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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, 1999
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
COMMISSION FILE NO. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE
OKLAHOMA CITY, OKLAHOMA 73118
(Address of principal executive offices) (Zip Code)
(405) 848-8000
Registrant's telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
---------------------------- -----------------------
Common Stock, par value $.01 New York Stock Exchange
7.875% Senior Notes due 2004 New York Stock Exchange
9.625% Senior Notes due 2005 New York Stock Exchange
9.125% Senior Notes due 2006 New York Stock Exchange
8.5% Senior Notes due 2012 New York Stock Exchange
7% Cumulative Convertible Preferred Stock, par value $.01 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of Common Stock held by non-affiliates on March
22, 2000 was $214,958,367. At such date, there were 103,955,497 shares of Common
Stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE REGISTRANT'S DEFINITIVE PROXY STATEMENT FOR THE 2000 ANNUAL
MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN PART III
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PART I
ITEM 1. BUSINESS
GENERAL
Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an
independent oil and gas company engaged in the development, exploration,
acquisition and production of onshore natural gas and oil reserves in the United
States and Canada. Chesapeake began operations in 1989 and completed its initial
public offering in 1993. Its common stock trades on the New York Stock Exchange
under the symbol CHK. The Company's principal offices are located at 6100 North
Western Avenue, Oklahoma City, Oklahoma 73118 (telephone 405/848-8000 and
website address of chkenergy.com).
Chesapeake owns interests in approximately 4,700 producing oil and gas wells
concentrated in three primary operating areas: the Mid-Continent region of
Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle; the
Gulf Coast region consisting primarily of the Austin Chalk Trend in Texas and
Louisiana and the Tuscaloosa Trend in Louisiana; and the Helmet area of
northeastern British Columbia. During 1999, the Company produced 133.5 Bcfe,
making Chesapeake one of the 15 largest public independent oil and gas producers
in the United States.
Business Strategy. From inception as a start-up in 1989 through today,
Chesapeake's business strategy has been to aggressively build and develop one of
the largest onshore natural gas resource bases in the U.S. The Company has
executed its strategy through a combination of active drilling and acquisition
programs during the past 10 years. Based on its view that natural gas will
become the fuel of choice in the 21st century to meet growing power demand and
increasing environmental concerns, Chesapeake believes its strategy will deliver
attractive returns and substantial growth opportunities in the years ahead.
1999 Highlights. In the challenging oil and gas environment of 1999, the
Company focused its efforts on drilling lower risk developmental wells,
acquiring reserves at the lowest possible cost, divesting of higher cost and
non-strategic properties and maintaining a capital expenditure budget closely
tied to operating cash flow and proceeds from asset sales. Despite experiencing
20-year lows in oil and gas pricing during the first half of 1999, Chesapeake
achieved considerable operating and financial progress during the year. Listed
below are a few of Chesapeake's accomplishments in 1999 compared to 1998's
results:
- net income of $33 million, compared to a net loss of $934 million
- cash flow from operations (before changes in working capital) of $139
million, an increase of 18%
- proved oil and gas reserves of 1,206 Bcfe, an increase of 11%
- oil and natural gas production of 133.5 Bcfe, an increase of 3%
- reserve replacement of 186% at a cost of $0.65 per Mcfe
In addition, Chesapeake's operating cost structure remained among the lowest
of all publicly traded independent energy producers during 1999. The Company's
per unit operating costs (consisting of general and administrative expenses,
production expenses, production taxes, and depreciation, depletion and
amortization of oil and gas properties) were $1.26 per Mcfe of production,
resulting in an operating margin of $0.84 per Mcfe. The Company's low costs are
attributable to its focus on developing highly productive natural gas
properties, its efficient and motivated employees, and the successful
integration of advanced drilling and completion expertise with its large
inventory of undeveloped leasehold.
During 1999 and early 2000, Chesapeake was successful in defeating two
material pieces of litigation against the Company. First, in the 1996 Union
Pacific Resources Corporation patent infringement litigation involving
horizontal drilling, the U.S. District Court in Ft. Worth dismissed the lawsuit,
ruling in September 1999 that a patent previously granted to UPRC was invalid
and therefore Chesapeake could not have infringed upon it. Second, in March
2000, the U.S. District Court in Oklahoma City dismissed a class action
securities suit which had been pending against the Company since 1997.
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2000 Outlook. Chesapeake's strategy remains unchanged for 2000: maintain a
superior operating cost structure, fund a capital expenditure budget in balance
with operating cash flow, and deliver attractive financial returns from its
assets during a time of strengthening natural gas fundamentals.
DRILLING ACTIVITY
The following table sets forth the wells drilled by the Company during the
periods indicated. In the table, "gross" refers to the total wells in which the
Company has a working interest and "net" refers to gross wells multiplied by the
Company's working interest therein.
SIX MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, JUNE 30,
------------------------------
1999 1998 1997 1997
------------- ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---
United States
Development:
Productive........... 167 93.3 158 93.9 55 24.4 90 55.0
Non-productive....... 17 10.6 9 4.7 1 0.3 2 0.2
--- ----- ---- ---- ---- ---- ---- ----
Total................ 184 103.9 167 98.6 56 24.7 92 55.2
=== ===== ==== ==== ==== ==== ==== ====
Exploratory:
Productive........... 9 3.7 46 23.4 28 15.5 71 46.1
Non-productive....... 6 4.6 9 6.8 2 0.9 8 5.7
--- ----- ---- ---- ---- ---- ---- ----
Total................ 15 8.3 55 30.2 30 16.4 79 51.8
=== ===== ==== ==== ==== ==== ==== ====
Canada
Development:
Productive........... 11 7.3 11 3.6
Non-productive....... 1 0.2 1 0.4
--- ----- ---- ----
Total................ 12 7.5 12 4.0
=== ===== ==== ====
Exploratory:
Productive........... -- -- 1 0.3
Non-productive....... -- -- 7 2.1
--- ----- ---- ----
Total................ -- -- 8 2.4
=== ===== ==== ====
WELL DATA
At December 31, 1999, the Company had interests in 4,719 (2,235.1 net)
producing wells, of which 238 (104.6 net) were classified as primarily oil
producing wells and 4,481 (2,130.5 net) were classified as primarily gas
producing wells.
VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with the Company's sale of oil and gas for the periods indicated:
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YEARS ENDED SIX MONTHS ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, JUNE 30,
---------------------------
1999 1998 1997 1997
------------ ------------ ------------ ------------
NET PRODUCTION:
Oil (MBbl) ..................................... 4,147 5,976 1,857 2,770
Gas (MMcf) ..................................... 108,610 94,421 27,326 62,005
Gas equivalent (MMcfe) ......................... 133,492 130,277 38,468 78,625
OIL AND GAS SALES ($ IN 000'S):
Oil ............................................ $ 66,413 $ 75,877 $ 34,523 $ 57,974
Gas ............................................ 214,032 181,010 61,134 134,946
------------ ------------ ------------ ------------
Total oil and gas sales ................ $ 280,445 $ 256,887 $ 95,657 $ 192,920
============ ============ ============ ============
AVERAGE SALES PRICE:
Oil ($ per Bbl) ................................ $ 16.01 $ 12.70 $ 18.59 $ 20.93
Gas ($ per Mcf) ................................ $ 1.97 $ 1.92 $ 2.24 $ 2.18
Gas equivalent ($ per Mcfe) .................... $ 2.10 $ 1.97 $ 2.49 $ 2.45
OIL AND GAS COSTS ($ PER MCFE):
Production expenses ............................ $ .35 $ .39 $ .20 $ .14
Production taxes ............................... $ .10 $ .06 $ .07 $ .05
General and administrative ..................... $ .10 $ .15 $ .15 $ .11
Depreciation, depletion and amortization ....... $ .71 $ 1.13 $ 1.57 $ 1.31
Included in the above table are the results of Canadian operations during
1999 and 1998. The average sales price for the Company's Canadian gas production
was $1.19 and $1.03 during 1999 and 1998, respectively, and the Canadian
production expenses were $0.18 and $0.24 per Mcfe, respectively.
PROVED RESERVES
The following table sets forth the Company's estimated proved reserves and
the present value (discounted at 10%) of the proved reserves (based on weighted
average prices at December 31, 1999 of $24.72 per barrel of oil and $2.25 per
Mcf of gas):
PERCENT PRESENT
GAS OF VALUE
OIL GAS EQUIVALENT PROVED (DISC. @ 10%)
(MBBL) (MMCF) (MMCFE) RESERVES ($ IN 000'S)
------ ---------- --------- -------- ------------
Mid-Continent............... 12,230 684,178 757,559 63% $ 663,993
Gulf Coast.................. 4,169 164,693 189,708 15 211,348
Canada...................... -- 178,242 178,242 15 97,749
Other areas................. 8,396 29,713 80,086 7 116,406
------ ---------- --------- ---- ----------
Total................... 24,795 1,056,826 1,205,595 100% $1,089,496
====== ========== ========= ==== ==========
During 1999, Chesapeake increased its proved developed reserve percentage to
80% by present value and 72% by volume, and natural gas reserves accounted for
88% of proved reserves at December 31, 1999.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated:
YEARS ENDED SIX MONTHS
DECEMBER 31, ENDED YEAR ENDED
------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
--------- --------- --------- ----------
($ IN THOUSANDS)
Development and leasehold costs........... $ 126,865 $ 176,610 $ 144,283 $ 324,989
Exploration costs......................... 23,693 68,672 40,534 136,473
Acquisition costs......................... 52,093 740,280 39,245 --
Sales of oil and gas properties........... (45,635) (15,712) -- --
Capitalized internal costs................ 2,710 5,262 2,435 3,905
--------- --------- --------- ---------
Total........................... $ 159,726 $ 975,112 $ 226,497 $ 465,367
========= ========= ========= =========
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ACREAGE
The following table sets forth as of December 31, 1999 the gross and net
acres of both developed and undeveloped oil and gas leases which the Company
holds. "Gross" acres are the total number of acres in which the Company owns a
working interest. "Net" acres refer to gross acres multiplied by the Company's
fractional working interest. Acreage numbers are stated in thousands and do not
include options for additional leasehold held by the Company, but not yet
exercised.
