. and Associates, a
private exploration company headquartered in Denver.
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. St. Mary's
discovery on our fee lands at South Horseshoe Bayou in early 1997 and a
subsequent successful confirmation well in early 1998 proved that significant
accumulations of gas are sourced and trapped at depths below 16,000 feet.
Centennial Project. St. Mary is participating in a 51 square mile 3-D
seismic survey over the Spindletop field near Beaumont, Texas, which should be
complete in late March 2001. St. Mary and its partners have leased or optioned
approximately 19,000 acres and intend to exploit a variety of formations,
including the Miocene, Frio, Hackberry, Discorbis, Vicksburg and Yegua sands. We
have a 21.25% working interest in the Centennial project, which is planned to be
a multi-year exploration and development program. St. Mary and its partners plan
to drill four to six wells in 2001 after evaluating the results of the seismic
survey.
15
ArkLaTex Region. St. Mary's operations in the ArkLaTex region are
managed by its 16-person office in Shreveport, Louisiana. The ArkLaTex region
accounted for 15% of St. Mary's estimated net proved reserves as of December 31,
2000, or 51.7 BCFE (86% proved developed and 82% gas).
In 1992 St. Mary 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 $9.5 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 556 producing wells, including 94 Company-operated wells, and
interests in leases totaling approximately 88,000 gross acres and mineral
servitudes totaling approximately 15,800 gross acres.
Activities in the ArkLaTex region during 2000 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 in two successful wells in 2000 at the East
Bridges field where it completed the Jones #1 and Jones #2 wells as
multi-lateral wells, each with initial production exceeding 4,000 Mcf per day.
The Shreveport office operates the Clarksville Field (44% working
interest) in Red River County, Texas acquired as part of King Ranch Energy. The
field currently produces 518 Bbl per day from 34 wells.
In 2001 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. The capital budget for the ArkLaTex region is $11
million, a 59% increase over 2000 expenditures. The Shreveport office
anticipates participating in 35 wells in the ArkLaTex region and expects to
operate 77% of its 2001 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 behalf of St. Mary since 1991. The
Williston Basin region accounted for 25% of St. Mary's estimated net proved
reserves as of December 31, 2000, or 88.1 BCFE (96% proved developed and 84%
oil).
Our office in Billings, Montana includes a 22-person staff, some of
whom have spent over 20 years and their entire careers in the Williston Basin.
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 24 out of 25 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. Six 3-D
surveys are planned for 2001, exceeding the number of surveys conducted in any
prior year.
16
St. Mary spent $12.6 million on exploration and development in the
Williston Basin in 2000. Its only dry hole since 1991 was drilled early in 2000
followed by 11 successful wells, 5 of which were operated by us. The Federal
16-28X (56.25% working interest) drilled to the Duperow formation had an initial
production rate of 640 barrels of oil per day and 450 Mcf per day. In addition
to its exploration and development efforts, St. Mary acquired $13.3 million of
oil and gas properties in 5 niche acquisitions that added 5,475 MCFE per day of
production.
Our 2001 Williston Basin exploration and development capital program
is budgeted for $12 million. We plan to drill nine operated wells with working
interests ranging from 70% to 100%. Rig availability is limited in the Williston
Basin. We have minimized the impact of the tight rig situation by committing to
keep one drilling rig utilized throughout the year. St. Mary plans to operate
85% of its Williston Basin capital budget in 2001.
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 recovery projects. 3-D seismic imaging of
existing fields and state-of-the-art secondary recovery programs are
substantially increasing oil recoveries in the Permian Basin.
Our holdings in the Permian Basin derive 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 11% of our estimated net proved reserves as of December 31, 2000, or 38.1
BCFE (84% proved developed and 66% oil).
St. Mary participated in drilling 9 wells in 2000 with a 67% success
rate. The $1.7 million spent on exploration and development resulted in adding
reserves of 2,317 MMCFE. The East Shugart Delaware Unit waterflood project was
initiated in 2000. Although an initial response from the water injection is not
anticipated until late 2001, we are hopeful the East Shugart waterflood will be
an analog to the successful Parkway Delaware Unit waterflood that increased
production from 450 Bbl per day in 1998 when the waterflood was initiated to
1,250 Bbl per day currently.
The Permian Basin capital expenditures budget for 2001 is $6.0
million. In addition to drilling four injection wells in the East Shugart
Delaware waterflood, two Morrow tests are planned in the Parkway field and a
Queen development well is planned at the Young North field. The HJSA toplease on
30,450 acres in Ward County, Texas became effective on August 5, 2000 and at
year-end was producing 3,250 MCFE per day net to St. Mary. 3-D seismic data over
the 50 square mile lease will be reprocessed during the first quarter of 2001
with exploitation drilling, based on the results of the 3-D seismic evaluation,
anticipated during the year. We anticipate significant opportunities will
develop with respect to our 21.4% interest in this lease.
Acquisitions
Our strategy is to make selective niche acquisitions of oil and gas
properties within our core operating areas in the United States. We seek to
acquire properties that complement our existing operations, offer economies of
scale and provide further development and exploration opportunities based on
proprietary geologic concepts or advanced well completion techniques. We believe
that our success in acquiring attractively priced and under-exploited properties
has resulted from our focus on transactions where we have specialized geologic
knowledge or operating experience. In addition, we will pursue corporate
acquisitions when they can be made on an accretive basis.
17
St. Mary completed $53.5 million in oil and gas property acquisitions
in 2000, the largest dollar value in our history. In December 2000 we completed
a $32.0 million acquisition of oil and gas properties in the Mid-Continent
region. We also made $13.3 million of niche acquisitions in the Williston Basin
in five separate transactions. The remaining $8.2 million was comprised of niche
acquisitions made in the ArkLaTex region, the Gulf Coast and Gulf of Mexico
region and the Permian Basin. During the last five years we have closed over
$151 million of acquisitions where proprietary geologic knowledge or operating
expertise and an attractive stock and performance track record have afforded us
a competitive advantage.
For 2001 St. Mary has reserved $60 million of its capital program
budget for property acquisitions. However, we have the financial capacity to
commit substantially greater resources to purchases should additional
opportunities be identified.
Reserves
At December 31, 2000, Ryder Scott Company, independent petroleum
engineers, evaluated properties representing approximately 82% of St. Mary's
total PV-10 value and St. Mary evaluated the remainder. The PV-10 values shown
in the following table are not intended to represent the current market value of
the estimated net proved oil and gas reserves owned by St. Mary. Neither prices
nor costs have been escalated, but prices include the effects of hedging
contracts.
The following table sets forth summary information with respect to the
estimates of our net proved oil and gas reserves for each of the years in the
three-year period ended December 31, 2000, as prepared by Ryder Scott Company
and us:
As of December 31,
------------------
2000 1999 1998
---- ---- ----
Proved Reserves Data:
Oil (MBbls) 20,950 18,900 8,614
Gas (MMcf) 225,975 207,642 132,605
MMCFE 351,673 321,042 184,289
PV-10 value, excluding income taxes (in thousands) $ 1,153,663 $ 351,016 $ 125,126
Proved Developed Reserves 87% 84% 86%
Production Replacement 168% 541% (25%)
Life (years) 6.5 6.1 6.5
The present value of estimated future net revenues before income taxes
of our reserves was $1.2 billion as of December 31, 2000. This present value is
based on a benchmark of prices in effect at that date of $26.80 per barrel of
oil (NYMEX) and $9.52 per MMBtu of gas (Gulf Coast spot price). Both of these
prices are then adjusted for transportation and basis differential. These prices
were 5 percent and 310 percent higher, respectively, than prices in effect at
the end of 1999. If we used five-year declining strip pricing, resulting in
average prices over the life of the properties of $3.96 per Mcf and $24.67 per
barrel, our PV-10 value would be $550 million.
18
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,
------------------------
2000 1999 1998
---- ---- ----
Operating Data:
Net production (1):
Oil (MBbls)........................................... 2,398 1,383 1,275
Gas (MMcf)............................................ 38,346 22,805 25,440
MMCFE................................................. 52,731 31,104 33,090
Average net daily production (1):
Oil (Bbls)............................................ 6,551 3,790 3,493
Gas (Mcf)............................................. 104,769 62,478 69,698
MCFE.................................................. 144,075 85,216 90,656
Average sales price (2):
Oil (per Bbl)......................................... $ 23.53 $ 16.56 $ 12.98
Gas (per Mcf)......................................... $ 3.44 $ 2.21 $ 2.16
Additional per MCFE data:
Lease operating expense............................... $ .48 $ .44 $ .39
Transportation Costs.................................. $ .04 $ .03 $ .03
Production taxes...................................... $ .21 $ .16 $ .12
[FN]
(1) Production from South Horseshoe Bayou and sold Oklahoma properties
represented 18.1% and 6.5% respectively, or a total of 24.6% of the
1998 production total.
(2) Includes the effects of St. Mary's hedging activities (see
"Management's Discussion and Analysis of Financial Condition and
Results of Operations").
St. Mary uses financial hedging instruments, primarily
fixed-for-floating price swap agreements and no-cost collar agreements with
financial counterparties, to manage its exposure to fluctuations in commodity
prices. We also employ the use of exchange-listed financial futures and options
as part of our hedging program for crude oil.
Productive Wells
The following table sets forth information regarding the number of
productive wells in which St. Mary held a working interest at December 31, 2000.
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.
Gross Net
----- ---
Oil 1,061 303
Gas 1,472 215
----- ----
Total 2,533 518
===== ====
19
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,
------------------------
2000 1999 1998
----- ---- ----
Gross Net Gross Net Gross Net
Development: ----- --- ----- --- ----- ---
Oil....................................... 40 17.37 26 10.45 6 .28
Gas....................................... 107 24.94 105 22.26 109 26.04
Non-productive............................ 31 9.38 14 5.75 12 3.98
--- ----- --- ----- --- -----
Total................................. 178 51.69 145 38.46 127 30.30
--- ----- --- ----- --- -----
Exploratory:
Oil....................................... 6 4.17 1 .20 1 .50
Gas....................................... 11 3.63 12 3.84 3 .95
Non-productive............................ 8 4.32 9 2.56 6 1.05
--- ----- -- ---- -- ----
Total................................. 25 12.12 22 6.60 10 2.50
--- ----- --- ----- --- -----
Farmout or non-consent 8 - 6 - 4 -
--- ----- --- ----- --- -----
Grand Total(1) ............................ 211 63.81 173 45.06 141 32.80
=== ===== === ===== === =====
[FN]
(1) Does not include 4 gross wells and 1 gross well completed on St. Mary's
fee lands during 2000 and 1998, respectively.
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not own any drilling equipment.
20
Domestic Acreage
The following table sets forth the gross and net acres of developed
and undeveloped oil and gas leases, fee properties, mineral servitudes and lease
options held by St. Mary as of December 31, 2000. Undeveloped acreage includes
leasehold interests that may already have been classified as containing proved
undeveloped reserves.
