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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:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
---------------------------- -----------------------
<S> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
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
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
=== ===== ==== ====
</TABLE>
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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<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, JUNE 30,
---------------------------
1999 1998 1997 1997
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
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
</TABLE>
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 $2.25 per
Mcf of gas):
<TABLE>
<CAPTION>
PERCENT PRESENT
GAS OF VALUE
OIL GAS EQUIVALENT PROVED (DISC. @ 10%)
(MBBL) (MMCF) (MMCFE) RESERVES ($ IN 000'S)
------ ---------- --------- -------- ------------
<S> <C> <C> <C> <C> <C>
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% $1,089,496
====== ========== ========= ==== ==========
</TABLE>
During 1999, Chesapeake increased its proved developed reserve percentage to
80% by present value and 72% by volume, and natural gas reserves accounted for
88% of proved reserves at December 31, 1999.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated:
<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS
DECEMBER 31, ENDED YEAR ENDED
------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
--------- --------- --------- ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
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
========= ========= ========= =========
</TABLE>
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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.
<TABLE>
<CAPTION>
TOTAL DEVELOPED
DEVELOPED UNDEVELOPED AND UNDEVELOPED
--------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
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
===== ===== ===== ===== ===== =====
</TABLE>
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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<PAGE> 9
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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<PAGE> 10
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):
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES - OIL AND GAS PROPERTIES
GROSS NET ------------------------------------------------------------------------
WELLS WELLS SALE OF
DRILLED DRILLED DRILLING LEASEHOLD SUB-TOTAL ACQUISITIONS PROPERTIES TOTAL
------- -------- -------- --------- --------- ------------ ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
======= ======== ======== ========= ========= ============ ========== ========
</TABLE>
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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<PAGE> 15
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.
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF DECEMBER 31, 1999 (MBBL) (MMCF) (MMCFE)
----------------------- ------- --------- ---------
<S> <C> <C> <C>
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
======= ========= =========
</TABLE>
<TABLE>
<CAPTION>
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF DECEMBER 31, 1999(a) DEVELOPED UNDEVELOPED PROVED
-------------------------- --------- ----------- ----------
($ IN THOUSANDS)
<S> <C> <C> <C>
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
</TABLE>
- ----------
(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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<PAGE> 16
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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<PAGE> 17
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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<PAGE> 18
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.
-18-
<PAGE> 19
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
-19-
<PAGE> 20
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:
<TABLE>
<CAPTION>
COMMON STOCK
---------------
HIGH LOW
---- ---
<S> <C> <C>
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
</TABLE>
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 $19.3 million as of February
29, 2000.
-20-
<PAGE> 21
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of the
Company for each of the two fiscal years ended June 30, 1997, the six-month
Transition Period ended December 31, 1997, the six months ended December 31,
1996 and the twelve months ended December 31, 1999, 1998 and 1997. The data are
derived from the audited consolidated financial statements of the Company,
although the periods for the year ended December 31, 1997 and the six months
ended December 31, 1996 have not been audited. Acquisitions made by the Company
during the first and second quarters of 1998 materially affect the comparability
of the selected financial data for 1997 and 1998. Each of the acquisitions was
accounted for using the purchase method. The table should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements, including the notes
thereto, appearing in Items 7 and 8 of this report.
-21-
<PAGE> 22
<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
------------------------------------------ ---------------------------
1999 1998 1997 1997 1996
------------ ------------ ------------ ------------ ------------
(unaudited) (unaudited)
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
YEARS ENDED
JUNE 30,
---------------------------
1997 1996
------------ ------------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C>
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
</TABLE>
-22-
<PAGE> 23
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:
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
------------------------------------------
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------
1999 1998 1997
------------------- ------------------- -------------------
MMCFE PERCENT MMCFE PERCENT MMCFE PERCENT
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
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%
======== ======== ======== ======== ======== ========
</TABLE>
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.
-23-
<PAGE> 24
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
-24-
<PAGE> 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.
-25-
<PAGE> 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
-26-
<PAGE> 27
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 will have on the financial
statements. However, the Company believes that all of its derivative instruments
will be designated as hedges in accordance with the relevant accounting
criteria, and therefore the impact of the adoption of FAS 133 is not expected to
have a material effect on the Company's financial statements.
FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical facts
included in this Form 10-K, including, without limitation, statements regarding
oil and gas reserve estimates, planned capital expenditures, expected oil and
gas production, the Company's financial position, business strategy and other
plans and objectives for future operations, expected future expenses, and
realization of deferred tax assets, are forward-looking statements. Although the
Company believes that the expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations will
prove to have been correct. Factors that could cause actual results to differ
materially from those expected by the Company, including, without limitation,
factors discussed under Risk Factors in Item 1 of this Form 10-K, are
substantial indebtedness, impairment of asset value, need to replace reserves,
substantial capital requirements, ability to supplement capital resources with
asset sales, fluctuations in the prices of oil and gas, uncertainties inherent
in estimating quantities of oil and gas reserves, projecting future rates of
production and the timing of development expenditures, competition, operating
risks, restrictions imposed by lenders, liquidity and capital requirements, the
effects of governmental and environmental regulation, pending litigation, and
adverse changes in the market for the Company's oil and gas production. Readers
are cautioned not to place undue reliance on these forward-looking statements,
which speak only as of the date hereof. The Company undertakes no obligation to
release publicly the result of any revisions to these forward-looking statements
that may be made to reflect events or circumstances after the date hereof,
including, without limitation, changes in the Company's business strategy or
planned capital expenditures, or to reflect the occurrence of unanticipated
events.
-27-
<PAGE> 28
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
The Company's results of operations are highly dependent upon the prices
received for oil and natural gas production.
HEDGING ACTIVITIES
Periodically the Company utilizes hedging strategies to hedge the price of a
portion of its future oil and gas production. These strategies include:
(i) swap arrangements that establish an index-related price above which
the Company pays the counterparty and below which the Company is paid
by the counterparty,
(ii) the purchase of index-related puts that provide for a "floor" price
below which the counterparty pays the Company the amount by which the
price of the commodity is below the contracted floor,
(iii) the sale of index-related calls that provide for a "ceiling" price
above which the Company pays the counterparty the amount by which the
price of the commodity is above the contracted ceiling, and
(iv) basis protection swaps, which are arrangements that guarantee the
price differential of oil or gas from a specified delivery point or
points.
Results from commodity hedging transactions are reflected in oil and gas
sales to the extent related to the Company's oil and gas production. The Company
only enters into commodity hedging transactions related to the Company's oil and
gas production volumes or CEMI's physical purchase or sale commitments. Gains or
losses on crude oil and natural gas hedging transactions are recognized as price
adjustments in the months of related production.
As of December 31, 1999, the Company had the following open natural gas swap
arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1999:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------ -----------
<S> <C> <C>
April 2000........................... 600,000 $ 2.50
May 2000............................. 620,000 2.50
June 2000............................ 600,000 2.50
July 2000............................ 620,000 2.50
August 2000.......................... 620,000 2.50
September 2000....................... 600,000 2.50
October 2000......................... 620,000 2.50
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1999,
the Company would have incurred a gain of $0.5 million.
As of December 31, 1999, the Company had no open oil swap arrangements.