TOTAL DEVELOPED
DEVELOPED UNDEVELOPED AND UNDEVELOPED
--------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Mid-Continent ..................... 1,439 563 848 306 2,287 869
Gulf Coast ........................ 230 156 766 666 996 822
Canada ............................ 100 50 641 305 741 355
Other areas ....................... 40 21 639 421 679 442
----- ----- ----- ----- ----- -----
Total ................... 1,809 790 2,894 1,698 4,703 2,488
===== ===== ===== ===== ===== =====
MARKETING
The Company's oil production is sold under market sensitive or spot price
contracts. The Company's natural gas production is sold to purchasers under
varying percentage-of-proceeds and percentage-of-index contracts or by direct
marketing to end users or aggregators. By the terms of the
percentage-of-proceeds contracts, the Company receives a percentage of the
resale price received by the purchaser for sales of residue gas and natural gas
liquids recovered after gathering and processing the Company's gas. The residue
gas and natural gas liquids sold by these purchasers are sold primarily based on
spot market prices. The revenue received by the Company from the sale of natural
gas liquids is included in natural gas sales. During 1999, only sales to Aquila
Southwest Pipeline Corporation of $31.5 million accounted for more than 10% of
the Company's total oil and gas sales. Management believes that the loss of this
customer would not have a material adverse effect on the Company's results of
operations or its financial position.
Chesapeake Energy Marketing, Inc. ("CEMI"), a wholly-owned subsidiary,
provides oil and natural gas marketing services, including commodity price
structuring, contract administration and nomination services for the Company,
its partners and other oil and natural gas producers in certain geographical
areas in which the Company is active.
HEDGING ACTIVITIES
Periodically the Company utilizes hedging strategies to hedge the price of a
portion of its future oil and gas production and to manage fixed interest rate
exposure. See Item 7A - Quantitative and Qualitative Disclosures About Market
Risk.
RISK FACTORS
Substantial Debt Levels Could Affect Operations.
As of December 31, 1999, we had long-term indebtedness of $964.1 million
(which included bank indebtedness of $43.5 million) and stockholders' equity was
a deficit of $217.5 million. Our ability to meet our debt service requirements
throughout the life of the senior notes and our ability to meet our preferred
stock obligations will depend on our future performance, which will be subject
to oil and gas prices, our production levels of oil and gas, general economic
conditions, and various financial, business and other factors affecting our
operations. Our level of indebtedness may have the following effects on future
operations:
o a substantial portion of our cash flow from operations may be
dedicated to the payment of interest on indebtedness and will not be
available for other purposes,
o restrictions in our debt instruments limit our ability to borrow
additional funds or to dispose of assets and may affect our
flexibility in planning for, and reacting to, changes in the energy
industry, and
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o our ability to obtain additional capital in the future may be
impaired.
As a result of our high level of indebtedness and poor conditions in the energy
industry, Standard & Poor's Corporation and Moody's Investors Service reduced
the credit ratings on our senior notes to "B" and "B3", respectively, in late
1998. These ratings were removed from credit review in 1999. Our credit ratings
could negatively impact our ability to access capital markets.
The Volatility of Oil and Gas Prices Creates Uncertainties.
Our revenues, operating results and future rate of growth are highly
dependent on the prices we receive for our oil and gas. Historically, the
markets for oil and gas have been volatile and may continue to be volatile in
the future. Various factors which are beyond our control will affect prices of
oil and gas. These factors include:
o worldwide and domestic supplies of oil and gas,
o weather conditions,
o the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls,
o political instability or armed conflict in oil-producing regions,
o the price and level of foreign imports,
o the level of consumer demand,
o the price and availability of alternative fuels,
o the availability of pipeline capacity, and
o domestic and foreign governmental regulations and taxes.
We are unable to predict the long-term effects of these and other conditions on
the prices of oil and gas. Lower oil and gas prices may reduce the amount of oil
and gas we produce, which may adversely affect our revenues and operating
income. Because in 2000 we plan to match as nearly as possible our capital
expenditures for drilling and acquisition activities to cash flow from
operations, significant reductions in oil and gas prices may require us to
reduce our capital expenditures. Reducing drilling will make it more difficult
for us to replace the reserves we produce.
We Must Replace Reserves to Sustain Production.
As is customary in the oil and gas exploration and production industry, our
future success depends largely upon our ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless we
replace the reserves we produce through successful development, exploration or
acquisition, our proved reserves will decline over time. In addition,
approximately 28% by volume, or 20% by value, of our total estimated proved
reserves at December 31, 1999 were undeveloped. By their nature, undeveloped
reserves are less certain. Recovery of such reserves will require significant
capital expenditures and successful drilling operations. We cannot assure you
that we can successfully find and produce reserves economically in the future.
Significant Capital Expenditures Will be Required to Exploit Reserves.
We have made and intend to make substantial capital expenditures in
connection with the exploration, development and production of our oil and gas
properties. Historically, we have funded our capital expenditures through a
combination of internally generated funds, equity issuances and long-term debt
financing arrangements and sale of non-core assets. From time to time, we have
used short-term bank debt, generally as a working capital facility. Future cash
flows are subject to a number of variables, such as the level of production from
existing wells, prices of oil and gas, and our success in developing and
producing new reserves and in selling non-core assets. If revenue were to
decrease as a result of lower oil and gas prices or decreased production, and
our access to capital were limited, we would have a reduced ability to replace
our reserves. If our cash flow from operations is not sufficient to fund our
capital expenditure budget, there can be no assurance that additional debt or
equity financing will be available to meet these requirements.
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We May Have Full-Cost Ceiling Writedowns if Oil and Gas Prices Decline or if
Drilling Results are Unfavorable.
We reported full-cost ceiling writedowns of $826 million, $110 million, and
$236 million during the year ended December 31, 1998, the six-month transition
period ended December 31, 1997 (the "Transition Period"), and the year ended
June 30, 1997 ("fiscal 1997"), respectively. These writedowns were caused by
significant declines in oil and gas prices during all three periods and by poor
drilling results in fiscal 1997 and during the Transition Period. Additionally,
significant declines in prices can cause proved undeveloped reserves to become
uneconomic, and long-lived production to become "economically truncated",
further reducing proved reserves and increasing any writedown. Our reserve
values were calculated using weighted average prices at December 31, 1999 of
$24.72 per barrel of oil and $2.25 per Mcf of natural gas. If prices in future
periods are below the prices of $10.48 per barrel of oil and $1.68 per mcf of
natural gas used at December 31, 1998, the last period during which Chesapeake
recorded an impairment to its oil and gas properties, future impairment charges
could be incurred. Although we have taken steps to reduce drilling risk, reduce
operating costs, and reduce investment in unproved leasehold, these steps may
not be sufficient to enhance future economic results or prevent additional
leasehold impairment and full-cost ceiling writedowns, which are highly
dependent on future oil and gas prices.
Drilling and Oil and Gas Operations Present Unique Risks.
Drilling activities are subject to many risks, including well blowouts,
cratering, uncontrollable flows of oil, natural gas or well fluids, fires,
formations with abnormal pressures, pollution, releases of toxic gases and other
environmental hazards and risk, any of which could result in substantial losses.
In addition, we incur the risk that we will not encounter any commercially
productive reservoirs through our drilling operations. We cannot assure you that
the new wells we drill will be productive or that we will recover all or any
portion of our investment in wells drilled. Drilling for oil and gas may involve
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce enough reserves to return a profit after drilling,
operating and other costs.
Existing Debt Covenants Restrict Our Operations.
The indentures which govern our senior notes contain covenants which
restrict our ability, and the ability of our subsidiaries other than CEMI, to
engage in the following activities:
o incurring additional debt,
o creating liens,
o paying dividends and making other restricted payments,
o merging or consolidating with any other entity,
o selling, assigning, transferring, leasing or otherwise disposing of
all or substantially all of our assets, and
o guaranteeing indebtedness.
At December 31, 1999, we did not meet a debt incurrence test contained in
two of the senior note indentures. Thus, we will be unable to incur unsecured
non-bank debt or resume the payment of dividends on our preferred stock until we
meet the debt incurrence test.
Canadian Operations Present the Risks Associated with Conducting Business
Outside the U.S.
A portion of our business is conducted in Canada. You may review the amounts
of revenue, operating income (loss) and identifiable assets attributable to our
Canadian operations in Note 8 of the Notes to Consolidated Financial Statements
in Item 8. Also, Note 11 of the Consolidated Financial Statements provides
disclosures about our Canadian oil and gas producing activities. Our operations
in Canada are subject to the risks associated with operating outside of the
United States. These risks include the following:
o adverse local political or economic developments,
o exchange controls,
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o currency fluctuations,
o royalty and tax increases,
o retroactive tax claims,
o negotiations of contracts with governmental entities, and
o import and export regulations.
In addition, in the event of a dispute, we may be required to litigate the
dispute in Canadian courts since we may not be able to sue foreign persons in a
United States court.
The Loss of Either the CEO or the COO Could Adversely Affect Operations.
Our operations are dependent upon our Chief Executive Officer, Aubrey K.
McClendon, and our Chief Operating Officer, Tom L. Ward. The unexpected loss of
the services of either of these executive officers could have a detrimental
effect on our operations. We maintain $20 million key man life insurance
policies on the life of each of Messrs. McClendon and Ward.
Transactions with Executive Officers May Create Conflicts of Interest.