Developed Undeveloped
Acreage (1) Acreage (2) Total
----------- ----------- -----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Arkansas..................................... 2,053 368 167 28 2,220 396
Louisiana................................... 113,326 34,288 47,227 12,691 160,553 46,979
Montana..................................... 26,962 12,221 80,182 48,361 107,144 60,582
New Mexico.................................. 7,280 1,957 2,520 1,507 9,800 3,464
North Dakota................................ 64,024 19,434 132,161 58,437 196,185 77,871
Oklahoma.................................... 168,943 37,718 69,223 19,588 238,166 57,306
Texas....................................... 142,356 52,020 163,679 64,558 306,035 116,578
Other (3) .................................. 3,460 1,860 10,892 4,002 14,352 5,862
-------- ------- ------- ------- --------- -------
Subtotal........................... 528,404 159,866 506,051 209,172 1,034,455 369,038
-------- ------- ------- ------- --------- -------
Louisiana Fee Properties..................... 10,336 10,336 14,578 14,578 24,914 24,914
Louisiana Mineral Servitudes................. 9,965 5,424 5,861 5,299 15,826 10,723
-------- ------- ------- ------- --------- -------
Subtotal................................ 20,301 15,760 20,439 19,877 40,740 35,637
-------- ------- ------- ------- --------- -------
GRAND TOTAL ............................ 548,705 175,626 526,490 229,049 1,075,195 404,675
======== ======= ======= ======= ========= =======
[FN]
-----------
(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 net proved reserves.
(3) Includes interests in Alabama, Colorado, Kansas, Mississippi, Utah and
Wyoming. St. Mary also holds an override interest in an additional
44,388 gross acres in Utah.
Other Assets
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.
21
ITEM 3. LEGAL PROCEEDINGS
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.
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 2000.
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 February 28, 2001.
Name Age Position
- ---- --- --------
Thomas E. Congdon 74 Chairman of the Board
Mark A. Hellerstein 48 President and Chief Executive Officer
Ronald D. Boone 52 Executive Vice President and Chief
Operating Officer
Robert T. Hanley 54 Vice President - Business Development
Richard C. Norris 45 Vice President - Finance, Secretary and
Treasurer
Milam Randolph Pharo 48 Vice President - Land and Legal
Garry A. Wilkening 50 Vice President - Administration and
Controller
Douglas W. York 39 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.
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 of Colorado (now named Xcel Energy).
22
Douglas W. York has served as Vice President - Acquisitions and
Engineering since joining St. Mary in 1996. He was previously with Meridian Oil
Company as Regional Engineer and with ARCO Oil and Gas Company in Planning and
Evaluation.
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 of
Directors 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 moved.
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.
23
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 closing
prices for the quarterly periods in 2000 and 1999, 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, 2000 $34.813 $19.125
September 30, 2000 24.063 14.969
June 30, 2000 21.032 15.375
March 31, 2000 15.469 11.250
December 31, 1999 $13.563 $10.156
September 30, 1999 14.875 10.938
June 30, 1999 10.547 8.063
March 31, 1999 10.250 7.555
Holders. As of March 9, 2001, the number of record holders of St.
Mary's common stock was 266. 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 quarterly in each of
the years 1997 through 2000. We expect that our practice of paying dividends on
our common stock will continue, although the payment of future dividends will
continue to depend on our earnings, capital requirements, financial condition
and other factors. Beginning in 2001 St. Mary plans to pay dividends on a
semi-annual basis. Dividends paid totaled $2,774,000 in 2000 and $2,193,000 in
1999.
Restricted Shares. St. Mary issued 5,332,374 shares to the
shareholders of King Ranch, Inc. for the acquisition of King Ranch Energy, Inc.
when it merged in December 1999. Those shares are subject to contractual
restrictions on transfer until March 31, 2001. The restriction prevents
transfers other than for estate planning reasons until March 31, 2001. We also
issued 518,988 restricted shares 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.
24
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 ended December 31, 2000 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,
------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(In thousands, except per share data)
Income Statement Data:
Operating revenues:
Oil and gas production $ 188,407 $ 73,387 $ 71,413 $ 76,603 $ 57,207
Other 7,259 1,527 8,096 15,282 2,777
--------- --------- --------- --------- ---------
Total operating revenues 195,666 74,914 79,509 91,885 59,984
--------- --------- --------- --------- ---------
Operating expenses:
Oil and gas production 38,461 19,574 17,770 16,097 13,330
Depletion, depreciation & amortization 40,129 22,574 24,912 18,366 12,732
Impairment of proved properties 4,449 3,982 17,483 5,202 408
Exploration 9,633 11,593 11,705 6,847 8,185
Abandonment and impairment of
unproved properties 1,841 6,616 4,457 2,077 1,469
General and administrative 11,166 9,172 7,097 7,645 7,603
Other 1,437 1,802 9,304 606 (1,194)
--------- --------- --------- --------- ---------
Total operating expenses 107,116 75,313 92,728 56,840 42,533
--------- --------- --------- --------- ---------
Income (loss) from operations 88,550 (399) (13,219) 35,045 17,451
Non-operating (expense) income 737 75 (1,027) (99) (1,951)
Income tax (expense) benefit (33,667) 406 5,415 (12,325) (5,333)
--------- --------- --------- --------- ---------
Income (loss) from continuing operations 55,620 82 (8,831) 22,621 10,167
Gain on sale of discontinued operations,
net of income taxes - - 34 488 159
--------- --------- --------- --------- ---------
Net income (loss) $ 55,620 $ 82 $ (8,797) $ 23,109 $ 10,326
========= ========= ========= ========= =========
Basic net income (loss) per common share:
Income (loss) from continuing operations $ 2.00 $ - $ (0.40) $ 1.07 $ 0.58
Gain on sale of discontinued operations - - - 0.02 0.01
--------- --------- --------- --------- ---------
Basic net income (loss) per share $ 2.00 $ - $ (0.40) $ 1.09 $ 0.59
========= ========= ========= ========= =========
Diluted net income (loss) per common share:
Income (loss) from continuing operations $ 1.97 $ - $ (0.40) $ 1.05 $ 0.57
Gain on sale of discontinued operations - - - 0.02 0.01
--------- --------- --------- -------- ---------
Diluted net income (loss) per share $ 1.97 $ - $ (0.40) $ 1.07 $ 0.58
========= ========= ========= ======== =========
Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.08
Basic weighted average common shares
outstanding 27,781 22,198 21,874 21,240 17,518
Diluted weighted average common shares
outstanding 28,271 22,329 21,874 21,506 17,652
25
Years Ended December 31,
------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(In thousands, except per share data)
Balance Sheet Data (end of period):
Working capital $ 40,639 $ 13,440 $ 9,785 $ 9,618 $ 13,926
Net property and equipment 252,411 180,664 143,825 157,481 101,510
Total assets 321,895 230,438 184,497 212,135 144,271
Long-term obligations 22,000 13,000 19,398 22,607 43,589
Total stockholders' equity 250,136 188,772 134,742 147,932 75,160
Other Data:
EBITDA (1) $ 128,679 $ 22,175 $ 11,693 $ 53,411 $ 30,183
Net cash provided by operating activities 92,267 40,755 45,386 43,111 24,205
Net cash used in investing activities (112,868) (22,243) (36,982) (67,477) (45,175)
Net cash (used in) provided by
financing activities 13,025 (12,138) (7,695) 28,140 22,585
Capital and exploration expenditures, cash
and noncash 125,184 91,184 57,855 89,213 52,601
[FN]
- ------------
(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.
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION
Overview
The year ended December 31, 2000 saw continued weakness in the
perceived supply of crude oil and considerable volatility in the price. Crude
oil producers who in 1999 had hedged 2000 production at prices which were
reasonable at the time and much better than prices received in 1998 recognized
hedging losses in 2000. Natural gas producers had been experiencing relative
price stability, but during 2000 the gas "bubble" burst as storage facilities
were unable to replenish their reserves during the summer and the country faced
its coldest winter in the last four years. Consequently, natural gas prices
increased steadily throughout the year as the country experienced shortages.
Natural gas producers who had hedged their 2000 production in 1999 or early 2000
at prices that were considered reasonable at that time also recognized hedging
losses. The positive aspect is that those companies who did not hedge all of
their production experienced considerable benefits from price increases on their
unhedged production. We are now seeing record rig utilization, cost increases
for operations and drilling, more expensive acquisitions and the door for equity
capital is starting to open.
As we note in our discussion of results of operations, St. Mary had an
extraordinary year in 2000 operating in this environment. Based on our forecast
in Outlook below, subject to uncertainties specified in our cautionary statement
about forward looking statements, if prices for crude oil and natural gas remain
strong we project another outstanding year of operations for 2001.
27
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 KRE. After the acquisition, KRE's name was changed to St. Mary
Energy Company or SMEC.
The following table sets forth selected operating data for the periods
indicated:
Years Ended December 31,
------------------------
2000 1999 1998
---- ---- ----
(In thousands, except per volume data)
Oil and gas production revenues:
Gas production.............................................. $ 131,979 $ 50,482 $ 54,868
Oil production.............................................. 56,428 22,905 16,545
--------- --------- ---------
Total.................................................... $ 188,407 $73,387 $71,413
========= ========= =========
Net production:
Gas (MMcf).................................................. 38,346 22,805 25,440
Oil (MBbls)................................................. 2,398 1,383 1,275
--------- --------- ---------
MMCFE....................................................... 52,731 31,103 33,090
--------- --------- ---------
Average sales price (1):
Gas (per Mcf)............................................... $ 3.44 $ 2.21 $ 2.16
Oil (per Bbl)............................................... $ 23.53 $ 16.56 $ 12.98
Oil and gas production costs:
Lease operating expenses.................................... $ 25,567 $ 13,641 $ 12,929
Transportation costs........................................ 1,817 893 765
Production taxes............................................ 11,077 5,040 4,076
--------- --------- ---------
Total.................................................... $38,461 $19,574 $17,770
========= ========= =========
Additional per MCFE data:
Sales price (see Discussion under Accounting Matters)....... $ 3.57 $ 2.36 $ 2.16
Lease operating expenses.................................... (.48) (.44) (.39)
Transportation costs........................................ (.04) (.03) (.03)
Production taxes............................................ (.21) (.16) (.12)
--------- --------- ---------
Operating margin......................................... $ 2.84 $ 1.73 $ 1.62
========= ========= =========
Depletion, depreciation and amortization.................... $ .76 $ .73 $ .75
Impairment of proved properties............................. $ .08 $ .13 $ .53
General and administrative.................................. $ .21 $ .29 $ .22
[FN]
(1) Includes the effects of the Company's hedging activities.