The Company has also closed transactions designed to hedge a portion of the
Company's domestic oil and natural gas production. The net unrecognized losses
resulting from these transactions, $3.9 million as of December 31, 1999, will be
recognized as price adjustments in the months of related production. These
hedging gains and losses are set forth below ($ in thousands):
<TABLE>
<CAPTION>
HEDGING GAINS (LOSSES)
-----------------------------------
MONTH GAS OIL TOTAL
- ----- --------- --------- ---------
<S> <C> <C> <C>
January 2000 ...................... $ -- $ (995) $ (995)
February 2000 ..................... -- (1,061) (1,061)
March 2000 ........................ 689 (851) (162)
April 2000 ........................ 71 (647) (576)
May 2000 .......................... 73 (668) (595)
June 2000 ......................... 71 (647) (576)
July 2000 ......................... 73 (231) (158)
August 2000 ....................... 73 -- 73
September 2000 .................... 71 -- 71
October 2000 ...................... 73 -- 73
--------- --------- ---------
$ 1,194 $ (5,100) $ (3,906)
========= ========= =========
</TABLE>
-28-
<PAGE> 29
Subsequent to December 31, 1999, the Company entered into the following natural
gas swap arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1999:
<TABLE>
<CAPTION>
NYMEX - INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------ ---------------
<S> <C> <C>
April 2000........................................................ 8,900,000 $2.593
May 2000.......................................................... 3,410,000 2.737
June 2000......................................................... 3,300,000 2.737
July 2000......................................................... 3,410,000 2.741
August 2000....................................................... 3,410,000 2.741
September 2000.................................................... 2,100,000 2.696
October 2000...................................................... 2,170,000 2.696
</TABLE>
Subsequent to December 31, 1999, the Company entered into the following
crude oil swap arrangements designed to hedge a portion of the Company's
domestic crude oil production for periods after December 1999:
<TABLE>
<CAPTION>
MONTHLY NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (BBLS) (PER BBL)
- ------ --------- ------------
<S> <C> <C>
March 2000............................................................... 183,000 $27.512
April 2000............................................................... 89,000 27.251
</TABLE>
In addition to commodity hedging transactions related to the Company's oil
and gas production, CEMI periodically enters into various hedging transactions
designed to hedge against physical purchase and sale commitments made by CEMI.
Gains or losses on these transactions are recorded as adjustments to oil and gas
marketing sales in the consolidated statements of operations and are not
considered by management to be material.
INTEREST RATE RISK
The Company also utilizes hedging strategies to manage fixed-interest rate
exposure. Through the use of a swap arrangement, the Company believes it can
benefit from stable or falling interest rates and reduce its current interest
expense. During 1999, the Company's interest rate swap resulted in a $2.0
million reduction of interest expense. The terms of the swap agreement are as
follows:
<TABLE>
<CAPTION>
Months Notional Amount Fixed Rate Floating Rate
------ --------------- ---------- -------------
<S> <C> <C> <C>
May 1998 - April 2001 $230,000,000 7% Average of three-month Swiss Franc LIBOR,
Deutsche Mark and Australian Dollar
plus 300 basis points
May 2001 - April 2008 $230,000,000 7% U.S. three-month LIBOR plus 300 basis points
</TABLE>
If the floating rate is less than the fixed rate, the counterparty will pay the
Company accordingly. If the floating rate exceeds the fixed rate, the Company
will pay the counterparty.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the long-term debt
has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
--------------------------------------------------------------------------------------
YEARS OF MATURITY
--------------------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
-------- -------- -------- -------- ------- ----------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES: ($ IN MILLIONS)
Long-term debt, including current $ 0.8 $ 0.8 $ 0.6 $ -- $ 150.0 $ 770.0 $ 922.2 $ 838.7
portion - fixed rate....
Average interest rate...... 9.1% 9.1% 9.1% -- 7.9% 9.3% 9.1% --
Long-term debt - variable rate $ -- $ 43.5 $ -- $ -- $ -- $ -- $ 43.5 $ 43.5
Average interest rate...... -- 9.75% -- -- -- -- 9.75% --
</TABLE>
-29-
<PAGE> 30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Financial Statements:
Report of Independent Accountants for the Years Ended December 31, 1999 and 1998, for the Six Months
Ended December 31, 1997 and for the Year Ended June 30, 1997 .................................... 31
Consolidated Balance Sheets at December 31, 1999 and 1998 .......................................... 32
Consolidated Statements of Operations for the Years Ended December 31, 1999 and 1998, for the Six
Months Ended December 31, 1997 and for the Year Ended June 30, 1997 ............................. 33
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999 and 1998, for the Six
Months Ended December 31, 1997 and for the Year Ended June 30, 1997 ............................. 34
Consolidated Statements of Stockholders' Equity (Deficit) and Comprehensive Income (Loss) for the
Years Ended December 31, 1999 and 1998, for the Six Months Ended December 31, 1997 and for
the Year Ended June 30, 1997 .................................................................... 36
Notes to Consolidated Financial Statements ......................................................... 37
Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts .................................................... 69
</TABLE>
-30-
<PAGE> 31
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Chesapeake Energy Corporation and its subsidiaries (the "Company")
at December 31, 1999 and 1998, and the results of their operations and their
cash flows for the years ended December 31, 1999 and 1998, the six months ended
December 31, 1997, and the year ended June 30, 1997, in conformity with
accounting principles generally accepted in the United States. In addition, in
our opinion, the financial statement schedule listed in the accompanying index
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these financial statements in accordance
with auditing standards generally accepted in the United States, which require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.
PRICEWATERHOUSECOOPERS LLP
Oklahoma City, Oklahoma
March 24, 2000
-31-
<PAGE> 32
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1999 1998
------------ ------------
($ IN THOUSANDS)
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ......................................................... $ 38,658 $ 29,520
Restricted cash ................................................................... 192 5,754
Accounts receivable:
Oil and gas sales ............................................................... 17,045 13,835
Oil and gas marketing sales ..................................................... 18,199 19,636
Joint interest and other, net of allowances of $ 3,218,000
and $3,209,000, respectively ................................................ 11,247 27,373
Related parties ................................................................. 4,574 15,455
Inventory ......................................................................... 4,582 5,325
Other ............................................................................. 3,049 1,101
------------ ------------
Total Current Assets ....................................................... 97,546 117,999
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ................................................ 2,315,348 2,142,943
Unevaluated properties .......................................................... 40,008 52,687
Less: accumulated depreciation, depletion and
amortization .................................................................. (1,670,542) (1,574,282)
------------ ------------
684,814 621,348
Other property and equipment ...................................................... 67,712 79,718
Less: accumulated depreciation and amortization ................................... (33,429) (37,075)
------------ ------------
Total Property and Equipment ............................................... 719,097 663,991
------------ ------------
OTHER ASSETS ........................................................................ 33,890 30,625
------------ ------------
TOTAL ASSETS ........................................................................ $ 850,533 $ 812,615
============ ============
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt ............................ $ 763 $ 25,000
Accounts payable .................................................................. 24,822 36,854
Accrued liabilities and other ..................................................... 34,713 46,572
Revenues and royalties due others ................................................. 27,888 22,858
------------ ------------
Total Current Liabilities .................................................. 88,186 131,284
------------ ------------
LONG-TERM DEBT, NET ................................................................. 964,097 919,076
------------ ------------
REVENUES AND ROYALTIES DUE OTHERS ................................................... 9,310 10,823
------------ ------------
DEFERRED INCOME TAXES ............................................................... 6,484 --
------------ ------------
CONTINGENCIES AND COMMITMENTS (NOTE 4)
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Stock, $.01 par value, 10,000,000 shares authorized; 4,596,400 and