Messrs. McClendon and Ward have the right to participate in certain wells we
drill, subject to certain limitations outlined in their employment contracts. As
a result of their participation, they routinely have significant accounts
payable to Chesapeake for joint interest billings and other related advances. As
of December 31, 1999, Messrs. McClendon and Ward had payables to Chesapeake of
$2.5 million and $1.8 million, respectively, in connection with such
participation. These amounts were reduced to $2.2 million and $1.2 million,
respectively, as of March 22, 2000. The rights to participate in wells we drill
could present a conflict of interest with respect to Messrs. McClendon and Ward.
The Ownership of a Significant Percentage of Stock by Insiders Could Influence
the Outcome of Shareholder Votes.
At March 22, 2000, our Board of Directors and senior management beneficially
owned an aggregate of 25,788,818 shares of common stock (including outstanding
vested options), which represented approximately 24% of our outstanding shares.
The beneficial ownership of Messrs. McClendon and Ward accounted for 21% of the
outstanding common stock. As a result, Messrs. McClendon and Ward, together with
other officers and directors of Chesapeake, are in a position to significantly
influence matters requiring the vote or consent of our shareholders.
REGULATION
General
Numerous departments and agencies, federal, state and local, issue rules and
regulations binding on the oil and gas industry, some of which carry substantial
penalties for failure to comply. The regulatory burden on the oil and gas
industry increases the Company's cost of doing business and, consequently,
affects its profitability.
Exploration and Production
The Company's operations are subject to various types of regulation at the
federal, state and local levels. Such regulation includes requiring permits for
the drilling of wells, maintaining bonding requirements in order to drill or
operate wells and regulating the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used or
obtained in connection with operations. The Company's operations are also
subject to various conservation regulations. These include the regulation of the
size of drilling and spacing units and the density of wells which may be drilled
and the unitization or pooling of oil and gas properties. In this regard, some
states (such as Oklahoma) allow the forced pooling or integration of tracts to
facilitate exploration while other states (such as Texas) rely on voluntary
pooling of lands and leases. In areas where pooling is voluntary, it may be more
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difficult to form units and, therefore, more difficult to develop a prospect if
the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amount of oil and gas the Company can produce from its wells and to
limit the number of wells or the locations at which the Company can drill. The
extent of any impact on the Company of such restrictions cannot be predicted.
Environmental and Occupational Regulation
General. The Company's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, rules and
regulations concerning the protection of the environment and human health will
not have a material effect upon the operations, capital expenditures, earnings
or the competitive position of the Company. The Company cannot predict what
effect additional regulation or legislation, enforcement policies thereunder and
claims for damages for injuries to property, employees, other persons and the
environment resulting from the Company's operations could have on its
activities.
Activities of the Company with respect to the exploration, development and
production of oil and natural gas are subject to stringent environmental
regulation by state and federal authorities including the United States
Environmental Protection Agency ("EPA"). Such regulation has increased the cost
of planning, designing, drilling, operating and in some instances, abandoning
wells. In most instances, the regulatory requirements relate to the handling and
disposal of drilling and production waste products and waste created by water
and air pollution control procedures. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on operations or earnings, risks of substantial costs and liabilities are
inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including criminal penalties, will not be
incurred. Moreover, it is possible that other developments, such as stricter
environmental laws and regulations, and claims for damages for injuries to
property or persons resulting from the Company's operations could result in
substantial costs and liabilities.
Waste Disposal. The Company currently owns or leases, and has in the past
owned or leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under the Company's control.
State and federal laws applicable to oil and natural gas wastes and properties
have gradually become more strict. Under such laws, the Company could be
required to remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators) or property contamination
(including groundwater contamination) or to perform remedial plugging operations
to prevent future contamination.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the disposal
options for certain hazardous and nonhazardous wastes and are considering the
adoption of stricter disposal standards for nonhazardous wastes. Furthermore,
certain wastes generated by the Company's oil and natural gas operations that
are currently exempt from treatment as hazardous wastes may in the future be
designated as hazardous wastes, and therefore be subject to considerably more
rigorous and costly operating and disposal requirements.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons with respect to the release of a "hazardous substance" into
the environment. These persons include the owner and operator of a site and
persons that disposed of or arranged for the disposal of the
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hazardous substances found at a site. CERCLA also authorizes the EPA and, in
some cases, third parties to take actions in response to threats to the public
health or the environment and to seek to recover from responsible classes of
persons the costs of such action. In the course of its operations, the Company
may have generated and may generate wastes that fall within CERCLA's definition
of "hazardous substances". The Company may also be or have been an owner of
sites on which "hazardous substances" have been released. The Company may be
responsible under CERCLA for all or part of the costs to clean up sites at which
such wastes have been released. To date, however, neither the Company nor, to
its knowledge, its predecessors or successors have been named a potentially
responsible party under CERCLA or similar state superfund laws affecting
property owned or leased by the Company.
Air Emissions. The operations of the Company are subject to local, state and
federal regulations for the control of emissions of air pollution. Legal and
regulatory requirements in this area are increasing, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future as a result of new regulatory developments. In particular, regulations
promulgated under the Clean Air Act Amendments of 1990 may impose additional
compliance requirements that could affect the Company's operations. However, it
is impossible to predict accurately the effect, if any, of the Clean Air Act
Amendments on the Company at this time. The Company may in the future be subject
to civil or administrative enforcement actions for failure to comply strictly
with air regulations or permits. These enforcement actions are generally
resolved by payment of monetary fines and correction of any identified
deficiencies. Alternatively, regulatory agencies could require the Company to
forego construction or operation of certain air emission sources.
OSHA. The Company is subject to the requirements of the federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the federal Superfund Amendment and Reauthorization Act and similar state
statutes require the Company to organize information about hazardous materials
used, released or produced in its operations. Certain of this information must
be provided to employees, state and local governmental authorities and local
citizens. The Company is also subject to the requirements and reporting set
forth in OSHA workplace standards. The Company provides safety training and
personal protective equipment to its employees.
OPA and Clean Water Act. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as the Company,
to prepare and implement spill prevention control plans, countermeasure plans
and facilities response plans relating to the possible discharge of oil into
surface waters. The Oil Pollution Act of 1990 ("OPA") amends certain provisions
of the federal Water Pollution Control Act of 1972, commonly referred to as the
Clean Water Act ("CWA"), and other statutes as they pertain to the prevention of
and response to oil spills into navigable waters. The OPA subjects owners of
facilities to strict joint and several liability for all containment and cleanup
costs and certain other damages arising from a spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. The CWA
provides penalties for any discharges of petroleum product in reportable
quantities and imposes substantial liability for the costs of removing a spill.
State laws for the control of water pollution also provide varying civil and
criminal penalties and liabilities in the case of releases of petroleum or its
derivatives into surface waters or into the ground. Regulations are currently
being developed under OPA and state laws concerning oil pollution prevention and
other matters that may impose additional regulatory burdens on the Company. In
addition, the CWA and analogous state laws require permits to be obtained to
authorize discharges into surface waters or to construct facilities in wetland
areas. With respect to certain of its operations, the Company is required to
maintain such permits or meet general permit requirements. The EPA has adopted
regulations concerning discharges of storm water runoff. This program requires
covered facilities to obtain individual permits, participate in a group permit
or seek coverage under an EPA general permit. The Company believes that with
respect to existing properties it has obtained, or is included under, such
permits and with respect to future operations it will be able to obtain, or be
included under, such permits, where necessary. Compliance with such permits is
not expected to have a material effect on the Company.
NORM. Oil and gas exploration and production activities have been identified
as generators of concentrations of low-level naturally-occurring radioactive
materials ("NORM"). NORM regulations have recently been adopted in several
states. The Company is unable to estimate the effect of these regulations,
although based upon the
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Company's preliminary analysis to date, the Company does not believe that its
compliance with such regulations will have a material adverse effect on its
operations or financial condition.
Safe Drinking Water Act. The Company's operations involve the disposal of
produced saltwater and other nonhazardous oilfield wastes by reinjection into
the subsurface. Under the Safe Drinking Water Act ("SDWA"), oil and gas
operators, such as the Company, must obtain a permit for the construction and
operation of underground Class II injection wells. To protect against
contamination of drinking water, periodic mechanical integrity tests are often
required to be performed by the well operator. The Company has obtained such
permits for the Class II wells it operates. The Company also has disposed of
wastes in facilities other than those owned by the Company which are commercial
Class II injection wells.
Toxic Substances Control Act. The Toxic Substances Control Act ("TSCA") was
enacted to control the adverse effects of newly manufactured and existing
chemical substances. Under the TSCA, the EPA has issued specific rules and
regulations governing the use, labeling, maintenance, removal from service and
disposal of PCB items, such as transformers and capacitors used by oil and gas
companies. The Company may own such PCB items but does not believe compliance
with TSCA has or will have a material adverse effect on the Company's operations
or financial condition.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, only cursory investigation of record title is made at
the time of acquisition. Drilling title opinions are usually prepared before
commencement of drilling operations. From time to time, the Company's title to
oil and gas properties is challenged through legal proceedings. The Company is
routinely involved in litigation involving title to certain of its oil and gas
properties, some of which management believes could be adverse to the Company,
individually or in the aggregate. See Item 3 - Legal Proceedings.
OPERATING HAZARDS AND INSURANCE
The oil and gas business involves a variety of operating risks, including
the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured
formations and environmental hazards such as oil spills, gas leaks, ruptures or
discharges of toxic gases, the occurrence of any of which could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. The Company's horizontal and deep
drilling activities involve greater risk of mechanical problems than vertical
and shallow drilling operations.
The Company maintains a $50 million oil and gas lease operator policy that
insures the Company against certain sudden and accidental risks associated with
drilling, completing and operating its wells. There can be no assurance that
this insurance will be adequate to cover any losses or exposure to liability.