28
2000 to 1999 Comparison
Oil and Gas Production Revenues. St. Mary experienced a record year
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. Crude oil and natural gas futures prices at December 31,
2000 were very good, but we do not expect to see the dramatic increases in our
average realized price received in 2001 that we experienced 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. St. Mary's KRE 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 current pricing 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 ("KMOC") 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. Oil and gas production expenses
include lease operating expenses, production taxes and, as discussed under
Accounting Matters, transportation 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 $.73 for 2000
compared with $.63 in 1999. As we indicate in Outlook below, we expect this
trend to continue. We believe that competition for resources will cause costs to
increase in 2001. St. Mary experienced a general $.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 $.04 per MCFE increase is due to lease
operating expenses and increased production taxes on increased revenue in the
higher-cost Williston and Permian Basins.
29
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 $.76 in 2000 compared to $.73 in
1999. During the first three quarters of 2000 St. Mary had 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 St. Mary 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 $.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
include a declining performance adjustment of $703,000 from the West Cameron
Block 39 prospect in the Gulf of Mexico. Marginal well impairments include
$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 is 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. As
indicated in Outlook below, we anticipate general and administrative expenses
will increase again in 2001 due in large part to our incentive bonus plans.
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 the current year.
30
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.
1999 to 1998 Comparison
Oil and Gas Production Revenues. Oil and gas production revenues
increased $2.0 million, or 3% to $73.4 million in 1999 compared to $71.4 million
in 1998. Revenue from gas production decreased $4.4 million or 8%. This decrease
resulted from a gas production volume decrease of 10% partially offset by a 2%
increase in the average realized gas price to $2.17 per Mcf in 1999. Revenue
from oil production increased $6.4 million or 38%. This increase was a result of
an oil production volume increase of 8% and a 28% increase in the average
realized oil price to $16.56 per Bbl in 1999. Average net daily production
declined to 85.2 MMCFE in 1999 compared to 90.6 MMCFE in 1998. The increase in
oil production occurred as a result of the Nance acquisition, production
increases at the Parkway Delaware Unit waterflood and the drilling of successful
wells in Montana. Gas production decreased as a result of the loss of production
at the South Horseshoe Bayou Field and the sale of certain Oklahoma properties
in December 1998. This decrease reduced the average daily production.
St. Mary hedged approximately 41.4% or 572 MBbls of its oil production
for 1999 and realized a $2.0 million decrease in oil revenue attributable to
hedging compared to a $435,000 increase in 1998. Without these contracts we
would have received an average price of $18.01 per Bbl in 1999 compared to
$12.64 in 1998. St. Mary also hedged approximately 56.2% of its 1999 gas
production or 14.1 million MMBtu and realized a $558,000 decrease in gas revenue
attributable to hedging compared to a $1.4 million increase in gas revenues in
1998. Without these contracts we would have received an average price of $2.19
per Mcf in 1999 compared to $2.07 in 1998.
Oil and Gas Production Expenses. Please see the discussion of EITF
00-10 under Accounting Matters. Total production costs increased $1.8 million,
or 10% in 1999 to $19.6 million compared with $17.8 million in 1998, while total
production costs per MCFE increased 17% to $.63 in 1999 compared with $.54 in
1998. A $396,000 increase in LOE workover costs and a $968,000 increase in LOE
relating to the Nance and KRE acquisitions were offset by a $591,000 decrease in
LOE at South Horseshoe Bayou and the December 1998 sale of producing properties
in Oklahoma. A $705,000 increase in production taxes was the result of higher
prices for oil production. The increase in the per MCFE amount is also due to a
10% decrease in gas production volumes caused by a reduction in volumes at South
Horseshoe Bayou and the December 1998 sale of producing properties in Oklahoma
which had lower production costs per MCFE.
Depreciation, Depletion, Amortization and Impairment. DD&A decreased
$2.3 million or 9% to $22.6 million in 1999 compared with $24.9 million in 1998.
DD&A expense per MCFE decreased 4% to $.73 in 1999 compared to $.75 in 1998 due
to low prices that affected the Company's oil and gas reserves and net book
value at December 31, 1998 and the subsequent recovery of prices which increased
the Company's oil and gas reserves during 1999. This effect was offset during
1999 by a 10% reduction in gas production caused by decreased production at
South Horseshoe Bayou, the December 1998 sale of producing properties in
Oklahoma with lower DD&A expense per MCFE and decreased royalty production from
the fee lands.
31
St. Mary recorded a $4.0 million impairment of proved oil and gas
properties in 1999 compared with $17.5 million in 1998. Impairments caused by
reserve reductions in under-performing properties in 1999 include $2.6 million
related to the Larose prospect, $246,000 related to the Greensburg prospect and
$264,000 related to several other prospects in Louisiana. A total of $734,000 of
impairment related to nine prospects in Oklahoma.
Abandonment and impairment of unproved properties increased $2.1
million or 48% to $6.6 million in 1999 compared to $4.5 million in 1998 due to
the Company's impairment of its remaining costs at South Horseshoe Bayou.
General and Administrative. General and administrative expenses
increased $2.1 million or 29% to $9.2 million in 1999 compared to $7.1 million
in 1998 due to a $1.9 million increase in compensation and benefit related
expenses including a $477,000 increase related to the Company's Stock
Appreciation Rights plan.
Other. This expense increased $1.0 million to $1.8 million from
$802,000 in 1998 due to increased activity in St. Mary's litigation seeking to
recover damages from the drilling contractor in connection with the St. Mary
Land & Exploration No. 1 well at South Horseshoe Bayou.
Non-Operating Income and Expense. Net non-operating expense decreased
$1.1 million to $75,000 of net income in 1999 compared to $1.0 million of net
expense in 1998 due to decreased interest expense attributable to reduced
long-term debt during 1999, and recognition of interest income from loans made
to Summo Minerals Corporation. Debt was decreased in 1999 with proceeds from the
sale of the Oklahoma properties in late 1998.
Income Taxes. Income taxes provided a net benefit of $406,000 for 1999
resulting in an effective tax rate of 125%. The effective rate reflects the
effect of the book net operating loss before tax and the compounded effect of
alternative fuel credits allowed under Internal Revenue Code Section 29 incurred
in years when St. Mary reports a pre-tax book loss.
Net Income (Loss). Net income for 1999 was $82,000 compared to a net
loss of $8.8 million for 1998. A 2% increase in gas prices, a 28% increase in
oil prices and an 8% increase in oil production volumes were partially offset by
a 10% decrease in gas production volumes for the year and resulted in a $1.9
million or 3% increase in oil and gas production revenues. The combination of
impairments of proved properties and DD&A decreased $15.8 million from 1998
amounts and were partially offset by a $1.7 million increase in oil and gas
production costs, a $2.2 million increase in unproved property impairments, and
a $2.1 million increase in general and administrative expenses. A $1.2 million
increase in other revenues and a $1.1 million decrease in non-operating income
and expenses were partially offset by a $1.6 million increase in minority
interest and other expense. Income tax benefit decreased by $5.0 million in
1999. Activity in 1998 not affecting net income in 1999 included $7.7 million in
gains on sales of proved properties, a $4.6 million writedown of the receivable
from KMOC and $4.6 million in losses related to St. Mary's investment activity
in Summo Minerals.
32
Liquidity and Capital Resources
St. Mary's primary sources of liquidity are the cash provided by
operating activities, debt financing, sales of non-strategic properties and
access to the capital markets. Its cash needs are for the acquisition,
exploration and development of oil and gas properties and for the payment of
debt obligations, trade payables, general corporate expenses and stockholder
dividends. Exploration and development programs are generally financed from
internally generated cash flow, bank debt and cash and cash equivalents on hand.
The capital expenditure budget is continually reviewed based on changes in cash
flow and other factors.
Cash Flow. 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 provided by operating activities decreased 10% to $40.8
million in 1999 compared to $45.4 million in 1998. The decrease was caused by a
$4.6 million decrease in accounts payable related to oil and gas production
costs and general and administrative expense. The $1.9 million increase in oil
and gas revenues was offset by a corresponding increase in accrued oil and gas
receivables. A $1.6 million increase in minority interest and other operating
expense was offset by a $764,000 increase in other revenues and a $1.1 million
decrease in cash paid for interest expense.
Exploratory dry hole costs are included in cash flows from investing
activities even though these costs are expensed as incurred. If exploratory dry
hole costs had been included in operating cash flows, the net cash provided by
operating activities would have been $90.9 million, $35.8 million, and $40.5
million in 2000, 1999, and 1998, respectively.
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 used in investing activities decreased $14.8 million or 40%
in 1999 to $22.2 million compared to $37.0 million in 1998. The decrease is due
to reduction in capital expenditures, $2.1 million received from the sale of the
subsidiary that held shares of KMOC stock, $2.6 million from the disposition of
a portion of St. Mary's investment in Summo and $12.7 million in cash received
as a result of St. Mary's purchase of Nance and KRE offset by a $20.9 million
decrease in proceeds received from property sales. Nance and KRE were acquired
with St. Mary common stock. Consequently, the value of the common stock issued
is not reflected in net cash used in investing activities. Total 1999 capital
expenditures for cash, including acquisitions of oil and gas properties,
decreased $18.3 million or 31% to $40.3 million in 1999 compared to $58.6
million in 1998 due to a decrease in drilling activity in 1999.
If exploratory dry hole costs had been included in operating cash
flows rather than in investing cash flows, net cash used in investing activities
would have been $111.5 million, $17.2 million, and $32.1 million in 2000, 1999,
and 1998, respectively.
33
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 discussed below.
Net cash used in financing activities increased $4.4 million to $12.1
million in 1999 compared to $7.7 million in 1998. The $9.8 million decrease in
long-term debt in 1999 compared to the $3.2 million decrease in 1998 was
partially offset by a $1.9 million decrease in stock repurchase payments.
St. Mary had $6.6 million in cash and cash equivalents and had working
capital of $40.6 million as of December 31, 2000 compared to $14.2 million in
cash and cash equivalents and working capital of $13.4 million as of December
31, 1999.
Credit Facility. On June 27, 2000, St. Mary entered into an agreement
to amend the existing long-term revolving credit agreement. The maximum loan
amount remains at $200.0 million. 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. As of December 31, 2000 the borrowing base as
determined by the lender was $140.0 million. The accepted borrowing base was
$40.0 million at December 31, 2000. The credit agreement has a maturity date of
December 31, 2006, and includes a revolving period that matures on June 30,
2003. We can elect to allocate up to 50% of available borrowings to a short-term
tranche due on June 25, 2003. St. Mary must comply with certain covenants
including maintenance of stockholders' equity at a specified level and
limitations on additional indebtedness. As of December 31, 2000 and 1999, $22.0
million and $13.0 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 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, 2000 St. Mary's debt to capitalization ratio
as defined under the credit agreement was 8.1%.
Common Stock. St. Mary is authorized to issue up to 50,000,000 shares
of its common stock. We anticipate proposing an increase in this amount to
100,000,000 shares of common stock for shareholder approval in 2001. See ITEM 5.
MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS for a
discussion of restricted shares.
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.
In August 1998 St. Mary's 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 St. Mary's common shares.
As of December 31, 2000 we have repurchased a total of 395,600 shares of St.