4,600,000 shares of 7% cumulative convertible stock issued and outstanding
at December 31, 1999 and 1998, respectively,
entitled in liquidation to $229.8 million and 230.0 million, respectively ....... 229,820 230,000
Common Stock, par value of $.01, 250,000,000 shares authorized;
105,858,580 and 105,213,750 shares issued
at December 31, 1999 and 1998, respectively ..................................... 1,059 1,052
Paid-in capital ................................................................... 682,905 682,263
Accumulated earnings (deficit) .................................................... (1,093,929) (1,127,195)
Accumulated other comprehensive income (loss) ..................................... 196 (4,726)
Less: treasury stock, at cost; 10,856,185 and 8,503,300 common
shares at December 31, 1999 and 1998, respectively .............................. (37,595) (29,962)
------------ ------------
Total Stockholders' Equity (Deficit) ....................................... (217,544) (248,568)
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) ................................ $ 850,533 $ 812,615
============ ============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-32-
<PAGE> 33
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
---------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
------------ ------------ ------------ ------------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales .................................................. $ 280,445 $ 256,887 $ 95,657 $ 192,920
Oil and gas marketing sales ........................................ 74,501 121,059 58,241 76,172
------------ ------------ ------------ ------------
Total Revenues ................................................... 354,946 377,946 153,898 269,092
------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses ................................................ 46,298 51,202 7,560 11,445
Production taxes ................................................... 13,264 8,295 2,534 3,662
General and administrative ......................................... 13,477 19,918 5,847 8,802
Oil and gas marketing expenses ..................................... 71,533 119,008 58,227 75,140
Oil and gas depreciation, depletion and amortization ............... 95,044 146,644 60,408 103,264
Depreciation and amortization of other assets ...................... 7,810 8,076 2,414 3,782
Impairment of oil and gas properties ............................... -- 826,000 110,000 236,000
Impairment of other assets ......................................... -- 55,000 -- --
------------ ------------ ------------ ------------
Total Operating Costs ............................................ 247,426 1,234,143 246,990 442,095
------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS ........................................ 107,520 (856,197) (93,092) (173,003)
------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income .......................................... 8,562 3,926 78,966 11,223
Interest expense ................................................... (81,052) (68,249) (17,448) (18,550)
------------ ------------ ------------ ------------
(72,490) (64,323) 61,518 (7,327)
------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY
ITEM ............................................................... 35,030 (920,520) (31,574) (180,330)
PROVISION (BENEFIT) FOR INCOME TAXES ................................. 1,764 -- -- (3,573)
------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM .............................. 33,266 (920,520) (31,574) (176,757)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax of $0 and $3,804,000, respectively .. -- (13,334) -- (6,620)
------------ ------------ ------------ ------------
NET INCOME (LOSS) .................................................... 33,266 (933,854) (31,574) (183,377)
PREFERRED STOCK DIVIDENDS ............................................ (16,711) (12,077) -- --
------------ ------------ ------------ ------------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS ................... $ 16,555 $ (945,931) $ (31,574) $ (183,377)
============ ============ ============ ============
EARNINGS (LOSS) PER COMMON SHARE:
EARNINGS (LOSS) PER COMMON SHARE-BASIC:
Income (loss) before extraordinary item .......................... $ 0.17 $ (9.83) $ (0.45) $ (2.69)
Extraordinary item ............................................... -- (0.14) -- (0.10)
------------ ------------ ------------ ------------
Net income (loss) ................................................ $ 0.17 $ (9.97) $ (0.45) $ (2.79)
============ ============ ============ ============
EARNINGS (LOSS) PER COMMON SHARE-ASSUMING DILUTION:
Income (loss) before extraordinary item .......................... $ 0.16 $ (9.83) $ (0.45) $ (2.69)
Extraordinary item ............................................... -- (0.14) -- (0.10)
------------ ------------ ------------ ------------
Net income (loss) ................................................ $ 0.16 $ (9.97) $ (0.45) $ (2.79)
============ ============ ============ ============
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING (IN 000'S):
Basic ............................................................ 97,077 94,911 70,835 65,767
============ ============ ============ ============
Assuming dilution ................................................ 102,038 94,911 70,835 65,767
============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-33-
<PAGE> 34
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
------------------------ DECEMBER 31, JUNE 30,
1999 1998 1997 1997
---------- ---------- ---------- ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) .................................................... $ 33,266 $ (933,854) $ (31,574) $ (183,377)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO
CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization ........................... 99,516 152,204 62,028 105,591
Impairment of oil and gas assets ................................... -- 826,000 110,000 236,000
Impairment of other assets ......................................... -- 55,000 -- --
Deferred taxes ..................................................... 1,764 -- -- (3,573)
Amortization of loan costs ......................................... 3,338 2,516 794 1,455
Amortization of bond discount ...................................... 84 98 41 217
Bad debt expense ................................................... 9 1,589 40 299
Gain on sale of Bayard stock ....................................... -- -- (73,840) --
Gain on sale of fixed assets ....................................... (459) (90) (209) (1,593)
Extraordinary loss ................................................. -- 13,334 -- 6,620
Equity in (earnings) losses from investments and other ............. 1,209 703 592 (499)
---------- ---------- ---------- ----------
Cash provided by operating activities before changes in current
assets and liabilities ........................................... 138,727 117,500 67,872 161,140
---------- ---------- ---------- ----------
CHANGES IN ASSETS AND LIABILITIES:
(Increase) decrease in short-term investments ...................... -- 12,027 92,127 (102,858)
(Increase) decrease in accounts receivable ......................... 17,592 12,191 (7,173) (19,987)
(Increase) decrease in inventory ................................... 743 168 (1,584) (1,467)
(Increase) decrease in other current assets ........................ 3,614 7,637 (1,519) 1,466
Increase (decrease) in accounts payable, accrued
liabilities and other ............................................ (23,891) (46,785) (11,044) 48,085
Increase (decrease) in current and non-current revenues
and royalties due others ......................................... 3,517 (8,099) 478 (2,290)
Increase (decrease) in deferred income taxes ....................... 4,720 -- -- --
---------- ---------- ---------- ----------
Changes in assets and liabilities ................................ 6,295 (22,861) 71,285 (77,051)
---------- ---------- ---------- ----------
Cash provided by operating activities ............................ 145,022 94,639 139,157 84,089
---------- ---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties .............. (153,268) (259,710) (187,252) (465,367)
Acquisitions of oil and gas companies and properties, net of
cash acquired .................................................... (49,893) (279,924) -- --
Divestitures of oil and gas properties ............................. 45,635 15,712 -- --
Investment in preferred stock of Gothic Energy Corporation ......... -- (39,500) -- --
Net proceeds from sale of Bayard stock ............................. -- -- 90,380 --
Repayment of note receivable ....................................... -- 2,000 18,000 --
Proceeds from sale of investment in PanEast ........................ -- 21,245 -- --
Other proceeds from sales .......................................... 5,530 3,600 17 6,428
Long-term loans made to third parties .............................. -- -- -- (20,000)
Investment in oil field service company ............................ -- -- (200) (3,048)
Increase in deferred charges ....................................... (5,865) -- -- --
Other investments .................................................. (730) -- (30,434) (8,000)
Other property and equipment additions ............................. (1,182) (11,473) (27,015) (33,867)
---------- ---------- ---------- ----------
Cash used in investing activities ................................ (159,773) (548,050) (136,504) (523,854)
---------- ---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock ............................. -- -- -- 288,091
Proceeds from long-term borrowings ................................. 116,500 658,750 -- 342,626
Payments on long-term borrowings ................................... (98,000) (474,166) -- (119,581)