The Company also carries comprehensive general liability policies and a $75
million umbrella policy. The Company and its subsidiaries carry workers'
compensation insurance in all states in which they operate and a $75 million
employment practice liability policy. While the Company believes these policies
are customary in the industry, they do not provide complete coverage against all
operating risks.
EMPLOYEES
The Company had 424 full-time employees as of December 31, 1999. No
employees are represented by organized labor unions. The Company considers its
employee relations to be good.
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FACILITIES
The Company owns an office building complex in Oklahoma City totaling
approximately 86,500 square feet and nine acres of land that comprise its
headquarters' offices. The Company also owns field offices in Lindsay and
Waynoka, Oklahoma and Garden City, Kansas. The Company leases office space in
Oklahoma City and Weatherford, Oklahoma; Fritch and Navasota, Texas; and in
Dickinson, North Dakota. The Company also has leased office space in College
Station, Texas; Wichita, Kansas; and Calgary, Alberta, Canada, which have been
sub-leased.
GLOSSARY
The terms defined in this section are used throughout this Form 10-K.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of gas equivalent.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Commercial Well; Commercially Productive Well. An oil and gas well which
produces oil and gas in sufficient quantities such that proceeds from the sale
of such production exceed production expenses and taxes.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
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.
Dry Hole; Dry Well. A well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well.
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.
Farmout. An assignment of an interest in a drilling location and related
acreage conditional upon the drilling of a well on that location.
Formation. A succession of sedimentary beds that were deposited under the
same general geologic conditions.
Full-Cost Pool. The full-cost pool consists of all costs associated with
property acquisition, exploration, and development activities for a company
using the full-cost method of accounting. Additionally, any internal costs that
can be directly identified with acquisition, exploration and development
activities are included. Any costs related to production, general corporate
overhead or similar activities are not included.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Horizontal Wells. Wells which are drilled at angles greater than 70 from
vertical.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBtu. One thousand Btus.
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Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of gas equivalent.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interest owned in
gross acres or gross wells.
Present Value. When used with respect to oil and gas reserves, present value
means the estimated future gross revenue to be generated from the production of
proved reserves, net of estimated production and future development costs, using
prices and costs in effect at the determination date, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and future income tax expense 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 Reserves. 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 Undeveloped Location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from
new wells drilled to known reservoir on undrilled acreage or from existing wells
where a relatively major expenditure is required for recompletion.
Royalty Interest. An interest in an oil and gas property entitling the owner
to a share of oil or gas production free of costs of production.
Tcf. One trillion cubic feet.
Tcfe. One trillion cubic feet of gas equivalent.
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 proved reserves.
Working Interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
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ITEM 2. PROPERTIES
The Company focuses its natural gas exploration, development and acquisition
efforts in three areas: (i) the Mid-Continent (consisting of Oklahoma, western
Arkansas, southwestern Kansas and the Texas Panhandle), (ii) the onshore Gulf
Coast in Texas and Louisiana, and (iii) the Helmet area in northeastern British
Columbia. In addition, Chesapeake has active oil exploration and development
programs in southeast New Mexico; and in portions of North Dakota; Montana; and
Saskatchewan, Canada which comprise the Williston Basin.
During the year ended December 31, 1999 ("1999"), the Company participated
in 211 gross (119.7 net) wells, 135 of which were Company operated. A summary of
the Company's drilling activities, capital expenditures and property sales by
primary operating area is as follows ($ in thousands):
CAPITAL EXPENDITURES - OIL AND GAS PROPERTIES
GROSS NET ------------------------------------------------------------------------
WELLS WELLS SALE OF
DRILLED DRILLED DRILLING LEASEHOLD SUB-TOTAL ACQUISITIONS PROPERTIES TOTAL
------- -------- -------- --------- --------- ------------ ---------- --------
Mid-Continent ......... 169 95.3 $ 55,670 $ 12,478 $ 68,148 $ 47,364 $ (36,702) $ 78,810
Gulf Coast ............ 10 3.7 22,049 8,288 30,337 629 (2,628) 28,338
Canada ................ 12 7.5 27,380 1,982 29,362 4,100 (813) 32,649
All other areas........ 20 13.2 24,106 1,315 25,421 -- (5,492) 19,929
------- -------- -------- --------- --------- ------------ ---------- --------
Total ............. 211 119.7 $129,205 $ 24,063 $ 153,268 $ 52,093 $ (45,635) $159,726
======= ======== ======== ========= ========= ============ ========== ========
The Company's proved reserves increased 11% to an estimated 1,206 Bcfe at
December 31, 1999, compared to 1,091 Bcfe of estimated proved reserves at
December 31, 1998 (see Note 11 of Notes to Consolidated Financial Statements in
Item 8).
The Company's strategy for 2000 is to continue developing its natural gas
assets by drilling, selective acquisitions and miscellaneous property
divestitures. Accordingly, the Company has established a capital expenditure
budget of $170-$190 million, including approximately $130-$140 million allocated
to drilling, acreage acquisition, seismic and related capitalized internal
costs, and $40-$50 million for acquisitions, debt repayment and general
corporate purposes. This budget is subject to adjustment based on drilling
results, oil and gas prices, and other factors.
PRIMARY OPERATING AREAS
Mid-Continent Region. The Company's Mid-Continent proved reserves of 758
Bcfe represented 63% of the Company's total proved reserves as of December 31,
1999 and this area produced 70 Bcfe, or 52% of the Company's 1999 production.
During 1999, the Company invested approximately $56 million to drill 169
gross (95.3 net) wells in the Mid-Continent. The Company anticipates spending
approximately 55%-60% of its total budget for exploration and development
activities in the Mid-Continent region during 2000. The Company anticipates the
Mid-Continent will contribute approximately 79 Bcfe of production during 2000,
or 56% of expected total production.
Gulf Coast. The Company's Gulf Coast proved reserves, consisting of the
Austin Chalk Trend in Texas and Louisiana, the Wharton County area in Texas, and
the Tuscaloosa Trend in Louisiana, represented 190 Bcfe, or 15% of the Company's
total proved reserves as of December 31, 1999. During 1999, the Gulf Coast
assets produced 45 Bcfe, or 34% of the Company's total production. The Company
anticipates the Gulf Coast will contribute approximately 39 Bcfe of production
during 2000, or 28% of expected total production.
During 1999, the Company invested approximately $22 million to drill 10
gross (3.7 net) wells in the Gulf Coast. For 2000, the Company anticipates
spending approximately 15%-20% of its total budget for exploration and
development activities in the Gulf Coast region.
Helmet Area. The Company's Canadian proved reserves of 178 Bcfe represented
15% of the Company's total proved reserves at December 31, 1999. During 1999,
production from Canada was 12 Bcfe, or 9% of the
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Company's total production. During 1999, the Company invested approximately $27
million to drill 12 gross (7.5 net) wells, install various pipelines and
compressors, and to perform capital workovers in Canada. The Company anticipates
spending approximately 10% of its total budget for exploration and development
activities in Canada during 2000, and expects production of 12 Bcfe in Canada,
or 9% of the Company's estimated total production for 2000.
OTHER OPERATING AREAS
In addition to the primary operating areas described above which are focused
on natural gas properties, the Company maintains operations in the Permian Basin
in New Mexico, and the Williston Basin in North Dakota; Montana; and
Saskatchewan, Canada which are focused on developing oil properties. In 1999,
these areas contributed 7 Bcfe, or 5% of the Company's total production. In
2000, production levels should increase to approximately 11 Bcfe as a result of
the Company allocating approximately 10% of its total budget for exploration and
development activities in these areas.
OIL AND GAS RESERVES
The tables below set forth information as of December 31, 1999 with respect
to the Company's estimated proved reserves, the estimated future net revenue
therefrom and the present value thereof at such date. Williamson Petroleum
Consultants, Inc. evaluated 50% and Ryder Scott Company evaluated 16% of the
Company's combined discounted future net revenues from the Company's estimated
proved reserves at December 31, 1999. The remaining properties were evaluated
internally by the Company's engineers. All estimates were prepared based upon a
review of production histories and other geologic, economic, ownership and
engineering data developed by the Company. The present value of estimated future
net revenue shown is not intended to represent the current market value of the
estimated oil and gas reserves owned by the Company.
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF DECEMBER 31, 1999 (MBBL) (MMCF) (MMCFE)
----------------------- ------- --------- ---------
Proved developed........................................................... 17,750 763,323 869,823
Proved undeveloped......................................................... 7,045 293,503 335,772
------- --------- ---------
Total proved............................................................... 24,795 1,056,826 1,205,595
======= ========= =========
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF DECEMBER 31, 1999(a) DEVELOPED UNDEVELOPED PROVED
-------------------------- --------- ----------- ----------
($ IN THOUSANDS)
Estimated future net revenue............................................... $1,470,297 $ 420,878 $1,891,175
Present value of future net revenue........................................ $ 867,985 $ 221,511 $1,089,496
- ----------
(a) Estimated future net revenue represents estimated future gross revenue
to be generated from the production of proved reserves, net of
estimated production and future development costs, using prices and
costs in effect at December 31, 1999. The amounts shown do not give
effect to non-property related expenses, such as general and
administrative expenses, debt service and future income tax expense or
to depreciation, depletion and amortization. The prices used in the
external and internal reports yield weighted average prices of $24.72
per barrel of oil and $2.25 per Mcf of gas.
The future net revenue attributable to the Company's estimated proved
undeveloped reserves of $420.9 million at December 31, 1999, and the $221.5
million present value thereof, have been calculated assuming that the Company
will expend approximately $212.5 million to develop these reserves. The amount
and timing of these expenditures will depend on a number of factors, including
actual drilling results, product prices and the availability of capital.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Securities and
Exchange Commission.