Mary's common stock under the program for $3.3 million at a weighted-average
price of $8.44 per share. In early 2001 we repurchased an additional 16,800
shares for a weighted-average price of $22.25 per share. We anticipate that
additional purchases of shares may occur as market conditions warrant. Such
purchases will be funded with internal cash flow and borrowings under St. Mary's
credit facility.
34
Capital and Exploration Expenditures. St. Mary's expenditures for
exploration and development of oil and gas properties and acquisitions are the
primary use of its capital resources. The following table sets forth certain
information regarding the costs incurred by us in our oil and gas activities
during the periods indicated.
Capital and Exploration Expenditures
------------------------------------
For the Years Ended
December 31,
------------
2000 1999 1998
---- ---- ----
(In thousands)
Development $ 48,996 $ 22,166 $ 32,191
Exploration 17,012 20,809 17,767
Acquisitions:
Proved 53,482 33,080 4,204
Unproved 5,694 15,129 3,693
-------- -------- -------
Total $125,184 $ 91,184 $ 57,855
======== ======== ========
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 St. Mary's 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 within the United States. The acquisition of
KRE in 1999 is an example of this strategy.
St. Mary's total costs incurred in 2000 increased $34.0 million or 37%
compared to 1999. This change reflects the increased activity we budgeted for
2000 and increased costs for drilling and acquisitions. Proved property
acquisitions increased $20.4 million in 2000. St. Mary made its largest
acquisition of oil and gas properties on December 28, 2000 when it acquired oil
and gas properties from JN Exploration and Production Limited Partnership, Colt
Resources Corporation, Princeps Partners, Inc., and The William G. Helis
Company, LLC for $32.0 million net of transaction costs and closing adjustments.
We utilized $22.0 million from our credit facility to fund a portion of this
acquisition. In several other acquisitions during 2000 St. Mary acquired
additional oil and gas interests in the Williston Basin for a total of $13.3
million. Post-closing and purchase price adjustments in 2000 relating to the KRE
acquisition totaled $3.4 million. Follow-on acquisitions relating to interests
purchased in the Permian Basin amounted to $2.6 million. Several smaller
acquisitions in other core areas were also completed during 2000 totaling $2.0
million. We spent $71.7 million in 2000 for unproved property acquisitions and
domestic exploration and development compared to $58.1 million in 1999 as a
result of increased drilling activity.
35
St. Mary's total costs incurred in 1999 increased $33.3 million or 58%
compared to 1998. Proved property acquisitions increased $28.9 million in 1999.
In June 1999 we acquired Nance and Quanterra Alpha Limited Partnership in a
stock transaction; the property acquisition amount included above was $6.1
million. Subsequent to this transaction, Nance as a wholly owned subsidiary of
St. Mary purchased $1.2 million of properties in several small acquisitions in
the Williston Basin. In December 1999 we acquired KRE in a stock transaction;
the property acquisition amount included above was $33.6 million. Certain
properties were acquired in Louisiana and the Gulf of Mexico for $2.8 million.
Several smaller acquisitions in other core areas were also completed during 1999
totaling $1.3 million. We spent $58.1 million in 1999 for unproved property
acquisitions and domestic exploration and development compared to $53.7 million
in 1998.
Outlook. Management believes that St. Mary's existing capital
resources, cash flows from operations and available borrowings are sufficient to
meet its anticipated capital and operating requirements for 2001.
We anticipate spending approximately $155.0 million for capital and
exploration expenditures in 2001 with $95 million allocated for ongoing
exploration and development and $60.0 million for acquisitions of producing
properties. Anticipated ongoing exploration and development expenditures for
each of St. Mary's core areas is as follows:
o Mid-Continent region $27.0 million
o Gulf Coast and Gulf of Mexico region $37.5 million
o ArkLaTex region $11.0 million
o Williston Basin $12.0 million
o Permian Basin and other $ 7.5 million
The amount not funded from our internally generated cash flow in 2001
can be funded from the remaining unused portion of our credit facility. The
amount and allocation of future capital and exploration expenditures will depend
on a number of factors, including the number 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
activities could lead to funding requirements for further development.
St. Mary enters 2001 with record high natural gas prices, good oil
prices, a strong production base and a strong balance sheet. Our industry has
been confronted with a gas bubble for 20 years. The bubble has burst and the
domestic economy is facing competition for a limited supply of natural gas. The
outlook for natural gas and oil prices has never been better, and St. Mary has
reduced its percentage of hedged oil and gas production. We expect to experience
competition for drilling rigs, and we expect drilling and service related costs
to increase. To take advantage of our prospect inventory and any potential
acquisitions, we have increased our capital expenditures budget by 24% over the
actual amount spent in 2000. Access to equity capital appears to be improving
but acquisitions appear to be more expensive. We believe we are well positioned
to capitalize on the current environment. We are forecasting the following
information for St. Mary in 2001:
o Production 56-58 BCFE
o Lease operating expense, including
production taxes and transportation $.80-.85/MCFE
o Depreciation, depletion and amortization $.78-.86/MCFE
o General and administrative expense $.28-.30/MCFE
36
o Current income taxes paid are expected
to approximate 50% of total tax expense
o Discretionary cash flows-a common industry
financial measure computed as net income
plus depreciation, depletion, amortization,
impairments, deferred taxes and exploration
expense $6.00-$6.50/common share
St. Mary seeks to protect its rate of return on acquisitions of
producing properties or drilling prospects by hedging when the economic criteria
from its evaluation and pricing model indicate it would be appropriate.
Management's strategy is to hedge cash flows from investments requiring a gas
price in excess of $3.25 per Mcf and an oil price in excess of $22.50 per Bbl in
order to meet minimum rate-of-return criteria. We anticipate this strategy will
result in the hedging of acquisitions. We generally limit St. Mary's 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 St. Mary's oil hedges to NYMEX prices and the majority of
gas hedges to various regional index prices associated with pipelines in
proximity to St. Mary's areas of gas production. Including hedges entered into
since December 31, 2000 we have hedged as follows:
Swaps - Averaged by year
- ------------------------
Average Quantity Average
Product Volumes/month Type Fixed price Duration
------- ------------- ---- ----------- --------
Natural Gas 118,000 MMBtu $4.42 01/01 - 12/01
Natural Gas 84,000 MMBtu $4.16 01/02 - 12/02
Oil 15,700 Bbls $22.88 01/01 - 12/01
Oil 4,600 Bbls $23.23 01/02 - 12/02
Collar Contracts Table
- ----------------------
Average
Product Volumes/month Ceiling Price Floor Price Duration
------- ------------- ------------- ----------- --------
Natural Gas 150,000 MMBtu $2.94 $2.30 01/01 - 12/01
Natural Gas 150,000 MMBtu $2.90 $2.30 01/01 - 12/01
Natural Gas 250,000 MMBtu $2.50 $3.04 01/01 - 03/01
Natural Gas 250,000 MMBtu $2.25 $2.79 04/01 - 10/01
Natural Gas 250,000 MMBtu $2.50 $2.98 11/01 - 12/01
Natural Gas 250,000 MMBtu $2.50 $2.98 01/01 - 03/01
Natural Gas 250,000 MMBtu $2.25 $2.72 04/01 - 10/01
Natural Gas 250,000 MMBtu $2.50 $2.93 11/01 - 12/01
Natural Gas 250,000 MMBtu $3.50 $2.40 01/01 - 12/01
Natural Gas 350,000 MMBtu $5.80 $3.00 01/01 - 12/01
Oil 7,500 Bbls $20.64 $16.44 01/01 - 12/01
Oil 7,500 Bbls $20.90 $16.70 01/01 - 12/01
Oil 15,000 Bbls $27.22 $19.00 01/01 - 12/01
Oil 7,000 Bbls $21.00 $18.00 01/01 - 12/01
Oil 10,000 Bbls $25.10 $19.50 01/01 - 12/01
We also have natural gas basis swap contracts in place that protect
our regional index prices. The hedged basis adjustments range from $0.010 to
negative $0.095.
37
All of these contracts expire by December 31, 2001. As of December 31,
2000 the estimated fair value of all of our contracts was a net liability of
$45.7 million. As of that date we had $397,000 in margin deposits outstanding to
counterparties.
On December 31, 2000, St. Mary owned 6,921 shares of KMOC stock as a
result of the July 2000 conversion of its production payment receivable.
Management believes that the current fair market value of the stock is in excess
of its carrying value.
On August 5, 2000, St. Mary and its partners assumed control of the
30,450-acre top lease in the North Ward Estes Field in Ward County, Texas. In
June 2000 we joined with our partners and sold the rights to approximately 260
shallow producing wells in this field to the previous operator. St. Mary
received $2.0 million in proceeds from the sale. We now have a 21.4% working
interest in the production from 95 wellbores and the future development and
production rights on this 50 square mile property. The top lease will continue
in effect for as long as oil and/or gas is produced in paying quantities.
Accounting Matters
In June 1998, the Financial Accounting Standards Board or FASB issued
Statement of Financial Accounting Standards or SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," effective beginning January 1,
2001. The Statement requires companies to report all derivatives at fair value
as either assets or liabilities and bases the accounting treatment of the
derivatives on the reasons an entity holds the instrument. In June 2000 the FASB
issued SFAS No, 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities." SFAS No. 138 amends and clarifies certain elements of SFAS
No. 133, including expansion of the normal purchases and normal sales exception.
St. Mary adopted SFAS No. 133 effective January 1, 2001. The adoption of SFAS
No. 133 on January 1, 2001 results in St. Mary recording a net derivative
liability of $45.7 million, income of $26,000 from cumulative effect of
accounting change in the statement of operations, and a charge to accumulated
other comprehensive income in stockholders' equity of $28.6 million, net of
deferred taxes.
In September 2000 the Emerging Issues Task Force or EITF reached a
consensus on EITF Issue 00-10, "Accounting for Shipping and Handling Fees and
Costs." This EITF consensus requires companies to isolate shipping and handling
revenues or costs and classify them as a separate item on the statement of
operations. We have interpreted this EITF consensus to require that St. Mary
separate transportation charges that had previously been netted with revenue
into oil and gas production costs on our income statement. St. Mary has complied
with this EITF consensus for the year ended December 31, 2000 and all prior
periods have been adjusted to reflect this change.
Effects of Inflation and Changing Prices
Within the United States inflation has had a minimal effect on St.
Mary. 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 St.
Mary's producing properties in relation to markets for the 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.
38
Material changes in oil and gas prices affect the current and future
value of St. Mary's estimated proved reserves and its borrowing capability,
which is largely based on the value of such proved reserves. Rising natural gas
prices and volatile oil prices characterized most of 2000. The supply of
drilling rigs, personnel, supplies and services has become tighter and the cost
of each of these items has increased. If oil and gas prices continue at current
levels, we expect increased competition for limited resources resulting in
shortages of both materials and personnel and corresponding increases in the
cost to St. Mary of exploration, drilling and production of oil and gas. A
mitigating factor for us is our good relationships with our vendors and our
reputation for timely payment of invoices, a positive by-product of St. Mary's
strong balance sheet.