Dividends paid on common stock ..................................... -- (5,592) (2,810) --
Dividends paid on preferred stock .................................. -- (8,050) -- --
Proceeds from issuance of preferred stock .......................... -- 222,663 -- --
Purchase of treasury stock and preferred stock ..................... (53) (29,962) -- --
Cash received from exercise of stock options ....................... 520 154 322 1,387
Other financing .................................................... -- -- (322) (379)
---------- ---------- ---------- ----------
Cash provided by (used in) financing activities .................. 18,967 363,797 (2,810) 512,144
---------- ---------- ---------- ----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH .............................. 4,922 (4,726) -- --
---------- ---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents ................. 9,138 (94,340) (157) 72,379
Cash and cash equivalents, beginning of period ....................... 29,520 123,860 124,017 51,638
---------- ---------- ---------- ----------
Cash and cash equivalents, end of period ............................. $ 38,658 $ 29,520 $ 123,860 $ 124,017
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-34-
<PAGE> 35
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
----------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
---------- ---------- ---------- ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAYMENTS FOR:
Interest, net of capitalized interest .................... $ 80,684 $ 59,881 $ 17,367 $ 12,919
Income taxes ............................................. $ -- $ -- $ 500 $ --
DETAILS OF ACQUISITION OF ANSON PRODUCTION CORPORATION:
Fair value of assets acquired ............................ $ -- $ -- $ 43,000 $ --
Accrued liability for estimated cash consideration ....... $ -- $ -- $ (15,500) $ --
Stock issued (3,792,724 shares) .......................... $ -- $ -- $ (27,500) $ --
DETAILS OF ACQUISITION OF DLB OIL & GAS, INC.:
Fair value of assets acquired ............................ $ -- $ 136,500 $ -- $ --
Cash consideration ....................................... $ -- $ (17,500) $ -- $ --
Stock issued (5,000,000 shares) .......................... $ -- $ (30,000) $ -- $ --
Debt assumed ............................................. $ -- $ (85,000) $ -- $ --
Acquisition costs paid ................................... $ -- $ (4,000) $ -- $ --
DETAILS OF ACQUISITION OF HUGOTON ENERGY CORPORATION:
Fair value of assets acquired ............................ $ -- $ 343,371 $ -- $ --
Stock options granted .................................... $ -- $ (2,050) $ -- $ --
Stock issued (25,790,146 shares) ......................... $ -- $ (206,321) $ -- $ --
Debt assumed ............................................. $ -- $ (120,000) $ -- $ --
Acquisition costs paid ................................... $ -- $ (15,000) $ -- $ --
</TABLE>
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
In November 1999, the Chief Executive Officer and Chief Operating Officer of
Chesapeake tendered to Chesapeake Energy Marketing, Inc. ("CEMI") 2,320,107
shares of Chesapeake common stock in full satisfaction of two notes payable to
CEMI with a combined outstanding balance of $7.6 million.
During 1999, the Company issued a $2.2 million note payable as consideration
for the acquisition of certain oil and gas properties.
The Company had a financing arrangement with a vendor to supply certain oil
and gas equipment inventory, which was terminated during the Transition Period.
The total amount owed at June 30, 1997 was $1,380,000. No cash consideration is
exchanged for inventory under this financing arrangement until actual draws on
the inventory are made.
In fiscal 1997, the Company recognized income tax benefits of $4,808,000
related to the disposition of stock options by directors and employees of the
Company. The tax benefits were recorded as an adjustment to deferred income
taxes and paid-in capital.
Proceeds from the issuance of $500 million of 9.625% senior notes in April
1998 and $300 million of senior notes ($150 million of 7.875% senior notes and
$150 million of 8.5% senior notes) in March 1997, are net of $11.7 million and
$6.4 million, respectively, in offering fees and expenses which were deducted
from the actual cash received.
On December 22, 1997, the Company declared a dividend of $0.02 per common
share, or $1,486,000, which was paid on January 15, 1998. On June 13, 1997 the
Company declared a dividend of $0.02 per common share, or $1,405,000, which was
paid on July 15, 1997.
The accompanying notes are an integral part of these
consolidated financial statements.
-35-
<PAGE> 36
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) AND
COMPREHENSIVE INCOME (LOSS)
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
-------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
------------ ------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
PREFERRED STOCK:
Balance, beginning of period ........................................ $ 230,000 $ -- $ -- $ --
Purchase of preferred stock ......................................... (180) -- -- --
Issuance of preferred stock ......................................... -- 230,000 -- --
------------ ------------ ------------ ------------
Balance, end of period .............................................. 229,820 230,000 -- --
------------ ------------ ------------ ------------
COMMON STOCK:
Balance, beginning of period ........................................ 1,052 743 703 3,008
Issuance of 8,972,000 shares of common stock ........................ -- -- -- 90
Exercise of stock options and warrants .............................. 6 -- 2 12
Issuance of 3,792,724 shares of common stock
to AnSon Production Corporation ................................... -- -- 38 --
Issuance of 25,790,146 shares of common stock to
Hugoton Energy Corporation ........................................ -- 258 -- --
Issuance of 5,000,000 shares of common stock to
DLB Oil and Gas, Inc. ............................................. -- 50 -- --
Change in par value and other ....................................... 1 1 -- (2,407)
------------ ------------ ------------ ------------
Balance, end of period .............................................. 1,059 1,052 743 703
------------ ------------ ------------ ------------
PAID-IN CAPITAL:
Balance, beginning of period ........................................ 682,263 460,770 432,991 136,782
Exercise of stock options and warrants .............................. 514 153 320 1,375
Issuance of common stock ............................................ -- 236,013 27,459 301,593
Offering expenses and other ......................................... 1 (16,723) -- (13,974)
Stock options issued in Hugoton purchase ............................ -- 2,050 -- --
Purchase of preferred stock at discount ............................. 127 -- -- --
Tax benefit from exercise of stock options .......................... -- -- -- 4,808
Change in par value ................................................. -- -- -- 2,407
------------ ------------ ------------ ------------
Balance, end of period .............................................. 682,905 682,263 460,770 432,991
------------ ------------ ------------ ------------
ACCUMULATED EARNINGS (DEFICIT):
Balance, beginning of period ........................................ (1,127,195) (181,270) (146,805) 37,977
Net income (loss) ................................................... 33,266 (933,854) (31,574) (183,377)
Dividends on common stock ........................................... -- (4,021) (2,891) (1,405)
Dividends on preferred stock ........................................ -- (8,050) -- --
------------ ------------ ------------ ------------
Balance, end of period .............................................. (1,093,929) (1,127,195) (181,270) (146,805)
------------ ------------ ------------ ------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period ........................................ (4,726) (37) -- --
Foreign currency translation adjustments ............................ 4,922 (4,689) (37) --
------------ ------------ ------------ ------------
Balance, end of period .............................................. 196 (4,726) (37) --
------------ ------------ ------------ ------------
TREASURY STOCK - COMMON:
Balance, beginning of period ........................................ (29,962) -- -- --
Exchange of notes receivable for common stock from related parties .. (7,633) (29,962) -- --
------------ ------------ ------------ ------------
Balance, end of period .............................................. (37,595) (29,962) -- --
------------ ------------ ------------ ------------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT) .................................. $ (217,544) $ (248,568) $ 280,206 $ 286,889
============ ============ ============ ============
COMPREHENSIVE INCOME (LOSS):
Net income (loss) ................................................... $ 33,266 $ (933,854) $ (31,574) $ (183,377)
Other comprehensive income (loss) - foreign currency translation
adjustments ......................................................... 4,922 (4,689) (37) --
------------ ------------ ------------ ------------
Comprehensive income (loss) ......................................... $ 38,188 $ (938,543) $ (31,611) $ (183,377)
============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-36-
<PAGE> 37
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Company
The Company is an oil and natural gas exploration and production company
engaged in the acquisition, exploration, and development of properties for the
production of crude oil and natural gas from underground reservoirs. The
Company's properties are located in Oklahoma, Texas, Arkansas, Louisiana,
Kansas, Montana, Colorado, North Dakota, New Mexico and British Columbia and
Saskatchewan, Canada.