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The Company's ownership interest used in calculating proved reserves and the
estimated future net revenue therefrom was determined after giving effect to the
assumed maximum participation by other parties to the Company's farmout and
participation agreements. The prices used in calculating the estimated future
net revenue attributable to proved reserves do not reflect market prices for oil
and gas production sold subsequent to December 31, 1999. There can be no
assurance that all of the estimated proved reserves will be produced and sold at
the assumed prices or that existing contracts will be honored or judicially
enforced.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and the accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary. In addition, results of drilling, testing and production subsequent
to the date of an estimate may justify revision of such estimates, and such
revisions may be material. Accordingly, reserve estimates are often different
from the actual quantities of oil and gas that are ultimately recovered.
Furthermore, the estimated future net revenue from proved reserves and the
present value thereof are based upon certain assumptions, including prices,
future production levels and cost, that may not prove correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
foregoing uncertainties are particularly true as to proved undeveloped reserves,
which are inherently less certain than proved developed reserves and which
comprise a significant portion of the Company's proved reserves.
See Item 1 and Note 11 of Notes to Consolidated Financial Statements
included in Item 8 for a description of the Company's primary and other
operating areas, production and other information regarding its oil and gas
properties.
ITEM 3. LEGAL PROCEEDINGS
The Company is subject to ordinary routine litigation incidental to its
business. In addition, the following matters are pending or were recently
terminated:
Securities Litigation. On March 3, 2000, the U.S. District Court for
the Western District of Oklahoma dismissed a consolidated class action complaint
styled In re Chesapeake Energy Corporation Securities Litigation. The complaint,
which consolidated twelve purported class action suits filed in August and
September 1997, alleged violations of Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934 by the Company and certain of its officers and directors.
The action was brought on behalf of purchasers of the Company's common stock and
common stock options between January 25, 1996 and June 27, 1997. The complaint
alleged that the defendants made material misrepresentations and failed to
disclose material facts about the Company's exploration and drilling activities
in the Louisiana Trend. The Court ruled that Chesapeake had disclosed the
precise risks of its Louisiana Trend activities.
Bayard Drilling Technologies, Inc. On July 30, 1998, the plaintiffs in
Yuan, et al. v. Bayard, et al. filed an amended class action complaint in the
U.S. District Court for the Western District of Oklahoma alleging violations of
Sections 11 and 12 of the Securities Act of 1933 and Section 408 of the Oklahoma
Securities Act by the Company and others. The action, originally filed in
February 1998, was brought purportedly on behalf of investors who purchased
Bayard common stock in, or traceable to, Bayard's initial public offering in
November 1997. The defendants include officers and directors of Bayard who
signed the registration statement, selling shareholders (including the Company)
and underwriters of the offering. Total proceeds of the offering were $254
million, of which the Company received net proceeds of $90 million.
Plaintiffs allege that the Company, which owned 30.1% of Bayard's
outstanding common stock prior to the offering, was a controlling person of
Bayard. Plaintiffs also allege that the Company had established an interlocking
financial relationship with Bayard and was a customer of Bayard's drilling
services under allegedly below-market terms. Plaintiffs assert that the Bayard
prospectus contained material omissions and misstatements relating to (i) the
Company's financial "problems" and their impact on Bayard's operating results,
(ii) increased
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costs associated with Bayard's growth strategy, (iii) undisclosed pending
related-party transactions between Bayard and third parties other than the
Company, (iv) Bayard's planned use of offering proceeds and (v) Bayard's capital
expenditures and liquidity. The alleged defective disclosures are claimed to
have resulted in a decline in Bayard's share price following the public
offering. Plaintiffs seek a determination that the suit is a proper class action
and damages in an unspecified amount or rescission, together with interest and
costs of litigation, including attorneys' fees.
On August 24, 1999, the District Court entered an order granting in
part and denying in part defendants' motion to dismiss the action. The court
dismissed plaintiffs' claims against the Company under Section 15 of the
Securities Act of 1933 alleging that Chesapeake was a "controlling person" of
Bayard. The Court denied that portion of defendants' motion seeking dismissal of
plaintiffs' claims under Sections 11 and 12(a)(2) of the Securities Act of 1933
and Section 408 of the Oklahoma Securities Act. Of these, only the Section 11
claim and the Section 408 claim are asserted against the Company. The court has
also entered an order setting September 15, 2000 as the cutoff for merits
discovery, November 1, 2000 for the filing of any dispositive motions and
February 1, 2001 as the trial date.
The Company believes that it has meritorious defenses to these claims
and intends to defend this action vigorously. No estimate of loss or range of
estimate of loss, if any, can be made at this time. Bayard, which was acquired
by Nabors Industries, Inc. in April 1999, has been reimbursing the Company for
its costs of defense as incurred.
Patent Litigation. In Union Pacific Resources Company v. Chesapeake, et
al., filed in October 1996 in the U.S. District Court for the Northern District
of Texas, Fort Worth Division, UPRC asserted that the Company had infringed
UPRC's patent covering a "geosteering" method utilized in drilling horizontal
wells. Following a trial to the court in June 1999, the court ruled on September
21, 1999 that the patent was invalid. Because the patent was declared invalid,
the court held that the Company could not have infringed the patent, dismissed
all of UPRC's claims with prejudice and assessed court costs against UPRC. The
court concluded that the UPRC patent was invalid for failure to definitively
describe the patented method in the patent claims and for failure to provide
sufficient disclosure in the patent to enable one of ordinary skill in the art
to practice the patented method. Appeals of the judgment by both the Company and
UPRC are pending in the Federal Circuit Court of Appeals. Management is unable
to predict the outcome of these appeals but believes the invalidity of the
patent will be upheld on appeal. The Company has appealed the trial court's
ruling denying the Company's request for attorneys' fees.
West Panhandle Field Cessation Cases. A subsidiary of the Company,
Chesapeake Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and
two subsidiaries of Kinder Morgan, Inc. are defendants in 13 lawsuits filed
between June 1997 and January 1999 by royalty owners seeking the cancellation of
oil and gas leases in the West Panhandle Field in Texas. MC Panhandle, Inc.,
which the Company acquired in April 1998, has owned the leases since January 1,
1997. The co-defendants are prior lessees.
Plaintiffs claim the leases terminated upon the cessation of production
for various periods primarily during the 1960s. In addition, plaintiffs seek to
recover conversion damages, exemplary damages, attorneys' fees and interest.
Defendants assert that any cessation of production was excused and have pled
affirmative defenses of limitations, waiver, temporary estoppel, laches and
title by adverse possession. Four of the 13 cases have been tried; two are
scheduled to be tried in May and June 2000; and trial dates have not been set
for the other cases.
Following are the cases pending or tried in the District Court of Moore
County, Texas, 69th Judicial District:
Lois Law, et al. v. NGPL, et al., No. 97-70, filed December 22, 1997,
jury trial in June 1999, verdict for Company and co-defendants. The jury found
plaintiffs' claims were barred by adverse possession, laches and revivor. On
January 19, 2000, the court granted plaintiffs' motion for judgment
notwithstanding verdict and entered judgment in favor of plaintiffs. In addition
to quieting title to the lease (including existing gas wells and all attached
equipment) in plaintiffs, the court awarded actual damages against CP in the
amount of $716,400 and
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exemplary damages in the amount of $25,000. The court further awarded, jointly
and severally from all defendants, $160,000 in attorneys' fees and interest and
court costs. CP and the other defendants have filed a motion to reconsider, a
motion for new trial, and a notice of appeal.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-30, first filed December
17, 1997, refiled May 11, 1998, jury trial in June 1999, verdict for Company and
co-defendants. The jury found plaintiffs' claims were barred by laches and
adverse possession. On September 28, 1999, the court granted plaintiffs' motion
for judgment notwithstanding verdict and entered judgment in favor of
plaintiffs. In addition to quieting title to the lease (including existing gas
wells and all attached equipment) in plaintiffs, the court awarded actual
damages as of June 28, 1999 of $545,000 from CP and $235,000 jointly and
severally from the other two defendants. The court further awarded, jointly and
severally from all defendants, $77,500 of attorneys' fees in the event of an
appeal, $1,900 of sanctions, interest and court costs. CP and the other two
defendants filed an appeal of the judgment in the Court of Appeals for the
Seventh District of Texas in Amarillo on October 12, 1999, and they have each
posted a supersedeas bond.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-36, first filed February
2, 1998, refiled May 20, 1998, jury trial in July 1999, verdict for plaintiffs.
The jury found that the defendants were bad-faith trespassers and produced gas
from the leases as a result of fraud. On September 28, 1999, the court entered
final judgment for plaintiffs terminating the lease, quieting title to the lease
(including existing gas wells and all attached equipment) in plaintiffs as of
June 1, 1999 and awarding actual damages of $1.5 million, attorneys' fees of
$97,500 in the event of an appeal, interest and court costs. CP's liability for
this award is joint and several with the other two defendants. The court also
awarded exemplary damages of $1.2 million against each of CP and the other two
defendants. CP and the other two defendants filed an appeal of the judgment in
the Court of Appeals for the Seventh District of Texas in Amarillo on October
12, 1999, and they have each posted a supersedeas bond.
A. C. Smith, et al. v. NGPL, et al., No. 98-47, first filed January 26,
1998, refiled May 29, 1998. On June 18, 1999, the court granted plaintiffs'
motion for summary judgment in part, finding that the lease had terminated due
to the cessation of production, subject to the defendants' affirmative defenses.
A jury trial is scheduled in May 2000.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-35, first filed February
2, 1998, refiled May 20, 1998. On December 3, 1999, the Court entered a partial
summary judgment finding the lease had terminated and that defendants'
affirmative defenses all failed as a matter of law except with respect to the
defense of revivor against certain of the plaintiffs. CP and the other
defendants filed a motion to reconsider on December 22, 1999.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-49, first filed March
10, 1998, refiled May 29, 1998.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-50, first filed March
18, 1998, refiled May 29, 1998.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-51, first filed December
2, 1997, refiled May 29, 1998.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-48, first filed February
2, 1998, refiled May 29, 1998.