Environmental
St. Mary's compliance with applicable environmental regulations has
not resulted in any significant capital expenditures or materially adverse
effects to our liquidity or results of operations. We believe we are in
substantial compliance with environmental regulations and foresee that no
material expenditures will be incurred in the future. However, we are unable to
predict the impact that future compliance with regulations may have on future
capital expenditures, liquidity and results of operations.
ITEM 7A. QUANTITATIVE AND QUALITATTIVE 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.
St. Mary's 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 St. Mary's 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 St. Mary's hedging of the basis differential accorded to
the pipelines relative to its areas of production.
39
A hypothetical $.10 change in St. Mary's year-end market prices for
natural gas swaps and futures contracts on a notional amount of 19.2 million
MMBtu would have caused a potential $1.3 million change in net income (loss)
before income taxes for contracts in place on December 31, 2000. A hypothetical
$1.00 change in the year-end market prices for crude oil swaps and future
contracts on a notional amount of 807 MBbls would have caused a potential
$528,000 change in net income (loss) before income taxes for oil contracts in
place on December 31, 2000. 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 held by St.
Mary at December 31, 2000, which are sensitive to changes in interest rates. For
fixed-rate debt, interest rate changes affect the fair market value but do not
impact results of operations or cash flows. Conversely for floating rate debt,
interest rate changes generally do not affect the fair market value but do
impact future results of operations and cash flows, assuming other factors are
held constant. The carrying amount of our floating rate debt approximates its
fair value. At December 31, 2000, we had floating rate debt of $22.0 million and
had no fixed rate debt. Assuming constant debt levels, the results of operations
and cash flows impact for the next year resulting from a one percentage point
change in interest rates would be approximately $220,000 before taxes.
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 2001 annual meeting of shareholders to be
filed within 120 days from December 31, 2000. The information required by this
Item concerning St. Mary's executive officers is included in Part I--Item
4A--Executive Officers of the Registrant.
40
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 2001
annual meeting of shareholders to be filed within 120 days from December 31,
2000.
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 2001
annual meeting of shareholders to be filed within 120 days from December 31,
2000.
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 2001
annual meeting of shareholders to be filed within 120 days from December 31,
2000.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
Report of Independent Public Accountants............................. F-1
Consolidated Balance Sheets.......................................... F-2
Consolidated Statements of Operations................................ F-3
Consolidated Statements of Stockholders' Equity...................... F-4
Consolidated Statements of Cash Flows................................ F-5
Notes to Consolidated Financial Statements........................... F-7
All other schedules are omitted because the required information is
not applicable or is not present in amounts sufficient to require submission of
the schedule or because the information required is included in the Consolidated
Financial Statements and Notes thereto.
(b) Reports on Form 8-K. There were no reports on Form 8-K filed
during the quarter ended December 31, 2000.
41
(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 dated November 11, 1992 (filed as
Exhibit 3.1A to the registrant's Registration Statement on
Form S-1 (Registration No. 33-53512) and incorporated herein
by reference)
3.2 Certificate of Amendment to Certificate of Incorporation of
St. Mary Land & Exploration Company dated June 22, 1998
(filed as Exhibit 3.2 to the registrant's Registration
Statement on Form S-4 (Registration No. 333-85537) filed on
August 19, 1999 and incorporated herein by reference)
3.3 Restated By-laws of St. Mary Land & Exploration Company as
of June 15, 1994 (filed as Exhibit 3.3 to the registrant's
Registration Statement on Form S-4 (Registration No.
333-85537) filed on August 19, 1999 and incorporated herein
by reference)
4.1 St. Mary Land & Exploration Company Shareholder Rights Plan
adopted on July 15, 1999 (filed as Exhibit 4.1 to the
registrant's Quarterly Report on Form 10-Q/A (File No.
0-20872) for the quarter ended June 30, 1999 and
incorporated herein by reference)
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)
42
Exhibit
Number Description
------ -----------
10.4 Net Profits Interest Bonus Plan (filed as Exhibit 10.6 to
the registrant's Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by
reference) Statement on Form S-1 (Registration No. 33-53512)
and incorporated herein by reference)
10.5 Summary Plan Description/Pension dated January 1, 1985
(filed as Exhibit 10.7 to the registrant's Registration
Statement on Form S-1 (Registration No. 33-53512) 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 Custom 401(k) Plan and Trust (filed
as Exhibit 10.10 to the registrant's Registration Statement
on Form S-1 (Registration No. 33-53512) and incorporated
herein by reference)
10.8 Stock Option Agreement - Mark A. Hellerstein (filed as
Exhibit 10.11 to the registrant's Registration Statement on
Form S-1 (Registration No. 33-53512) and incorporated herein
by reference)
10.9 Stock Option Agreement - Ronald D. Boone (filed as Exhibit
10.12 to the registrant's Registration Statement on Form S-1
(Registration No. 33-53512) and incorporated herein by
reference)
10.10 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)
10.11 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)
10.12 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)
10.13 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)
10.14 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 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)
10.16 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)
43
Exhibit
Number Description
------ -----------
10.17 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)
10.18 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)
10.19 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)
10.20 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)
10.21 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)
10.22 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)
10.23 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)
10.24 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)
10.25 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 3, 2001 and incorporated herein by reference)
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)
27.1* Financial Data Schedule
----------------------------
* Filed with this form 10-K.
(d) Financial Statement Schedules. See Item 14(c) above.
44
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, 2000 and 1999, and the related consolidated statements of
operations, stockholders' equity, and cash flows for each of the three
years in the period ended December 31, 2000. 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, 2000
and 1999, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United
States.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado,
February 20, 2001.
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,
------------
2000 1999
---- ----
Current assets:
Cash and cash equivalents $ 6,619 $ 14,195
Accounts receivable 55,068 22,971
Prepaid expenses and other 2,134 2,199
Deferred income taxes 163 90
--------- ---------
Total current assets 63,984 39,455
--------- ---------
Property and equipment (successful efforts method), at cost:
Proved oil and gas properties 385,076 292,323
Less accumulated depletion, depreciation and amortization (171,412) (142,680)
Unproved oil and gas properties, net of impairment allowance
of $7,956 in 2000 and $8,984 in 1999 35,497 28,556
Other property and equipment, net of accumulated depreciation of $3,600
in 2000 and $3,033 in 1999 3,250 2,465
--------- ---------
252,411 180,664
--------- ---------
Other assets:
Khanty Mansiysk Oil Corporation receivable and stock 1,651 5,110
Other assets 3,849 5,209
--------- ---------
5,500 10,319
--------- ---------
$ 321,895 $ 230,438
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 23,345 $ 26,015
--------- ---------
Total current liabilities 23,345 26,015
--------- ---------
Long-term liabilities:
Long-term debt 22,000 13,000
Deferred income taxes 24,820 501
Other noncurrent liabilities 987 1,835
--------- ---------
47,807 15,336
--------- ---------
Commitments and contingencies (Notes 1,6,7,8)
--------- ---------
Minority interest 607 315
--------- ---------
Stockholders' equity:
Common stock, $.01 par value: authorized - 50,000,000 shares; issued and
outstanding - 28,553,826 shares in 2000 and 27,893,910 shares in 1999 286 279
Additional paid-in capital 132,973 123,974
Treasury stock - at cost: 395,600 shares in 2000 and 365,600 shares in 1999 (3,339) (2,995)
Retained earnings 120,075 67,230
Unrealized net gain on marketable equity securities available for sale 141 284
--------- ---------
Total stockholders' equity 250,136 188,772
--------- ---------
$ 321,895 $ 230,438
========= =========
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,
--------------------------------
2000 1999 1998
---- ---- ----
Operating revenues:
Oil and gas production $188,407 $ 73,387 $ 71,413
Gain (loss) on sale of proved properties 3,404 (55) 7,685
Other oil and gas revenue 1,421 1,166 352
Gain on sale of KMOC stock 2,156 - -
Other revenues 278 416 59
-------- -------- --------
Total operating revenues 195,666 74,914 79,509
-------- -------- --------
Operating expenses:
Oil and gas production 38,461 19,574 17,770
Depletion, depreciation and amortization 40,129 22,574 24,912
Impairment of proved properties 4,449 3,982 17,483
Exploration 9,633 11,593 11,705
Abandonment and impairment of unproved properties 1,841 6,616 4,457
General and administrative 11,166 9,172 7,097
Writedown of investments - - 8,502
Other 1,437 1,802 802
-------- -------- --------
Total operating expenses 107,116 75,313 92,728
-------- -------- --------
Income (loss) from operations 88,550 (399) (13,219)
Nonoperating income and (expense):
Interest income 897 1,008 638
Interest expense (160) (933) (1,665)
-------- -------- --------
Income (loss) from continuing operations before income taxes 89,287 (324) (14,246)
Income tax expense (benefit) from continuing operations 33,667 (406) (5,415)
-------- -------- --------
Income (loss) from continuing operations 55,620 82 (8,831)
Gain on sale of discontinued operations, net of taxes
of $17 in 1998 - - 34
-------- -------- --------
Net income (loss) $ 55,620 $ 82 $ (8,797)
======== ======== ========
Basic earnings per common share:
Income (loss) from continuing operations $ 2.00 $ - $ (.40)
Gain on sale of discontinued operations - - -
-------- -------- --------
Basic net income (loss) per common share $ 2.00 $ - $ (.40)
======== ======== ========
Diluted earnings per common share:
Income (loss) from continuing operations $ 1.97 $ - $ (.40)
Gain on sale of discontinued operations - - -
-------- -------- --------
Diluted net income (loss) per common share $ 1.97 $ - $ (.40)
======== ======== ========
Basic weighted average shares outstanding 27,781 22,198 21,874
======== ======== ========
Diluted weighted average shares outstanding 28,271 22,329 21,874
======== ======== ========
The accompanying notes are an integral part
of these consolidated financial statements.