These consolidated financial statements relate to the years ended December
31, 1999 ("1999"), December 31, 1998 ("1998") and June 30, 1997 ("fiscal 1997").
The Company changed its fiscal year end from June 30 to December 31 in 1997. The
Company's results of operations and cash flows for the six months ended December
31, 1997 (the "Transition Period") are also included in these consolidated
financial statements.
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy
Corporation include the accounts of its direct and indirect wholly-owned
subsidiaries (the "Company"). All significant intercompany accounts and
transactions have been eliminated. Investments in companies and partnerships
which give the Company significant influence, but not control, over the investee
are accounted for using the equity method.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates.
Cash Equivalents
For purposes of the consolidated financial statements, the Company considers
investments in all highly liquid debt instruments with maturities of three
months or less at date of purchase to be cash equivalents.
Investments in Securities
The Company invests in various equity securities and short-term debt
instruments including corporate bonds and auction preferreds, commercial paper
and government agency notes. The Company has classified all of its short-term
investments in equity and debt instruments as trading securities, which are
carried at fair value with unrealized holding gains and losses included in
earnings. Investments in equity securities and limited partnerships that do not
have readily determinable fair values are stated at cost and are included in
noncurrent other assets. In determining realized gains and losses, the cost of
securities sold is based on the average cost method.
Inventory
Inventory consists primarily of tubular goods and other lease and well
equipment which the Company plans to utilize in its ongoing exploration and
development activities and is carried at the lower of cost or market using the
specific identification method.
-37-
<PAGE> 38
Oil and Gas Properties
The Company follows the full-cost method of accounting under which all costs
associated with property acquisition, exploration and development activities are
capitalized. The Company capitalizes internal costs that can be directly
identified with its acquisition, exploration and development activities and does
not include any costs related to production, general corporate overhead or
similar activities (see Note 11). Capitalized costs are amortized on a composite
unit-of-production method based on proved oil and gas reserves. As of December
31, 1999, approximately 66% of the Company's proved reserve value (based on SEC
PV10%) was evaluated by independent petroleum engineers, with the balance
evaluated by the Company's engineers. In addition, the company's engineers
evaluate all properties quarterly. The average composite rates used for
depreciation, depletion and amortization were $0.71 ($0.73 in U.S. and $0.52 in
Canada) per equivalent Mcf in 1999, $1.13 ($1.17 in U.S. and $0.43 in Canada)
per equivalent Mcf in 1998, $1.57 per equivalent Mcf in the Transition Period
and $1.31 per equivalent Mcf in fiscal 1997. The Company did not have operations
in Canada prior to 1998.
Proceeds from the sale of properties are accounted for as reductions to
capitalized costs unless such sales involve a significant change in the
relationship between costs and the value of proved reserves or the underlying
value of unproved properties, in which case a gain or loss is recognized. The
costs of unproved properties are excluded from amortization until the properties
are evaluated. The Company reviews all of its unevaluated properties quarterly
to determine whether or not and to what extent proved reserves have been
assigned to the properties, and otherwise if impairment has occurred.
Unevaluated properties are grouped by major producing area where individual
property costs are not significant, and assessed individually when individual
costs are significant.
The Company reviews the carrying value of its oil and gas properties under
the full-cost accounting rules of the Securities and Exchange Commission on a
quarterly basis. Under these rules, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues less estimated
future expenditures to be incurred in developing and producing the proved
reserves, less any related income tax effects. During 1998, capitalized costs of
oil and gas properties exceeded the estimated present value of future net
revenues from the Company's proved reserves, net of related income tax
considerations, resulting in writedowns in the carrying value of oil and gas
properties of $826 million. During the Transition Period, capitalized costs of
oil and gas properties exceeded the estimated present value of future net
revenues from the Company's proved reserves, net of related income tax
considerations, resulting in a writedown in the carrying value of oil and gas
properties of $110 million. During fiscal 1997, capitalized costs of oil and gas
properties exceeded the estimated present value of future net revenues from the
Company's proved reserves, net of related income tax considerations, resulting
in a writedown in the carrying value of oil and gas properties of $236 million.
Other Property and Equipment
Other property and equipment consists primarily of gas gathering and
processing facilities, vehicles, land, office buildings and equipment, and
software. Major renewals and betterments are capitalized while the costs of
repairs and maintenance are charged to expense as incurred. The costs of assets
retired or otherwise disposed of and the applicable accumulated depreciation are
removed from the accounts, and the resulting gain or loss is reflected in
operations. Other property and equipment costs are depreciated on both
straight-line and accelerated methods. Buildings are depreciated on a
straight-line basis over 31.5 years. All other property and equipment are
depreciated over the estimated useful lives of the assets, which range from five
to seven years.
Capitalized Interest
During 1999, 1998, the Transition Period and fiscal 1997, interest of
approximately $3.5 million, $6.5 million, $5.1 million and $12.9 million,
respectively, was capitalized on significant investments in unproved properties
that were not being currently depreciated, depleted, or amortized and on which
exploration activities were in progress.
-38-
<PAGE> 39
Income Taxes
The Company has adopted Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires deferred tax
liabilities or assets to be recognized for the anticipated future tax effects of
temporary differences that arise as a result of the differences in the carrying
amounts and the tax bases of assets and liabilities.
Net Income (Loss) Per Share
Statement of Financial Accounting Standards No. 128, Earnings Per Share
("SFAS 128") requires presentation of "basic" and "diluted" earnings per share,
as defined, on the face of the statement of operations for all entities with
complex capital structures. SFAS 128 requires a reconciliation of the numerator
and denominator of the basic and diluted EPS computations. For 1998, the
Transition Period and fiscal 1997, there was no difference between actual
weighted average shares outstanding, which are used in computing basic EPS, and
diluted weighted average shares, which are used in computing diluted EPS.
Options to purchase 12.9 million, 11.3 million, 8.3 million and 7.9 million
shares of common stock at weighted average exercise prices of $1.76, $1.86,
$5.49 and $7.09 were outstanding during 1999, 1998, the Transition Period and
fiscal 1997 but were not included in the computation of diluted EPS because the
effect of these outstanding options would be antidilutive. A reconciliation for
1999 is as follows:
<TABLE>
<CAPTION>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ------
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999:
BASIC EPS
Income available to common stockholders....... $ 16,555 97,077 $ 0.17
=======
EFFECT OF DILUTIVE SECURITIES
Employee stock options........................ -- 4,961
-------- --------
DILUTED EPS
Income available to common stockholders
and assumed conversions.................... $ 16,555 102,038 $ 0.16
======== ======== =======
</TABLE>
Gas Imbalances -- Revenue Recognition
Revenues from the sale of oil and gas production are recognized when title
passes, net of royalties. The Company follows the "sales method" of accounting
for its gas revenue whereby the Company recognizes sales revenue on all gas sold
to its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A liability is recognized only to the
extent that the Company has a net imbalance in excess of the remaining gas
reserves on the underlying properties. The Company's net imbalance positions at
December 31, 1999 and 1998 were not material.