Joseph H. Pool, et al. v. NGPL, et al., No. 98-70, first filed March
23, 1998, refiled October 22, 1998.
The Pool cases listed above were first filed in the U.S. District
Court, Northern District of Texas, Amarillo Division. Other related cases
pending are the following:
Phillip Thompson, et al. v. NGPL, et al, U.S. District Court, Northern
District of Texas, Amarillo Division, Nos. 2:98-CV-012 and 2:98-CV-106, filed
January 8, 1998 and March 18, 1998, respectively (actions consolidated), jury
trial in May 1999, verdict for Company and co-defendants. The jury found
plaintiffs' claims were barred by the payment of shut-in royalties, laches, and
revivor. Plaintiffs have filed a motion for a new trial.
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Craig Fuller, et al. v. NGPL, et al., District Court of Carson County,
Texas, 100th Judicial District, No. 8456, filed June 23, 1997, cross motions for
summary judgment pending. No trial date has been set.
Pace v. NGPL et al., U.S. District Court, Northern District of Texas,
Amarillo Division, filed January 29, 1999. Defendants' motion for summary
judgment pending. Trial date in June 2000.
Ralph W. Coon, et al. v. MC Panhandle, Inc., et al., U.S. District
Court, Eastern District of Texas, Lufkin Division, No. 2:98-CV-63, filed March
27, 1998. All lease termination claims have been withdrawn. Only royalty
calculation issues remain.
The Company has previously established an accrued liability that
management believes will be sufficient to cover the estimated costs of
litigation for each of these cases. Because of the inconsistent verdicts reached
by the juries in the four cases tried to date and because the amount of damages
sought is not specified in all of the other cases, the outcome of the remaining
trials and the amount of damages that might ultimately be awarded could differ
from management's estimates. Management believes, however, that the leases are
valid, there is no basis for exemplary damages and that any findings of fraud or
bad faith will be overturned on appeal. CP and the other defendants intend to
vigorously defend against the plaintiffs' claims.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
The common stock trades on the New York Stock Exchange under the symbol
"CHK". The following table sets forth, for the periods indicated, the high and
low sales prices per share of the common stock as reported by the New York Stock
Exchange:
COMMON STOCK
---------------
HIGH LOW
---- ---
Year ended December 31, 1998:
First Quarter..................................................................... 7.75 5.50
Second Quarter.................................................................... 6.00 3.88
Third Quarter..................................................................... 4.06 1.13
Fourth Quarter.................................................................... 2.63 0.75
Year ended December 31, 1999:
First Quarter..................................................................... 1.50 0.63
Second Quarter.................................................................... 2.94 1.31
Third Quarter..................................................................... 4.13 2.75
Fourth Quarter.................................................................... 3.88 2.13
At March 17, 2000 there were 1,105 holders of record of common stock and
approximately 22,500 beneficial owners.
DIVIDENDS
The Company paid quarterly dividends of $0.02 per common share from July
1997 to July 1998. In September 1998 the Board of Directors determined that
because of low oil and natural gas prices the payment of cash dividends on the
common stock should be cancelled. The payment of future cash dividends, if any,
will be reviewed periodically by the Board of Directors and will depend upon,
among other things, the Company's financial condition, funds from operations,
the level of its capital and development expenditures, its future business
prospects and any contractual restrictions.
Two of the indentures governing the Company's outstanding senior notes
contain restrictions on the Company's ability to declare and pay dividends.
Under these indentures, the Company may not pay any cash dividends on its common
or preferred stock if (i) a default or an event of default has occurred and is
continuing at the time of or immediately after giving effect to the dividend
payment, (ii) the Company would not be able to incur at least $1 of additional
indebtedness under the terms of the indentures, or (iii) immediately after
giving effect to the dividend payment, the aggregate of all dividends and other
restricted payments declared or made after the respective issue dates of the
notes exceeds the sum of specified income, proceeds from the issuance of stock
and debt by the Company and other amounts from the quarter in which the
respective note issuances occurred to the quarter immediately preceding the date
of the dividend payment. From December 31, 1998 through December 31, 1999, the
Company did not meet the debt incurrence tests under these indentures and was
not able to pay dividends on its preferred stock.
Subsequent to December 31, 1999, the Company entered into a number of
unsolicited transactions whereby the Company issued approximately 8.8 million
shares of the Company's common shares in exchange for 625,000 shares of the
Company's preferred stock. This reduced the liquidation amount of preferred
stock outstanding by $31.3 million to $198.7 million, and reduced the amount of
preferred dividends in arrears by $2.9 million to $19.3 million as of February
29, 2000.
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ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of the
Company for each of the two fiscal years ended June 30, 1997, the six-month
Transition Period ended December 31, 1997, the six months ended December 31,
1996 and the twelve months ended December 31, 1999, 1998 and 1997. The data are
derived from the audited consolidated financial statements of the Company,
although the periods for the year ended December 31, 1997 and the six months
ended December 31, 1996 have not been audited. Acquisitions made by the Company
during the first and second quarters of 1998 materially affect the comparability
of the selected financial data for 1997 and 1998. Each of the acquisitions was
accounted for using the purchase method. The table should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements, including the notes
thereto, appearing in Items 7 and 8 of this report.
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YEARS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
------------------------------------------ ---------------------------
1999 1998 1997 1997 1996
------------ ------------ ------------ ------------ ------------
(unaudited) (unaudited)
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales ....................... $ 280,445 $ 256,887 $ 198,410 $ 95,657 $ 90,167
Oil and gas marketing sales ............. 74,501 121,059 104,394 58,241 30,019
Oil and gas service operations .......... -- -- -- -- --
------------ ------------ ------------ ------------ ------------
Total revenues ..................... 354,946 377,946 302,804 153,898 120,186
------------ ------------ ------------ ------------ ------------
Operating costs:
Production expenses ..................... 46,298 51,202 14,737 7,560 4,268
Production taxes ........................ 13,264 8,295 4,590 2,534 1,606
General and administrative .............. 13,477 19,918 10,910 5,847 3,739
Oil and gas marketing expenses .......... 71,533 119,008 103,819 58,227 29,548
Oil and gas service operations .......... -- -- -- -- --
Oil and gas depreciation,
depletion and amortization .......... 95,044 146,644 127,429 60,408 36,243
Depreciation and amortization of
other assets .......................... 7,810 8,076 4,360 2,414 1,836
Impairment of oil and gas properties..... -- 826,000 346,000 110,000 --
Impairment of other assets .............. -- 55,000 -- -- --
------------ ------------ ------------ ------------ ------------
Total operating costs .............. 247,426 1,234,143 611,845 246,990 77,240
------------ ------------ ------------ ------------ ------------
Income (loss) from operations .............. 107,520 (856,197) (309,041) (93,092) 42,946
------------ ------------ ------------ ------------ ------------
Other income (expense):
Interest and other income ............... 8,562 3,926 87,673 78,966 2,516
Interest expense ........................ (81,052) (68,249) (29,782) (17,448) (6,216)
------------ ------------ ------------ ------------ ------------
(72,490) (64,323) 57,891 61,518 (3,700)
------------ ------------ ------------ ------------ ------------
Income (loss) before income taxes
and extraordinary item ................ 35,030 (920,520) (251,150) (31,574) 39,246
Provision (benefit) for income taxes ....... 1,764 -- (17,898) -- 14,325
------------ ------------ ------------ ------------ ------------
Income (loss) before extraordinary item..... 33,266 (920,520) (233,252) (31,574) 24,921
Extraordinary item:
Loss on early extinguishment of
debt, net of applicable income taxes... -- (13,334) (177) -- (6,443)
------------ ------------ ------------ ------------ ------------
Net income (loss) .......................... 33,266 (933,854) (233,429) (31,574) 18,478
Preferred stock dividends .................. (16,711) (12,077) -- -- --
------------ ------------ ------------ ------------ ------------
Net income (loss) available to
common shareholders ................... $ 16,555 $ (945,931) $ (233,429) $ (31,574) $ 18,478
============ ============ ============ ============ ============
Earnings (loss) per common share - basic:
Income (loss) before extraordinary item .... $ 0.17 $ (9.83) $ (3.30) $ (0.45) $ 0.40
Extraordinary item ......................... -- (0.14) -- -- (0.10)
------------ ------------ ------------ ------------ ------------
Net income (loss) .......................... $ 0.17 $ (9.97) $ (3.30) $ (0.45) $ 0.30
============ ============ ============ ============ ============
Earnings (loss) per common share -
assuming dilution:
Income (loss) before extraordinary item..... $ 0.16 $ (9.83) $ (3.30) $ (0.45) $ 0.38
Extraordinary item ......................... -- (0.14) -- -- (0.10)
------------ ------------ ------------ ------------ ------------
Net income (loss) .......................... $ 0.16 $ (9.97) $ (3.30) $ (0.45) $ 0.28
============ ============ ============ ============ ============
Cash dividends declared
per common share ...................... $ -- $ 0.04 $ 0.06 $ 0.04 $ --
CASH FLOW DATA:
Cash provided by operating
activities before changes in
working capital ....................... $ 138,727 $ 117,500 $ 152,196 $ 67,872 $ 76,816
Cash provided by
operating activities .................. 145,022 94,639 181,345 139,157 41,901
Cash used in investing activities .......... 159,773 548,050 476,209 136,504 184,149
Cash provided by (used in)
financing activities .................. 18,967 363,797 277,985 (2,810) 231,349
Effect of exchange rate
changes on cash ....................... 4,922 (4,726) -- -- --