F-3
ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands, except share amounts)
Accumulated
Common Stock Additional Treasury Stock Other Total
--------------- Paid-in Retained ---------------- Comprehensive Stockholder's
Shares Amount Capital Earnings Shares Amount Income Equity
--------------------------------------------------------------------------------------
Balance, December 31, 1997 21,960,846 $ 220 $ 67,384 $ 80,328 - $ - $ - $ 147,932
Comprehensive income:
Net loss - - - (8,797) - - - (8,797)
-------
Total comprehensive income (8,797)
-------
Cash dividends, $ .10 per share - - - (2,190) - - - (2,190)
Treasury stock purchases - - - - (295,600) (2,470) - (2,470)
Issuance for Employee Stock Purchase Plan 16,848 - 172 - - - - 172
Directors' stock compensation 7,200 - 95 - - - - 95
------------------------------------------------------------------------------------
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, $ .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
------------------------------------------------------------------------------------
Balance, 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 55,447
-------
Cash dividends, $ .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 - - - - 2
Sale of common stock, including income
tax benefit of stock option exercises 619,220 6 8,597 - - - - 8,604
Directors' stock compensation 8,400 1 88 - - - - 89
------------------------------------------------------------------------------------
Balance, December 31, 2000 28,553,826 $ 286 $132,973 $120,075 (395,600) $(3,339) $ 141 $ 250,136
====================================================================================
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,
--------------------------------
2000 1999 1998
---- ---- ----
Reconciliation of net income (loss) to net cash provided
by operating activities:
Net income (loss) $ 55,620 $ 82 $ (8,797)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Gain on sale of KMOC stock (2,156) - -
Writedown of investments - - 8,502
Loss (gain) on sale of proved properties (3,404) 55 (7,685)
Depletion, depreciation and amortization 40,129 22,574 24,912
Impairment of proved properties 4,449 3,982 17,483
Exploration 1,389 4,991 4,892
Abandonment and impairment of unproved properties 1,841 6,616 4,457
Deferred income taxes 21,348 (898) (5,431)
Minority interest and other 1,260 29 1,039
-------- -------- --------
120,476 37,431 39,372
Changes in current assets and liabilities:
Accounts receivable (23,138) 4,983 6,502
Prepaid expenses and other 254 1,118 (2,247)
Accounts payable and accrued expenses (5,252) (2,812) 1,762
Deferred income taxes (73) 35 (3)
-------- -------- --------
Net cash provided by operating activities 92,267 40,755 45,386
-------- -------- --------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties 3,573 1,056 23,380
Capital expenditures (65,241) (34,994) (54,375)
Acquisition of oil and gas properties (52,076) (5,294) (4,204)
Sale of Chelsea Corporation - 2,066 -
Collections on loan to Summo Minerals Corporation - 2,163 -
Receipts from restricted cash - 720 7,275
Deposits to restricted cash - - (7,995)
Investment in St. Mary Energy Company (420) 12,068 -
Other 1,296 (28) (1,063)
-------- -------- --------
Net cash used in investing activities (112,868) (22,243) (36,982)
-------- -------- --------
Cash flows from financing activities:
Proceeds from long-term debt 45,050 29,750 54,579
Repayment of long-term debt (36,050) (39,537) (57,787)
Proceeds from sale of common stock 7,143 311 173
Repurchase of common stock (344) (525) (2,470)
Dividends paid (2,775) (2,193) (2,190)
Other 1 56 -
-------- -------- --------
Net cash provided by (used in) financing activities 13,025 (12,138) (7,695)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (7,576) 6,374 709
Cash and cash equivalents at beginning of period 14,195 7,821 7,112
-------- -------- --------
Cash and cash equivalents at end of period $ 6,619 $ 14,195 $ 7,821
======== ======== ========
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,
--------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
Cash paid for interest $ 764 $ 916 $ 1,650
Cash paid for income taxes 11,205 92 307
Cash paid for exploration expenses 9,032 11,826 11,873
In January 1998 the Company issued 7,200 shares of common stock to its directors
and recorded compensation expense of $94,500.
In January 1999 the Company issued 7,200 shares of common stock to its directors
and recorded compensation expense of $54,612.
In January 2000 the Company issued 8,400 shares of common stock to its directors
and recorded compensation expense of $88,368.
In June 2000 the Company received equipment valued at $1,202,000 as partial
proceeds for property sold.
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 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.:
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) -
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, 2000
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
due to 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;
Grand Junction, Colorado: Houston, Texas; Shreveport, Louisiana; Tulsa,
Oklahoma: Lafayette, Louisiana: and Billings, Montana. At December 31, 2000 and
1999, the Company had $11,093,000 and $12,120,000, 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.
F-7
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, 2000 based on total
expected abandonment costs of $10,611,000 and a liability of $8,627,000 as of
December 31, 1999 based on total expected abandonment costs of $10,446,000. This
liability is included in accumulated DD&A on the consolidated balance sheets.
The Company recorded $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, 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 with a
15% discount rate using escalated prices and including the estimated effects of
the Company's hedging contracts in place at year end. 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 2000, 1999 and 1998 the Company recorded impairment
charges for proved properties of $4,449,000, $3,982,000, and $17,483,000,
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.
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.
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.
F-8
Restricted Cash:
Proceeds from certain sales of oil and gas producing properties are
held in escrow and restricted for future acquisitions under a tax-free exchange
agreement. These funds are invested in money market funds consisting of
corporate commercial paper, repurchase agreements and U.S. Treasury obligations
and are carried at cost, which approximates market.
Gas Balancing:
The Company uses the sales method to account for gas imbalances. Under
this method, revenue is recorded on the basis of gas actually sold by the
Company. The Company records revenue for its share of gas sold by other owners
that cannot be volumetrically balanced in the future due to insufficient
remaining reserves. Related receivables totaling $1,035,000 at December 31, 2000
and $2,255,000 at December 31, 1999 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 $335,000 at December
31, 2000 and $733,000 at December 31, 1999 are included in other liabilities in
the accompanying balance sheets. The Company's remaining underproduced gas
balancing position is included in the Company's proved oil and gas reserves (see
Note 11).
Financial Instruments:
The Company periodically uses commodity contracts to hedge or
otherwise reduce a portion of the impact of oil and gas price fluctuations.
Gains and losses on commodity hedge contracts are recognized as an adjustment to
revenues when the related oil or gas is sold. Cash flows from such transactions
are included in oil and gas operations.
In connection with these hedging transactions, the Company may be
exposed to nonperformance by other parties to such agreements, thereby
subjecting the Company to current oil and gas prices. However, the Company only
enters into hedging contracts with large financial institutions that maintain
high credit ratings and does not anticipate nonperformance by these
institutions.
In June 1998, the Financial Accounting Standard Board or FASB issued
Statement of Financial Accounting Standards or SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," effective beginning January 1,
2001. The Statement requires companies to report all derivatives at fair value
as either assets or liabilities and bases the accounting treatment of the
derivatives on the reasons an entity holds the instrument. In June 2000 the FASB
issued SFAS No, 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities." SFAS No. 138 amends and clarifies certain elements of SFAS
No. 133, including expansion of the normal purchases and normal sales exception.
St. Mary adopted SFAS No. 133 effective January 1, 2001. The adoption of SFAS
No. 133 on January 1, 2001 results in St. Mary recording a net derivative
liability of $45,699,000 income of $26,000 from cumulative effect of accounting
change in the statement of operations, and a charge to other comprehensive
income in stockholders' equity of $28,587,000, net of deferred income taxes.
Income Taxes:
Deferred income taxes are provided on the difference between the tax
basis of an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively.
F-9
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 outstanding common shares and other dilutive
securities. Dilutive securities of the Company consist entirely of outstanding
options to purchase the Company's common stock. As of December 31, 2000, there
were 490,288 outstanding securities that would be considered dilutive. The
outstanding dilutive securities for the years ended December 31, 1999 and 1998
were 131,356 and 133,496, respectively. However, as the Company was in a net
loss position for the year ended December 31, 1998, all of the outstanding
options at that date were considered anti-dilutive and were therefore excluded
from the diluted earnings per share calculation. All net income of the Company
is available to common stockholders.
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 is presented in the
consolidated statements of stockholders' equity.
Major Customers:
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. During 1998 no individual customer accounted for 10% or more of the
Company's total oil and gas production revenue.
Industry Segment and Geographic Information:
The Company operates predominantly in one industry segment, which is
the exploration, development and production of natural gas and crude oil, and
all of the Company's operations are conducted in the United States.
Consequently, the Company currently reports as a single industry segment.
Use of Estimates in the Preparation of Financial Statements:
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
F-10
Reclassifications:
Certain amounts in the 1999 and 1998 consolidated financial statements
have been reclassified to correspond to the 2000 presentation.
In September 2000 the Emerging Issues Task Force or EITF reached a
consensus on EITF Issue 00-10, "Accounting for Shipping and Handling Fees and
Costs." This EITF consensus requires companies to isolate shipping and handling
revenues or costs and classify them as a separate item on the statement of
operations. We have interpreted this EITF consensus to require that St. Mary
separate transportation charges that had previously been netted with revenue
into oil and gas production costs on our income statement. St. Mary has complied
with this EITF consensus for the year ended December 31, 2000 and all prior
periods have been adjusted to reflect this change.
2. Accounts Receivable:
Accounts receivable are composed of the following:
December 31,
----------------------------------
2000 1999
----------------- ----------------
(In thousands)
Accrued oil and gas sales $38,159 $17,672
Due from joint interest owners 6,497 3,736
Receivable for sale of KMOC stock 7,009 -
Other 3,403 1,563
----------------- ----------------
Total accounts receivable $55,068 $22,971
================= ================
3. Acquisitions
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.
On December 17, 1999, the Company completed the purchase of 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 for the period from December 17 to December 31, 1999 are included in the
accompanying consolidated financial statements. The following unaudited pro
forma information presents a summary of the consolidated results of operations
as if the acquisition had occurred at the beginning of the periods presented:
For the Years Ended December 31,
---------------------------------------
1999 1998
------------- -------------
(unaudited, in thousands
except per share amounts)
Total operating revenues $ 118,654 $ 118,151
Net income (loss) from continuing operations $ 1,676 $ (7,523)
Basic and diluted net income (loss) per share from
continuing operations $ 0.09 $ (0.28)
These unaudited pro forma results have been prepared for comparative
purposes only and include certain adjustments such as reduced depreciation to
reflect lower fair market values assigned to oil and gas properties and
elimination of interest expense for a note payable to the parent corporation.
They do not purport to be indicative of results of operations that actually
would have resulted had the combination occurred at the beginning of the periods
presented, or future results of operations of the consolidated entities.
F-11
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 $32,000,000 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.
4. Income Taxes:
The provision for income taxes consists of the following:
For the Years Ended December 31,
----------------------------------------
2000 1999 1998
---- ---- ----
(In thousands)
Current taxes:
Federal $ 11,194 $ 219 $ 213
State 1,181 315 141
Deferred taxes 21,292 (940) (5,752)
--------- --------- ----------
Total income tax expense (benefit) $ 33,667 $ (406) $ (5,398)
========= ========= ==========
Continuing operations $ 33,667 $ (406) $ (5,415)
Discontinued operations - - 17
--------- --------- ----------
Total income tax expense (benefit) $ 33,667 $ (406) $ (5,398)
========= ========== ==========
The above taxes from continuing operations are net of alternative
fuels credits (Internal Revenue Code Section 29) of $79,000 in 2000, $283,000 in
1999, and $315,000 in 1998. The income tax payables as of December 31, 2000 and
1999 were reduced by $1,771,000 and $36,000, respectively, as a result of the
tax deductions for stock option exercises.