Hedging
The Company periodically uses certain instruments to hedge its exposure to
price fluctuations on oil and natural gas transactions and interest rates.
Recognized gains and losses on hedge contracts are reported as a component of
the related transaction. Results of oil and gas hedging transactions are
reflected in oil and gas sales to the extent related to the Company's oil and
gas production, in oil and gas marketing sales to the extent related to the
Company's marketing activities, and in interest expense to the extent so
related.
Debt Issue Costs
Included in other assets are costs associated with the issuance of the
senior notes. The remaining unamortized costs on these issuances of senior notes
at December 31, 1999 totaled $16.6 million and are being amortized over the life
of the senior notes.
-39-
<PAGE> 40
Comprehensive Income
In 1998, the Company adopted SFAS No. 130, Reporting Comprehensive Income.
This statement establishes rules for the reporting of comprehensive income and
its components. Comprehensive income consists of net income and foreign currency
translation adjustments and is presented in the Consolidated Statements of
Stockholders' Equity (Deficit) and Comprehensive Income (Loss). The adoption of
SFAS 130 had no impact on total stockholders' equity. Prior year financial
statements have been reclassified to conform to the SFAS 130 requirements. All
balance sheet accounts of foreign operations are translated into U.S. dollars at
the year-end rate of exchange and statement of operations items are translated
at the weighted average exchange rates for the year.
Reclassifications
Certain reclassifications have been made to the consolidated financial
statements for 1998, the Transition Period, and fiscal 1997 to conform to the
presentation used for the 1999 consolidated financial statements.
2. SENIOR NOTES
On April 22, 1998, the Company issued $500 million principal amount of
9.625% Senior Notes due 2005 ("9.625% Senior Notes"). The 9.625% Senior Notes
are redeemable at the option of the Company at any time on or after May 1, 2002
at the redemption prices set forth in the indenture or at the make-whole prices,
as set forth in the indenture, if redeemed prior to May 1, 2002. The Company may
also redeem at its option up to $167 million of the 9.625% Senior Notes at
109.625% of their principal amount with the proceeds of an equity offering
completed prior to May 1, 2001.
On March 17, 1997, the Company issued $150 million principal amount of
7.875% Senior Notes due 2004 ("7.875% Senior Notes"). The 7.875% Senior Notes
are redeemable at the option of the Company at any time prior to March 15, 2004
at the make-whole prices determined in accordance with the indenture.
Also on March 17, 1997, the Company issued $150 million principal amount of
8.5% Senior Notes due 2012 ("8.5% Senior Notes"). The 8.5% Senior Notes are
redeemable at the option of the Company at any time prior to March 15, 2004 at
the make-whole prices determined in accordance with the indenture and, on or
after March 15, 2004 at the redemption prices set forth therein.
On April 9, 1996, the Company issued $120 million principal amount of 9.125%
Senior Notes due 2006 ("9.125% Senior Notes"). The 9.125% Senior Notes are
redeemable at the option of the Company at any time prior to April 15, 2001 at
the make-whole prices determined in accordance with the indenture and, on or
after April 15, 2001 at the redemption prices set forth therein.
On May 25, 1995, the Company issued $90 million principal amount of 10.5%
Senior Notes due 2002 ("10.5% Senior Notes"). In April 1998, the Company
purchased all of its 10.5% Senior Notes for approximately $99 million. The early
retirement of these notes resulted in an extraordinary charge of $13.3 million.
The Company is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. The Company's
obligations under the 9.625% Senior Notes, the 9.125% Senior Notes, the 7.875%
Senior Notes and the 8.5% Senior Notes have been fully and unconditionally
guaranteed, on a joint and several basis, by each of the Company's "Restricted
Subsidiaries" (as defined in the respective indentures governing the Senior
Notes) (collectively, the "Guarantor Subsidiaries"). Each of the Guarantor
Subsidiaries is a direct or indirect wholly-owned subsidiary of the Company.
The senior note indentures contain certain covenants, including covenants
limiting the Company and the Guarantor Subsidiaries with respect to asset sales;
restricted payments; the incurrence of additional indebtedness and the issuance
of preferred stock; liens; sale and leaseback transactions; lines of business;
dividend and other payment restrictions affecting Guarantor Subsidiaries;
mergers or consolidations; and transactions with affiliates.
-40-
<PAGE> 41
The Company is obligated to repurchase the 9.625% and 9.125% Senior Notes in the
event of a change of control or certain asset sales.
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 $19.3 million related to its preferred stock as of
February 29, 2000. Subsequent payments will be subject to the same restrictions
and are dependent upon variables that are beyond the Company's ability to
predict. This restriction does not affect the Company's ability to borrow under
or expand its secured commercial bank facility. If the Company fails to pay
dividends for six quarterly periods, the holders of preferred stock will be
entitled to elect two new directors to the Board. Based on current projections
of cash flow and fixed charges, the Company does not expect to be able to pay a
dividend on the preferred stock on May 1, 2000, which would be the sixth
consecutive dividend payment date on which dividends have not been paid.
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, the Company's subsidiaries which are not guarantors of
the Senior Notes (the "Non-Guarantor Subsidiaries") and the Company. Separate
audited financial statements of each Guarantor Subsidiary have not been provided
because management has determined that they are not material to investors.
Chesapeake Energy Marketing, Inc. ("CEMI") was a Non-Guarantor Subsidiary
for all periods presented. The following were additional Non-Guarantor
Subsidiaries: Chesapeake Acquisition Corporation during the Transition Period
and Chesapeake Canada Corporation during fiscal 1997. All of the Company's other
subsidiaries were Guarantor Subsidiaries during all periods presented.