BALANCE SHEET DATA (at end of period):
Total assets ............................... $ 850,533 $ 812,615 $ 952,784 $ 952,784 $ 860,597
Long-term debt, net of current
maturities ............................ 964,097 919,076 508,992 508,992 220,149
Stockholders' equity (deficit) ............. (217,544) (248,568) 280,206 280,206 484,062
YEARS ENDED
JUNE 30,
---------------------------
1997 1996
------------ ------------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales ....................... $ 192,920 $ 110,849
Oil and gas marketing sales ............. 76,172 28,428
Oil and gas service operations .......... -- 6,314
------------ ------------
Total revenues ..................... 269,092 145,591
------------ ------------
Operating costs:
Production expenses ..................... 11,445 6,340
Production taxes ........................ 3,662 1,963
General and administrative .............. 8,802 4,828
Oil and gas marketing expenses .......... 75,140 27,452
Oil and gas service operations .......... -- 4,895
Oil and gas depreciation,
depletion and amortization .......... 103,264 50,899
Depreciation and amortization of
other assets .......................... 3,782 3,157
Impairment of oil and gas properties..... 236,000 --
Impairment of other assets .............. -- --
------------ ------------
Total operating costs .............. 442,095 99,534
------------ ------------
Income (loss) from operations .............. (173,003) 46,057
------------ ------------
Other income (expense):
Interest and other income ............... 11,223 3,831
Interest expense ........................ (18,550) (13,679)
------------ ------------
(7,327) (9,848)
------------ ------------
Income (loss) before income taxes
and extraordinary item ................ (180,330) 36,209
Provision (benefit) for income taxes ....... (3,573) 12,854
------------ ------------
Income (loss) before extraordinary item..... (176,757) 23,355
Extraordinary item:
Loss on early extinguishment of
debt, net of applicable income taxes... (6,620) --
------------ ------------
Net income (loss) .......................... (183,377) 23,355
Preferred stock dividends .................. -- --
------------ ------------
Net income (loss) available to
common shareholders ................... $ (183,377) $ 23,355
============ ============
Earnings (loss) per common share - basic:
Income (loss) before extraordinary item .... $ (2.69) $ 0.43
Extraordinary item ......................... (0.10) --
------------ ------------
Net income (loss) .......................... $ (2.79) $ 0.43
============ ============
Earnings (loss) per common share -
assuming dilution:
Income (loss) before extraordinary item..... $ (2.69) $ 0.40
Extraordinary item ......................... (0.10) --
------------ ------------
Net income (loss) .......................... $ (2.79) $ 0.40
============ ============
Cash dividends declared
per common share ...................... $ 0.02 $ --
CASH FLOW DATA:
Cash provided by operating
activities before changes in
working capital ....................... $ 161,140 $ 88,431
Cash provided by
operating activities .................. 84,089 120,972
Cash used in investing activities .......... 523,854 344,389
Cash provided by (used in)
financing activities .................. 512,144 219,520
Effect of exchange rate
changes on cash ....................... -- --
BALANCE SHEET DATA (at end of period):
Total assets ............................... $ 949,068 $ 572,335
Long-term debt, net of current
maturities ............................ 508,950 268,431
Stockholders' equity (deficit) ............. 286,889 177,767
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
The following table sets forth certain operating data of the Company for the
periods presented:
YEARS ENDED
DECEMBER 31,
------------------------------------------
1999 1998 1997
------------ ------------ ------------
NET PRODUCTION DATA:
Oil (MBbl) ................................ 4,147 5,976 3,511
Gas (MMcf) ................................ 108,610 94,421 59,236
Gas equivalent (MMcfe) .................... 133,492 130,277 80,302
OIL AND GAS SALES ($ IN 000'S):
Oil ....................................... $ 66,413 $ 75,877 $ 68,079
Gas ....................................... 214,032 181,010 130,331
------------ ------------ ------------
Total oil and gas sales ........... $ 280,445 $ 256,887 $ 198,410
============ ============ ============
AVERAGE SALES PRICE:
Oil ($ per Bbl) ........................... $ 16.01 $ 12.70 $ 19.39
Gas ($ per Mcf) ........................... $ 1.97 $ 1.92 $ 2.20
Gas equivalent ($ per Mcfe) ............... $ 2.10 $ 1.97 $ 2.47
OIL AND GAS COSTS ($ PER MCFE):
Production expenses and taxes ............. $ .45 $ .45 $ .24
General and administrative ................ $ .10 $ .15 $ .14
Depreciation, depletion and amortization .. $ .71 $ 1.13 $ 1.59
NET WELLS DRILLED:
Horizontal wells .......................... 11 20 69
Vertical wells ............................ 109 116 32
NET WELLS AT END OF PERIOD .................. 2,242 2,405 401
RESULTS OF OPERATIONS
Years Ended December 31, 1999, 1998 and 1997
General. In 1999, the Company had net income of $33.3 million, or $0.16 per
diluted common share, on total revenues of $354.9 million. This compares to a
net loss of $933.9 million, or a loss of $9.97 per diluted common share, on
total revenues of $377.9 million during the year ended December 31, 1998
("1998"), and a net loss of $233.4 million, or a loss of $3.30 per diluted
common share, on total revenues of $302.8 million during the year ended December
31, 1997 ("1997"). The loss in 1998 was caused primarily by an $826.0 million
oil and gas property writedown recorded under the full-cost method of accounting
and a $55.0 million writedown of other assets. The loss in 1997 was caused
primarily by a $346 million oil and gas property writedown. See "Impairment of
Oil and Gas Properties" and "Impairment of Other Assets".
Oil and Gas Sales. During 1999, oil and gas sales increased to $280.4
million versus $256.9 million in 1998 and $198.4 million in 1997. In 1999, the
Company produced 133.5 Bcfe at a weighted average price of $2.10 per Mcfe,
compared to 130.3 Bcfe produced in 1998 at a weighted average price of $1.97 per
Mcfe, and 80.3 Bcfe produced in 1997 at a weighted average price of $2.47 per
Mcfe.
The following table shows the Company's production by region for 1999, 1998
and 1997:
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------
1999 1998 1997
------------------- ------------------- -------------------
MMCFE PERCENT MMCFE PERCENT MMCFE PERCENT
-------- -------- -------- -------- -------- --------
Mid-Continent ................ 69,946 52% 61,930 48% 17,685 22%
Gulf Coast ................... 44,822 34 52,793 40 60,662 76
Canada ....................... 11,737 9 7,746 6 -- --
All other areas .............. 6,987 5 7,808 6 1,955 2
-------- -------- -------- -------- -------- --------
Total production ....... 133,492 100% 130,277 100% 80,302 100%
======== ======== ======== ======== ======== ========
Natural gas production represented approximately 81% of the Company's total
production volume on an equivalent basis in 1999, compared to 72% in 1998 and
74% in 1997.
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For 1999, the Company realized an average price per barrel of oil of $16.01,
compared to $12.70 in 1998 and $19.39 in 1997. Gas price realizations fluctuated
from an average of $1.92 per Mcf in 1998 and $2.20 in 1997 to $1.97 per Mcf in
1999. The Company's hedging activities resulted in a decrease in oil and gas
revenues of $1.7 million in 1999, an increase in oil and gas revenues of $11.3
million in 1998, and a decrease in oil and gas revenues of $4.6 million in 1997.
Oil and Gas Marketing Sales. The Company realized $74.5 million in oil and
gas marketing sales for third parties in 1999, with corresponding oil and gas
marketing expenses of $71.5 million, for a net margin of $3.0 million. This
compares to sales of $121.1 million and $104.4 million, expenses of $119.0
million and $103.8 million, and a margin of $2.1 million and $0.6 million in
1998 and 1997, respectively.
Production Expenses and Taxes. Production expenses and taxes, which include
lifting costs, production taxes and ad valorem taxes, were $59.6 million in
1999, compared to $59.5 million and $19.3 million in 1998 and 1997,
respectively. On a unit of production basis, production expenses and taxes were
$0.45 per Mcfe in 1999 and 1998, and $0.24 per Mcfe in 1997. The Company expects
that lease operating expenses per Mcfe will generally remain at current levels
throughout 2000, although production taxes will increase as a result of
increased oil and gas prices.
Impairment of Oil and Gas Properties. The Company utilizes the full-cost
method to account for its investment in oil and gas properties. Under this
method, all costs of acquisition, exploration and development of oil and gas
reserves (including such costs as leasehold acquisition costs, geological and
geophysical expenditures, certain capitalized internal costs, dry hole costs and
tangible and intangible development costs) are capitalized as incurred. These
oil and gas property costs, along with the estimated future capital expenditures
to develop proved undeveloped reserves, are depleted and charged to operations
using the unit-of-production method based on the ratio of current production to
proved oil and gas reserves as estimated by the Company's independent
engineering consultants and Company engineers. Costs directly associated with
the acquisition and evaluation of unproved properties are excluded from the
amortization computation until it is determined whether or not proved reserves
can be assigned to the property or whether impairment has occurred. The excess
of capitalized costs of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred income taxes, over the
discounted future net revenues of proved oil and gas properties is charged to
operations.
The Company incurred an impairment of oil and gas properties charge of $826
million in 1998. No such charge was incurred in 1999. The 1998 writedown was
caused by a combination of several factors, including the acquisitions completed
by the Company during 1998, which were accounted for using the purchase method,
and the significant decreases in oil and gas prices throughout 1998. Oil and gas
prices used to value the Company's proved reserves decreased from $17.62 per Bbl
of oil and $2.29 per Mcf of gas at December 31, 1997, to $10.48 per Bbl of oil
and $1.68 per Mcf of gas at December 31, 1998. Higher drilling and completion
costs and the evaluation of certain leasehold, seismic and other
exploration-related costs that were previously unevaluated were the remaining
factors which contributed to the writedown in 1998.
The Company incurred an impairment of oil and gas properties charge of $346
million during 1997. The writedown in 1997 was caused by several factors,
including declining oil and gas prices during the year, escalating drilling and
completion costs, and poor drilling results primarily in Louisiana.