The components of the net deferred tax liability are as follows:
December 31,
--------------------------------
2000 1999
---- ----
(In thousands)
Deferred tax liabilities:
Oil and gas properties $ 32,031 $ 3,314
Other 282 581
---------- ----------
Total deferred tax liabilities 32,313 3,895
---------- ----------
Deferred tax assets:
Other, primarily employee benefits 5,005 611
State tax net operating loss carryforward 1,006 1,717
State and federal income tax benefit 1,817 876
Alternative minimum tax credit carryforward - 1,278
---------- ----------
Total deferred tax assets 7,828 4,482
Valuation allowance (172) (998)
---------- ----------
Net deferred tax assets 7,656 3,484
---------- ----------
Total net deferred tax liabilities 24,657 411
Current deferred income tax assets 163 90
---------- ----------
Non-current net deferred tax liabilities $ 24,820 $ 501
========== ==========
F-12
In accordance with SFAS No. 109 the Company records purchase
adjustments to its long-term deferred income tax liability accounts. These
adjustments more closely align book and tax basis at the time of acquisition and
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 and that are considered to be tax-free basis
transfers for tax accounting purposes. 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 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
adjusted its long-term deferred income tax liability account for a $2,972,000
increase due to purchase price adjustments related to its KRE stock acquisition.
At December 31, 2000, the Company had state net operating loss
carryforwards of approximately $24,700,000 that expire between 2001 and 2016.
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 2000 results from the state benefit of
federal income tax which is now offset by reversing state temporary differences.
Federal income tax expense and benefit differs from the amount that
would be provided by applying the statutory federal income tax rate to income
(loss) from continuing operations before income taxes for the following items:
For the Years Ended December 31,
--------------------------------
2000 1999 1998
---- ---- ----
(In thousands)
Federal statutory taxes $ 30,267 $ (137) $ (4,843)
Increase (reduction) in taxes resulting from:
State taxes (net of federal benefit) 4,342 105 191
Statutory depletion (71) (110) (119)
Alternative fuels credits (Section 29) (79) (283) (315)
Change in valuation allowance (826) (17) (289)
Other 34 36 (40)
--------- --------- ----------
Income tax expense (benefit) from
continuing operations $ 33,667 $ (406) $ (5,415)
========= ========= ==========
5. Long-term Debt and Notes Payable:
On June 27, 2000, St. Mary entered into an agreement to amend the
existing long-term revolving credit agreement dated June 30, 1998, and amended
December 1998. Under the second amendment the maximum loan amount was maintained
at $200,000,000 and the aggregate borrowing base was set at $140,000,000. The
lender may periodically re-determine the aggregate borrowing base depending upon
the value of the Company's oil and gas properties and other assets. The accepted
borrowing base was $40 million at December 31, 2000. The second amendment
extends the maturity date to December 31, 2006 and includes a revolving period
that matures on June 30, 2003. The Company can elect to allocate up to 50% of
available borrowings to a short-term tranche due June 26, 2001. No borrowings
were outstanding under this short-term election at December 31, 2000. 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, 2000 and 1999, $22.0 million and $13.0 million,
respectively, was outstanding under this credit agreement. These outstanding
balances accrue interest at rates determined by the Company's debt to total
capitalization ratio. During the revolving period of the loan, loan balances
accrue interest at the Company's option of either (1) the higher of the federal
funds rate plus 1/2% or the prime rate, or (2) LIBOR plus 3/4% when the
Company's debt to total capitalization is less than 30%, up to a maximum of
either (a) the higher of the federal funds rate plus 3/4% or the prime rate plus
1/4%, or (b) LIBOR plus 1-3/8% when the Company's debt to total capitalization
is equal to or greater than 50%. As of December 31, 2000, the Company's debt to
total capitalization ratio as defined under the credit agreement was 8.1%, and
the actual interest rate as defined in the agreement was 9.5%. The weighted
average interest rate paid in 2000 was 8.4%.
F-13
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)
----------------------- -------------------
2001 $ -
2002 -
2003 3,142
2004 6,286
2005 6,286
Thereafter 6,286
-------------
Total $22,000
=============
6. Commitments and Contingencies:
The Company leases office space under various operating leases with
terms extending as far as November 30, 2004. The Company has noncancelable
annual subleases with affiliates of approximately $79,000 for the same term as
the Company's primary office lease. Rent expense, net of sublease income, was
$782,000, $611,000, and $484,000 in 2000, 1999 and 1998, respectively. The
Company also leases office equipment under various operating leases. The annual
minimum lease payments for the next four years are presented below:
Years Ending
December 31, (In thousands)
----------------------- -------------------
2001 $ 971
2002 690
2003 341
2004 132
The Company realized a net loss of $33,641,000 on commodity contracts
for the year ended December 31, 2000, a net loss of $2,561,000 for the year
ended December 31, 1999, and a net gain of $1,873,000 for the year ended
December 31, 1998.
F-14
Including hedges entered into since December 31, 2000 the Company
currently has the following commodity contracts in place to hedge or otherwise
reduce the impact of oil and gas price fluctuations:
Swaps
-----
Average
Product Volumes/month Fixed Price Duration
------- ------------- ----------- --------
Natural Gas 118,000 M Mbtu $4.42 01/01 - 12/01
Natural Gas 84,000 MMBtu $4.16 01/02 - 12/02
Oil 15,700 Bbls $22.88 01/01 - 12/01
Oil 4,600 Bbls $23.23 01/02 - 12/02
Collar Contracts Table
----------------------
Average
Product Volumes/month Ceiling Price Floor Price Duration
------- ------------- ------------- ----------- --------
Natural Gas 150,000 MMBtu $2.94 $2.30 01/01 - 12/01
Natural Gas 150,000 MMBtu $2.90 $2.30 01/01 - 12/01
Natural Gas 250,000 MMBtu $2.50 $3.04 01/01 - 03/01
Natural Gas 250,000 MMBtu $2.25 $2.79 04/01 - 10/01
Natural Gas 250,000 MMBtu $2.50 $2.98 11/01 - 12/01
Natural Gas 250,000 MMBtu $2.50 $2.98 01/01 - 03/01
Natural Gas 250,000 MMBtu $2.25 $2.72 04/01 - 10/01
Natural Gas 250,000 MMBtu $2.50 $2.93 11/01 - 12/01
Natural Gas 250,000 MMBtu $3.50 $2.40 01/01 - 12/01
Natural Gas 350,000 MMBtu $5.80 $3.00 01/01 - 12/01
Oil 7,500 Bbls $20.64 $16.44 01/01 - 12/01
Oil 7,500 Bbls $20.90 $16.70 01/01 - 12/01
Oil 15,000 Bbls $27.22 $19.00 01/01 - 12/01
Oil 7,000 Bbls $21.00 $18.00 01/01 - 12/01
Oil 10,000 Bbls $25.10 $19.50 01/01 - 12/01
We also have natural gas basis swap contracts in place that protect
our regional index prices. The hedged basis adjustments range from $0.010 to
negative $0.095.
All of these contracts expire by December 31, 2001. As of December 31,
2000 the estimated fair value of all of these contracts was a net liability of
$45,699,000.
The Company seeks to protect its rate of return on acquisitions of
producing properties or drilling prospects by hedging when the economic criteria
from its evaluation and pricing model indicate it would be appropriate.
Management's strategy is to ensure certain minimum levels of operating cash flow
and to take advantage of windows of commodity prices favorable to an acquisition
or drilling prospect. 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.
F-15
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 50% 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
$1,957,000 for cash bonuses in 2000 that were paid in 2001, $2,293,000 for cash
bonuses in 1999 that were paid in 2000, and $71,000 for cash bonuses in 1998
that were paid in 1999. 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 $877,000
in 2000 and $574,000 in 1999 and $229,000 in 1998 relating to net profits
attributable to these properties.
In March 1992 the Company adopted a stock appreciation rights ("SAR")
plan for officers and directors. SARs vest over a four-year period, with payment
occurring five years after the date of grant. The SAR plan replaced the
restricted stock bonus plan. Between 1993 and 1996 the Company awarded a total
of 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. Compensation expense was reduced by $197,000 in 1998 under the
SAR plan. 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.
The resulting liability is classified as current and long-term in the
consolidated balance sheets, based on expected payment dates. SAR compensation
expense recorded after the termination of future awards relates to the vesting
of SARs outstanding at the time of the termination of future awards and to the
fluctuation of the stock price below the capped price of $10.25. The final SAR
payments were made in February 2001.
The Company has a defined contribution pension plan ("401(k) Plan")
which 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 amounted to $412,000,
$288,000, and $269,000 for the years ended December 31, 2000, 1999, and 1998,
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 2000 and 1999 shares issued under the Stock Purchase
Plan totaled 32,296 and 32,794, respectively. Total proceeds to the Company for
the issuance of these shares was $311,000 and $258,000 in 2000 and 1999,
respectively. The Company recorded compensation expense of $3,000 and $20,000 in
2000 and 1999, respectively, due to nonqualified dispositions of stock acquired
by employees under the Stock Purchase Plan. No compensation expense was recorded
in 1998 related to 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.
The options are now fully vested and expire ten years from the respective dates
of grant. In 1999 10,000 of these options were exercised, and in 2000 the
remaining 30,000 options were exercised. None of these options were outstanding
at December 31, 2000.
F-16
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 1999
the stockholders approved an increase in the number of shares of the Company's
common stock reserved for issuance under the Option Plans from 1,400,000 shares
to 3,300,000 shares. In 1998 the Company granted 503,548 options at an exercise
price of $9.25 per share, and no options were exercised under the Option Plans.
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. 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.
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,
------------------------------------------------------------------------------
2000 1999 1998
-------------------------- ------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------- ------------ ------------ ------------ ------------ ------------
Outstanding at beginning of year 1,998,254 $ 11.63 1,442,436 $ 11.28 958,686 $ 12.40
Granted 653,848 33.31 623,492 12.38 503,548 9.25
Exercised 619,220 11.05 17,660 4.95 - -
Forfeited 46,758 11.74 50,014 13.21 19,798 14.32
--------- --------- ---------
Outstanding at end of year 1,986,124 18.95 1,998,254 11.63 1,442,436 11.23
========= ========= =========
Options exercisable at year end 1,150,196 15.00 651,876 10.36 329,340 9.21
========= ========= =========
Weighted average fair value of
options granted during the year $ 14.75 $ 5.13 $ 4.08
========= ========= =========
A summary of additional information related to the options outstanding as
of December 31, 2000 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 - $ 10.25 548,963 5.5 years $ 9.69 471,495 $ 9.76
12.38 - 14.69 648,973 8.2 years 12.61 380,899 12.77
17.50 - 17.50 132,340 7.0 years 17.50 132,340 17.50
33.31 - 33.31 653,848 10.0 years 33.31 163,462 33.31
--------- ---------
Total 1,984,124 8.3 years 18.95 1,148,196 15.00
========= =========
F-17
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.
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 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 fair value of options granted in 1998 was estimated using the
following weighted-average assumptions: risk-free interest rate of 4.6%;
dividend yield of 1.08%; volatility factor of the expected market price of the
Company's common stock of 40.16%; and expected life of the options of 7.5 years.