-41-
<PAGE> 42
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1999
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ............ $ (6,964) $ 20,409 $ 25,405 $ -- $ 38,850
Accounts receivable .................. 45,170 18,297 73 (12,475) 51,065
Inventory ............................ 4,183 399 -- -- 4,582
Other ................................ 1,997 700 352 -- 3,049
------------ ------------ ------------ ------------ ------------
Total Current Assets ......... 44,386 39,805 25,830 (12,475) 97,546
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ............... 2,311,633 3,715 -- -- 2,315,348
Unevaluated leasehold ................ 40,008 -- -- -- 40,008
Other property and equipment ......... 29,088 20,521 18,103 -- 67,712
Less: accumulated depreciation,
depletion and amortization ........ (1,683,890) (18,205) (1,876) -- (1,703,971)
------------ ------------ ------------ ------------ ------------
Net Property and Equipment ... 696,839 6,031 16,227 -- 719,097
------------ ------------ ------------ ------------ ------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES ................ 806,180 -- 493,738 (1,299,918) --
------------ ------------ ------------ ------------ ------------
OTHER ASSETS ........................... 16,402 8,409 16,765 (7,686) 33,890
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ........................... $ 1,563,807 $ 54,245 $ 552,560 $ (1,320,079) $ 850,533
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt ...... $ -- $ 763 $ -- $ -- $ 763
Accounts payable and other ........... 63,194 19,265 17,466 (12,502) 87,423
------------ ------------ ------------ ------------ ------------
Total Current Liabilities .... 63,194 20,028 17,466 (12,502) 88,186
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT ......................... 43,500 1,437 919,160 -- 964,097
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE
OTHERS ............................... 9,310 -- -- -- 9,310
------------ ------------ ------------ ------------ ------------
DEFERRED INCOME TAXES .................. 6,484 -- -- -- 6,484
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES .................. 1,356,466 (2,450) (1,354,043) 27 --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock ......................... 27 1 1,048 (17) 1,059
Other ................................ 84,826 35,229 968,929 (1,307,587) (218,603)
------------ ------------ ------------ ------------ ------------
84,853 35,230 969,977 (1,307,604) (217,544)
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY (DEFICIT) ..................... $ 1,563,807 $ 54,245 $ 552,560 $ (1,320,079) $ 850,533
============ ============ ============ ============ ============
</TABLE>
-42-
<PAGE> 43
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1998
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ................. $ (11,565) $ 7,000 $ 39,839 $ -- $ 35,274
Accounts receivable ....................... 54,384 29,641 270 (7,996) 76,299
Inventory ................................. 4,919 406 -- -- 5,325
Other ..................................... 721 15 365 -- 1,101
------------ ------------ ------------ ------------ ------------
Total Current Assets .............. 48,459 37,062 40,474 (7,996) 117,999
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties .................... 2,142,943 -- -- -- 2,142,943
Unevaluated leasehold ..................... 52,687 -- -- -- 52,687
Other property and equipment .............. 47,628 15,109 16,981 -- 79,718
Less: accumulated depreciation,
depletion and amortization ............. (1,601,931) (8,036) (1,390) -- (1,611,357)
------------ ------------ ------------ ------------ ------------
Net Property and Equipment ......... 641,327 7,073 15,591 -- 663,991
------------ ------------ ------------ ------------ ------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES ..................... 473,578 -- 481,150 (954,728) --
------------ ------------ ------------ ------------ ------------
OTHER ASSETS ................................ 10,610 560 19,455 -- 30,625
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ................................ $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt ........... $ 25,000 $ -- $ -- $ -- $ 25,000
Accounts payable and other ................ 80,786 15,992 17,529 (8,023) 106,284
------------ ------------ ------------ ------------ ------------
Total Current Liabilities ......... 105,786 15,992 17,529 (8,023) 131,284
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT .............................. -- -- 919,076 -- 919,076
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE
OTHERS .................................... 10,823 -- -- -- 10,823
------------ ------------ ------------ ------------ ------------
DEFERRED INCOME TAXES ....................... -- -- -- -- --
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES ....................... 1,338,948 11,376 (1,350,351) 27 --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock .............................. 26 1 1,042 (17) 1,052
Other ..................................... (281,609) 17,326 969,374 (954,711) (249,620)
------------ ------------ ------------ ------------ ------------
(281,583) 17,327 970,416 (954,728) (248,568)
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY (DEFICIT) .......................... $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615
============ ============ ============ ============ ============
</TABLE>
-43-
<PAGE> 44
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999:
REVENUES:
Oil and gas sales ...................................... $ 279,740 $ -- $ -- $ 705 $ 280,445
Oil and gas marketing sales ............................ -- 194,605 -- (120,104) 74,501
------------ ------------ ------------ ------------ ------------
Total Revenues ......................................... 279,740 194,605 -- (119,399) 354,946
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .......................... 59,158 404 -- -- 59,562
Oil and gas marketing expenses ......................... -- 190,932 -- (119,399) 71,533
Impairment of oil and gas properties ................... -- -- -- -- --
Impairment of other assets ............................. -- -- -- -- --
Oil and gas depreciation, depletion and amortization ... 94,649 395 -- -- 95,044
Other depreciation and amortization .................... 4,474 80 3,256 -- 7,810
General and administrative ............................. 12,143 1,251 83 -- 13,477
------------ ------------ ------------ ------------ ------------
Total Operating Costs .................................. 170,424 193,062 3,339 (119,399) 247,426
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS .......................... 109,316 1,543 (3,339) -- 107,520
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income .............................. 3,257 4,823 84,120 (83,638) 8,562
Interest expense ....................................... (82,852) (96) (81,742) 83,638 (81,052)
------------ ------------ ------------ ------------ ------------
(79,595) 4,727 2,378 -- (72,490)
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ................................... 29,721 6,270 (961) -- 35,030
INCOME TAX EXPENSE (BENEFIT) ........................... 1,764 -- -- -- 1,764
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ................................... 27,957 6,270 (961) -- 33,266
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax ....................... -- -- -- -- --
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) ...................................... $ 27,957 $ 6,270 $ (961) $ -- $ 33,266
============ ============ ============ ============ ============
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1998:
REVENUES:
Oil and gas sales ...................................... $ 254,541 $ -- $ -- $ 2,346 $ 256,887
Oil and gas marketing sales ............................ -- 225,195 -- (104,136) 121,059
------------ ------------ ------------ ------------ ------------
Total Revenues ......................................... 254,541 225,195 -- (101,790) 377,946
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .......................... 59,497 -- -- -- 59,497
Oil and gas marketing expenses ......................... -- 220,798 -- (101,790) 119,008
Impairment of oil and gas properties ................... 826,000 -- -- -- 826,000
Impairment of other assets ............................. 47,000 8,000 -- -- 55,000
Oil and gas depreciation, depletion and amortization ... 146,644 -- -- -- 146,644
Other depreciation and amortization .................... 5,204 126 2,746 -- 8,076
General and administrative ............................. 18,081 1,766 71 -- 19,918
------------ ------------ ------------ ------------ ------------
Total Operating Costs .................................. 1,102,426 230,690 2,817 (101,790) 1,234,143
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS .......................... (847,885) (5,495) (2,817) -- (856,197)
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income .............................. 649 2,259 100,886 (99,868) 3,926
Interest expense ....................................... (96,214) (382) (71,521) 99,868 (68,249)
------------ ------------ ------------ ------------ ------------
(95,565) 1,877 29,365 -- (64,323)
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ................................... (943,450) (3,618) 26,548 -- (920,520)
INCOME TAX EXPENSE (BENEFIT) ........................... -- -- -- -- --
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ................................... (943,450) (3,618) 26,548 -- (920,520)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax ....................... (2,164) -- (11,170) -- (13,334)
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) ...................................... $ (945,614) $ (3,618) $ 15,378 $ -- $ (933,854)
============ ============ ============ ============ ============
</TABLE>
-44-
<PAGE> 45
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE SIX MONTHS ENDED DECEMBER 31, 1997:
REVENUES:
Oil and gas sales ........................................ $ 93,384 $ 1,199 $ -- $ 1,074 $ 95,657
Oil and gas marketing sales .............................. -- 101,689 -- (43,448) 58,241
------------ ------------ ------------ ------------ ------------
Total Revenues ........................................... 93,384 102,888 -- (42,374) 153,898
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes ............................ 9,905 189 -- -- 10,094