Impairment of Other Assets. The Company incurred a $55 million impairment
charge during 1998. Of this amount, $30 million related to the Company's
investment in preferred stock of Gothic Energy Corporation, and the remainder
was related to certain of the Company's gas processing and transportation assets
located in Louisiana. No such charge was recorded in 1999 or 1997.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization ("DD&A") of oil and gas properties was $95.0 million,
$146.6 million and $127.4 million during 1999, 1998 and 1997, respectively. The
average DD&A rate per Mcfe, which is a function of capitalized costs, future
development costs, and the related underlying reserves in the periods presented,
was $0.71 ($0.73 in U.S. and $0.52 in Canada), $1.13
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25
($1.17 in U.S. and $0.43 in Canada) and $1.59 (U.S. only) in 1999, 1998 and
1997, respectively. The Company expects the 2000 DD&A rate to be between $0.75
and $0.80 per Mcfe.
Depreciation and Amortization of Other Assets. Depreciation and amortization
("D&A") of other assets was $7.8 million in 1999, compared to $8.1 million in
1998 and $4.4 million in 1997. The increase in 1998 compared to 1997 was caused
by increased investments in depreciable buildings and equipment and increased
amortization of debt issuance costs as a result of the issuance of senior notes
in April 1998.
General and Administrative. General and administrative ("G&A") expenses,
which are net of capitalized internal payroll and non-payroll expenses (see Note
11 of Notes to Consolidated Financial Statements), were $13.5 million in 1999,
$19.9 million in 1998 and $10.9 million in 1997. The decrease in 1999 compared
to 1998 was due primarily to various actions taken to lower corporate overhead,
including staff reductions and office closings which occurred in late 1998 and
early 1999. The increase in 1998 compared to 1997 is due primarily to increased
personnel expenses required by the Company's growth and industry wage inflation.
The Company capitalized $2.7 million, $5.3 million and $5.3 million of internal
costs in 1999, 1998 and 1997, respectively, directly related to the Company's
oil and gas exploration and development efforts. The Company anticipates that
G&A costs for 2000 per Mcfe will remain at approximately the same level as 1999.
Interest and Other Income. Interest and other income for 1999 was $8.6
million compared to $3.9 million in 1998, and $87.7 million in 1997. The
increase from 1998 to 1999 was due primarily to gains on sales of various
non-core assets during 1999. During 1997, the Company realized a gain on the
sale of its Bayard common stock of $73.8 million, the most significant component
of interest and other income.
Interest Expense. Interest expense increased to $81.1 million in 1999,
compared to $68.2 million in 1998 and $29.8 million in 1997. The increase in
1999 is due primarily to a full year of interest on the Company's $500 million
senior notes. The increase in 1998 compared to 1997 was due primarily to the
issuance of $500 million of senior notes in April 1998. In addition to the
interest expense reported, the Company capitalized $3.5 million of interest
during 1999, compared to $6.5 million capitalized in 1998, and $10.4 million
capitalized in 1997. The Company anticipates that capitalized interest for 2000
will be between $3 million and $4 million.
Provision (Benefit) for Income Taxes. The Company recorded income taxes of
$1.8 million in 1999 compared to $0 in 1998 and an income tax benefit of $17.9
million in 1997. The income tax expense recorded in 1999 is related entirely to
the Company's Canadian operations.
At December 31, 1999, the Company had a U.S. net operating loss carryforward
of approximately $613 million for regular federal income taxes which will expire
in future years beginning in 2007. Management believes that it cannot be
demonstrated at this time that it is more likely than not that the deferred
income tax assets, comprised primarily of the net operating loss carryforwards
generated for U.S. purposes, will be realizable in future years, and therefore a
valuation allowance of $442 million has been recorded. The Company does not
expect to record any net income tax expense related to its U.S. operations in
2000 based on information available at this time.
LIQUIDITY AND CAPITAL RESOURCES
Years Ended December 31, 1999, 1998 and 1997
Cash Flows from Operating Activities. Cash provided by operating activities
(inclusive of changes in working capital) was $145.0 million in 1999, compared
to $94.6 million in 1998 and $181.3 million in 1997. The increase of $50.4
million from 1998 to 1999 was due primarily to increased oil and gas revenues.
The decrease of $86.7 million from 1997 to 1998 was due primarily to reduced
operating income resulting from significant decreases in average oil and gas
prices between periods, as well as significant increases in G&A expenses and
interest expense.
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26
Cash Flows from Investing Activities. Cash used in investing activities
decreased to $159.8 million in 1999, compared to $548.1 million in 1998 and
$476.2 million in 1997. During 1999, the Company invested $153.3 million for
exploration and development drilling, $49.9 million for the acquisition of oil
and gas properties, and received $45.6 million related to divestitures of oil
and gas properties. During 1998, $279.9 million was used to acquire certain oil
and gas properties and companies with oil and gas reserves. However, the
increase in cash used to acquire oil and gas properties was partially offset by
reduced expenditures during 1998 for exploratory and developmental drilling.
During 1998 and 1997, the Company invested $259.7 million and $471.0 million,
respectively, for exploratory and developmental drilling. Also during 1998, the
Company sold its 19.9% stake in Pan East Petroleum Corp. to Poco Petroleums,
Ltd. for approximately $21.2 million. During 1997 the Company received net
proceeds from the sale of its investment in Bayard common stock of approximately
$90.4 million.
Cash Flows from Financing Activities. Cash provided by financing activities
decreased to $19.0 million in 1999, compared to $363.8 million in 1998, and
$278.0 million in 1997. During 1999, the Company made additional borrowings
under its commercial bank credit facility of $116.5 million, and had payments
under this facility of $98.0 million. During 1998, the Company retired $85
million of debt assumed at the completion of the DLB Oil & Gas, Inc.
acquisition, $120 million of debt assumed at the completion of the Hugoton
Energy Corporation acquisition, $90 million of senior notes, and $170 million of
borrowings made under its commercial bank credit facilities. Also during 1998,
the Company issued $500 million in senior notes and $230 million in preferred
stock. During 1997, the Company issued $300 million of senior notes.
Financial Flexibility and Liquidity
The Company had working capital of $9.4 million at December 31, 1999 and a
cash balance of $38.7 million. The Company has a $50 million revolving bank
credit facility which matures in January 2001, with an initial committed
borrowing base of $50 million. As of December 31, 1999, the Company had borrowed
$43.5 million under this facility. Borrowings under the facility are secured by
certain producing oil and gas properties and bear interest at a variable rate,
which was 9.75% per annum as of December 31, 1999.
At December 31, 1999, the Company's senior notes represented $919.2 million
of its $964.1 million of long-term debt. Debt ratings for the senior notes are
B3 by Moody's Investors Service and B by Standard & Poor's Corporation as of
March 22, 2000. There are no scheduled principal payments required on any of the
senior notes until March 2004, when $150 million is due.
The senior note indentures restrict the ability of the Company and its
restricted subsidiaries to incur additional indebtedness. As of December 31,
1999, the Company estimates that secured commercial bank indebtedness of $147
million could have been incurred within these restrictions. The indenture
restrictions do not apply to borrowings incurred by CEMI, an unrestricted
subsidiary.
The senior note indentures also limit the Company's ability to make
restricted payments (as defined), including the payment of preferred stock
dividends, unless certain tests are met. From December 31, 1998 through December
31, 1999, the Company was unable to meet the requirements to incur additional
unsecured indebtedness, and consequently was not able to pay cash dividends on
its 7% cumulative convertible preferred stock. The Company had accumulated
dividends in arrears of $19.3 million related to its preferred stock as of
February 29, 2000. Subsequent payments will be subject to the same restrictions
and are dependent upon variables that are beyond the Company's ability to
predict. This restriction does not affect the Company's ability to borrow under
or expand its secured commercial bank facility. If the Company fails to pay
dividends for six quarterly periods, the holders of preferred stock will be
entitled to elect two new directors to the Board. Based on current projections
of cash flow and fixed charges, the Company does not expect to be able to pay a
dividend on the preferred stock on May 1, 2000, which would be the sixth
consecutive dividend payment date on which dividends have not been paid.
In January and February 2000, the Company engaged in five separate
transactions with two institutional investors in which the Company exchanged a
total of 8.8 million shares of common stock (both newly issued and treasury
shares) for 625,000 shares of its issued and outstanding preferred stock with a
liquidation value of $31.3
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million plus dividends in arrears of $2.9 million. All preferred shares acquired
in these transactions were cancelled and retired and will have the status of
authorized but unissued shares of undesignated preferred stock.
The Company believes it has adequate resources, including cash on hand,
budgeted cash flow from operations and proceeds from miscellaneous asset sales,
to fund its capital expenditure budget for exploration and development
activities during 2000, which are currently estimated to be approximately
$130-$140 million. However, low oil and gas prices or unfavorable drilling
results could cause the Company to reduce its drilling program, which is largely
discretionary.
RECENTLY ISSUED ACCOUNTING STANDARDS
On June 15, 1998, the Financial Accounting Standards Board issued FAS No.
133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133").
FAS 133 establishes a new model for accounting for derivatives and hedging
activities and supersedes and amends a number of existing standards. FAS 133 (as
amended by FAS 137) is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000.
FAS 133 standardizes the accounting for derivative instruments by requiring
that all derivatives be recognized as assets and liabilities and measured at
fair value. The accounting for changes in the fair value of derivatives (gains
and losses) depends on (i) whether the derivative is designated and qualifies as
a hedge, and (ii) the type of hedging relationship that exists. Changes in the
fair value of derivatives that are not designated as hedges or that do not meet
the hedge accounting criteria in FAS 133 are required to be reported in
earnings. In addition, all hedging relationships must be designated, reassessed
and documented pursuant to the provisions of FAS 133. The Company has not yet
determined the impact that adoption of FAS 133 wi