The 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 value of the
options is amortized to expense over the options' vesting period. Had
compensation cost been determined based on the fair value at grant dates for
stock option awards consistent with SFAS No. 123, the Company's net income
(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,
--------------------
2000 1999 1998
---- ---- ----
(In thousands, except
per share amounts)
Net income (loss) applicable As reported $ 55,620 $ 82 $ (8,797)
to common stock Pro forma $ 52,515 $ (1,530) $ (9,682)
Basic earnings (loss) per share As reported $ 2.00 $ - $ (0.40)
Pro forma $ 1.89 $ (0.07) $ (0.45)
Diluted earnings (loss) per share As reported $ 1.97 $ - $ (0.40)
Pro forma $ 1.86 $ (0.07) $ (0.45)
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 and Other Postretirement Benefits
The Company's employees participate in a non-contributory pension plan
covering substantially all employees who meet age and service requirements (the
"Qualified Pension Plan"). The Company also has a supplemental non-contributory
pension plan covering certain management employees (the "Nonqualified Pension
Plan") and a postretirement non-contributory health care benefit plan (the
"Health Care Plan"). The Company's disclosures about pension and other
postretirement benefits are as follows:
Pension Plans Other Benefits
------------- --------------
December 31, December 31,
------------ ------------
2000 1999 2000 1999
---- ---- ---- ----
(In thousands) (In thousands)
Change in benefit obligations:
Benefit obligation at beginning of year $ 2,588 $ 2,470 $ 158 $ 185
Service Cost 257 178 11 25
Interest Cost 193 172 6 11
Actuarial gain (loss) 190 (84) (76) (63)
Benefits paid (174) (148) - -
-------- ------- ------- --------
Benefit obligation at end of year $ 3,054 $ 2,588 $ 99 $ 158
======== ======= ======== ========
Change in plan assets:
Fair value of plan assets at beginning of year $ 1,592 $ 1,212 $ - $ -
Actual return on plan assets (1) 165 - -
Employer contribution 358 363 - -
Benefits paid (174) (148) - -
-------- ------- ------- --------
Fair value of plan assets at end of year $ 1,775 $ 1,592 $ - $ -
======== ======= ======= ========
Funded Status $ (1,279) $ (996) $ (99) $ (158)
Unrecognized net actuarial gain (loss) 888 615 (72) (1)
Unrecognized prior service cost (28) (36) - -
-------- ------- ------- --------
Prepaid (accrued) benefit cost $ (419) $ (417) $ (171) $ (159)
======== ======= ======= ========
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 $357,000 at December 31, 2000, and $300,000
at December 31, 1999. There are no plan assets in the nonqualified plan due to
the nature of the plan. The Company's Health Care Plan also has no plan assets.
The aggregate benefit obligation for that plan is $171,000 as of December 31,
2000, and $159,000 as of December 31, 1999.
Assumptions used in the measurement of the Company's benefit
obligation are as follows:
Pension Plans Other Benefits
------------- --------------
December 31, December 31,
------------ ------------
2000 1999 2000 1999
---- ---- ---- ----
Weighted-average assumptions:
Discount rate 7.5% 8.0% 8.0% 8.0%
Expected return on plan assets 8.0% 8.0% N/A N/A
Rate of compensation increase 5.0% 5.0% 5.0% 5.0%
F-19
For measurement purposes, a 3.5% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2001.
Pension Plans Other Benefits
------------- --------------
For the Years Ended For the Years Ended
December 31, December 31,
------------ ------------
2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
(In thousands) (In thousands)
Components of net periodic benefit cost:
Service cost $ 257 $ 178 $ 201 $ 11 $ 25 $ 24
Interest cost 193 172 151 6 11 11
Expected return on plan assets (119) (88) (179) - - -
Amortization of prior service cost 29 83 174 - - -
Recognized net actuarial loss - - - (4) 2 2
------ ------ ------ ------- ------- -------
Net periodic benefit cost $ 360 $ 345 $ 347 $ 13 $ 38 $ 37
====== ====== ====== ======= ======= =======
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.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the Health Care Plan. A 1% change in assumed health care
cost trend rates would have the following effects (in thousands):
1% Increase 1% Decrease
----------- -----------
Effect on total of service and interest cost components
of net periodic postretirement health care benefit cost $ 3 $ 3
Effect on the health care component of the accumulated
postretirement benefit obligation $ 18 $ 15
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. Management believes that the current fair market value of the
remaining stock exceeds its carrying value.
F-20
10. 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,
--------------------------------
2000 1999 1998
---- ---- ----
(In thousands)
Development costs $ 48,996 $ 22,166 $ 32,191
Exploration 17,012 20,809 17,767
Acquisitions:
Proved 53,482 33,080 4,204
Unproved 5,694 15,129 3,693
--------- --------- ---------
Total $ 125,184 $ 91,184 $ 57,855
========= ========= =========
Oil and Gas Reserve Quantities (Unaudited):
The reserve information as of December 31, 2000, 1999, and 1998 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.
Presented below is a summary of the changes in estimated domestic
reserves of the Company:
For the Years Ended December 31,
--------------------------------
2000 1999 1998
---- ---- ----
Oil or Oil or Oil or
Condensate Gas Condensate Gas Condensate Gas
---------- --- ---------- --- ---------- ---
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
Total proved U.S. reserves:
Developed and undeveloped:
Beginning of year 18,900 207,642 8,614 132,605 11,493 196,230
Revisions of previous estimates 210 (1,172) 3,308 (10,445) (2,437) (42,430)
Discoveries and extensions 1,707 37,702 2,062 43,501 336 38,744
Purchases of minerals in place 3,149 21,689 6,323 65,129 679 1,225
Sales of reserves (618) (1,540) (24) (343) (182) (35,724)
Production (2,398) (38,346) (1,383) (22,805) (1,275) (25,440)
------- ------- ------- -------- ------- -------
End of year (a) 20,950 225,975 18,900 207,642 8,614 132,605
======= ======= ======= ======== ======= =======
Proved developed U.S. reserves:
Beginning of year 16,688 169,379 7,723 112,189 10,268 168,229
======= ======= ======= ======== ======= =======
End of year 19,006 192,472 16,688 169,379 7,723 112,189
======= ======= ======= ======== ======= =======
[FN]
------------------
(a) At December 31, 2000, 1999, and 1998, includes approximately
1,199, 1,802, and 2,022 MMcf, respectively, representing the
Company's underproduced gas balancing position.
F-21
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 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:
For the Years Ended December 31,
--------------------------------
2000 1999 1998
---- ---- ----
Gas (per Mcf) $ 8.857 $ 2.186 $ 1.767
Oil (per Bbl) $ 25.439 $ 23.847 $ 10.634
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,
--------------------------------
2000 1999 1998
---- ---- ----
(In thousands)
Future cash inflows $2,648,108 $ 900,199 $ 328,630
Future production and
development costs (570,711) (344,350) (128,120)
Future income taxes (727,929) (150,239) (39,471)
---------- --------- ---------
Future net cash flows 1,349,468 405,610 161,039
10% annual discount (630,984) (144,296) (59,093)
---------- --------- ---------
Standardized measure of
discounted future net cash flows $ 718,484 $ 261,314 $ 101,946
========== ========= =========
F-22
The principle sources of change in the standardized measure of
discounted future net cash flows are as follows:
For the Years Ended December 31,
--------------------------------
2000 1999 1998
---- ---- ----
(In thousands)
Standardized measure,
beginning of year $ 261,314 $ 101,946 $ 187,347
Sales of oil and gas produced,
net of production costs (183,586) (53,814) (53,643)
Net changes in prices and
production costs 772,910 82,976 (78,974)
Extensions, discoveries and other,
net of production costs 203,786 76,198 36,495
Purchase of minerals in place 104,883 105,728 5,548
Development costs incurred
during the year 12,436 5,816 12,964
Changes in estimated future
development costs 351 (25,281) 1,641
Revisions of previous quantity estimates 306 10,976 (39,303)
Accretion of discount 33,871 11,474 26,152
Sales of reserves in place (3,329) (542) (26,435)
Net change in income taxes (357,780) (76,907) 50,994
Other (126,678) 22,744 (20,840)
----------- ---------- ----------
Standardized measure, end of year $ 718,484 $ 261,314 $ 101,946
========== ========== ===========
F-23
11. Quarterly Financial Information (Unaudited):
The Company's quarterly financial information for fiscal 2000 and 1999
is as follows:
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
(in thousands, except per share data)
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 from continuing operations
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
Year Ended December 31, 1999:
Total revenue $ 14,313 $ 16,133 $ 20,124 $ 24,344
Less: costs and expenses 13,580 13,511 16,081 32,141
---------- ---------- ---------- ----------
Operating income (loss) $ 733 $ 2,622 $ 4,043 $ (7,797)
Income (loss) from continuing operations
before income taxes $ 588 $ 2,889 $ 3,847 $ (7,648)
Net income (loss) $ 409 $ 1,907 $ 2,493 $ (4,727)
Net income (loss) per common share:
Basic $ 0.02 $ 0.08 $ 0.11 $ (0.21)
Diluted $ 0.02 $ 0.08 $ 0.11 $ (0.21)
Dividends paid per share $ 0.025 $ 0.025 $ 0.025 $ 0.025
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 19, 2001 By: /s/ MARK A. HELLERSTEIN
---------------------------
Mark A. Hellerstein, 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
- ---------------------
Thomas E. Congdon Chairman of the Board of Directors March 19, 2001
/s/ MARK A. HELLERSTEIN
- ----------------------- President, Chief Executive Officer, March 19, 2001
Mark A. Hellerstein and Director
/s/ RONALD D. BOONE
- ------------------- Executive Vice President, Chief March 19, 2001
Ronald D. Boone Operating Officer and Director
/s/ RICHARD C. NORRIS
- --------------------- Vice President-Finance, March 19, 2001
Richard C. Norris Secretary and Treasurer
/s/ GARRY A. WILKENING
- ---------------------- Vice President-Administration March 19, 2001
Garry A. Wilkening and Controller
/s/ LARRY W. BICKLE
- -------------------
Larry W. Bickle Director March 19, 2001
Signature Title Date
- --------- ----- ----
/s/ DAVID C. DUDLEY
- -------------------
David C. Dudley Director March 19, 2001
/s/ ROBERT L. NANCE
- -------------------
Robert L. Nance Director March 19, 2001
/s/ R. JAMES NICHOLSON
- ----------------------
R. James Nicholson Director March 19, 2001
/s/ AREND J. SANDBULTE
- ----------------------
Arend J. Sandbulte Director March 19, 2001
/s/ JOHN M. SEIDL
- -----------------
John M. Seidl Director March 19, 2001
/s/ WILLIAM J. GARDINER
- -----------------------
William J. Gardiner Director March 19, 2001
/s/ JACK HUNT
- -------------
Jack Hunt Director March 19, 2001