Oil and gas marketing expenses ........................... -- 100,601 -- (42,374) 58,227
Impairment of oil and gas properties ..................... 96,000 14,000 -- -- 110,000
Oil and gas depreciation, depletion and amortization ..... 59,758 650 -- -- 60,408
Other depreciation and amortization ...................... 1,383 40 991 -- 2,414
General and administrative ............................... 4,598 1,132 117 -- 5,847
------------ ------------ ------------ ------------ ------------
Total Operating Costs .................................... 171,644 116,612 1,108 (42,374) 246,990
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS ............................ (78,260) (13,724) (1,108) -- (93,092)
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ................................ 515 192 110,751 (32,492) 78,966
Interest expense ......................................... (27,481) (39) (22,420) 32,492 (17,448)
------------ ------------ ------------ ------------ ------------
(26,966) 153 88,331 -- 61,518
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ..................................... (105,226) (13,571) 87,223 -- (31,574)
INCOME TAX EXPENSE (BENEFIT) ............................. -- -- -- -- --
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ..................................... (105,226) (13,571) 87,223 -- (31,574)
EXTRAORDINARY ITEM ....................................... -- -- -- -- --
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) ........................................ $ (105,226) $ (13,571) $ 87,223 $ -- $ (31,574)
============ ============ ============ ============ ============
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED JUNE 30, 1997:
REVENUES:
Oil and gas sales ........................................ $ 191,303 $ -- $ -- $ 1,617 $ 192,920
Oil and gas marketing sales .............................. -- 145,942 -- (69,770) 76,172
------------ ------------ ------------ ------------ ------------
Total Revenues ........................................... 191,303 145,942 -- (68,153) 269,092
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes ............................ 15,107 -- -- -- 15,107
Oil and gas marketing expenses ........................... -- 143,293 -- (68,153) 75,140
Impairment of oil and gas properties ..................... 236,000 -- -- -- 236,000
Oil and gas depreciation, depletion and amortization ..... 103,264 -- -- -- 103,264
Other depreciation and amortization ...................... 2,152 80 1,550 -- 3,782
General and administrative ............................... 6,313 921 1,568 -- 8,802
------------ ------------ ------------ ------------ ------------
Total Operating Costs .................................... 362,836 144,294 3,118 (68,153) 442,095
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS ............................ (171,533) 1,648 (3,118) -- (173,003)
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ................................ 778 749 49,224 (39,528) 11,223
Interest expense ......................................... (37,644) (10) (20,424) 39,528 (18,550)
------------ ------------ ------------ ------------ ------------
(36,866) 739 28,800 -- (7,327)
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ..................................... (208,399) 2,387 25,682 -- (180,330)
INCOME TAX EXPENSE (BENEFIT) ............................. (4,129) 47 509 -- (3,573)
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ..................................... (204,270) 2,340 25,173 -- (176,757)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of
applicable income tax ............................... (769) -- (5,851) -- (6,620)
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) ........................................ $ (205,039) $ 2,340 $ 19,322 $ -- $ (183,377)
============ ============ ============ ============ ============
</TABLE>
-45-
<PAGE> 46
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999:
CASH FLOWS FROM OPERATING ACTIVITIES .................. $ 135,303 $ 7,193 $ 2,526 $ -- $ 145,022
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net ......................... (159,888) 2,362 -- -- (157,526)
Proceeds from sale of assets ........................ 2,082 3,448 -- -- 5,530
Other investments ................................... (480) (250) -- -- (730)
Other additions ..................................... (5,777) (72) (1,198) -- (7,047)
------------ ------------ ------------ ------------ ------------
(164,063) 5,488 (1,198) -- (159,773)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings .................. 116,500 -- -- -- 116,500
Payments on long-term borrowings .................... (98,000) -- -- -- (98,000)
Cash paid for purchase of preferred stock ........... -- (53) -- -- (53)
Exercise of stock options ........................... -- -- 520 -- 520
Intercompany advances, net .......................... 15,501 781 (16,282) -- --
------------ ------------ ------------ ------------ ------------
34,001 728 (15,762) -- 18,967
------------ ------------ ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH ............................................. 4,922 -- -- -- 4,922
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash
Equivalents ......................................... 10,163 13,409 (14,434) -- 9,138
Cash, beginning of period ............................. (17,319) 7,000 39,839 -- 29,520
------------ ------------ ------------ ------------ ------------
Cash, end of period ................................... $ (7,156) $ 20,409 $ 25,405 $ -- $ 38,658
============ ============ ============ ============ ============
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1998:
CASH FLOWS FROM OPERATING ACTIVITIES .................. $ 66,960 $ (13,137) $ 40,816 $ -- $ 94,639
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties .............................. (523,922) -- -- -- (523,922)
Proceeds from sale of assets ........................ -- -- 3,600 -- 3,600
Investment in preferred stock of Gothic Energy
Corporation ...................................... (39,500) -- -- -- (39,500)
Repayment of note receivable ........................ 2,000 -- -- -- 2,000
Proceeds from sale of PanEast Petroleum Corporation . -- -- 21,245 -- 21,245
Other additions ..................................... (2,510) 8,408 (17,371) -- (11,473)
------------ ------------ ------------ ------------ ------------
(563,932) 8,408 7,474 -- (548,050)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings .................. -- -- 658,750 -- 658,750
Payments on long-term borrowings .................... -- -- (474,166) -- (474,166)
Cash received from issuance of preferred stock ...... -- -- 222,663 -- 222,663
Cash paid for purchase of treasury stock ............ -- -- (29,962) -- (29,962)
Dividends paid on common stock and preferred stock .. -- -- (13,642) -- (13,642)
Exercise of stock options ........................... -- -- 154 -- 154
Intercompany advances, net .......................... 476,663 6,035 (482,698) -- --
------------ ------------ ------------ ------------ ------------
476,663 6,035 (118,901) -- 363,797
------------ ------------ ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH ............................................. (4,726) -- -- -- (4,726)
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash
Equivalents ......................................... (25,035) 1,306 (70,611) -- (94,340)
Cash, beginning of period ............................. (284) 13,694 110,450 -- 123,860
------------ ------------ ------------ ------------ ------------
Cash, end of period ................................... $ (25,319) $ 15,000 $ 39,839 $ -- $ 29,520
============ ============ ============ ============ ============
</TABLE>
-46-
<PAGE> 47
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE SIX MONTHS ENDED DECEMBER 31, 1997:
CASH FLOWS FROM OPERATING ACTIVITIES .............. $ 28,598 $ (10,842) $ 121,401 $ -- $ 139,157
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties .......................... (187,252) -- -- -- (187,252)
Investment in service operations ................ (200) -- -- -- (200)
Other investments ............................... (26,472) -- 99,380 -- 72,908
Other additions ................................. (22,864) 1,357 (453) -- (21,960)
------------ ------------ ------------ ------------ ------------
(236,788) 1,357 98,927 -- (136,504)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid on common stock .................. -- -- (2,810) -- (2,810)
Exercise of stock options ....................... -- -- 322 -- 322
Other financing ................................. -- (322) -- -- (322)
Intercompany advances, net ...................... 214,135 19,443 (233,578) -- --
------------ ------------ ------------ ------------ ------------
214,135 19,121 (236,066) -- (2,810)
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash
Equivalents ..................................... 5,945 9,636 (15,738) -- (157)
Cash, beginning of period ......................... (6,534) 4,363 126,188 -- 124,017
------------ ------------ ------------ ------------ ------------
Cash, end of period ............................... $ (589) $ 13,999 $ 110,450 $ -- $ 123,860
============ ============ ============ ============ ============
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED JUNE 30, 1997:
CASH FLOWS FROM OPERATING ACTIVITIES .............. $ 165,850 $ (11,008) $ (70,753) $ -- $ 84,089
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties .......................... (465,424) 57 -- -- (465,367)
Proceeds from sale of assets .................... 6,428 -- -- -- 6,428
Investment in service operations ................ (3,048) -- -- -- (3,048)
Long-term loans to third parties ................ (2,000) -- (18,000) -- (20,000)
Other investments ............................... -- -- (8,000) -- (8,000)
Other additions ................................. (24,318) (1,999) (7,550) -- (33,867)
------------ ------------ ------------ ------------ ------------
(488,362) (1,942) (33,550) -- (523,854)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ........................ 50,000 -- 292,626 -- 342,626
Payments on borrowings .......................... (118,901) -- (680) -- (119,581)
Exercise of stock options ....................... -- -- 1,387 -- 1,387
Issuance of common stock ........................ -- -- 288,091 -- 288,091
Other financing ................................. -- -- (379) -- (379)
Intercompany advances, net ...................... 380,735 14,645 (395,380) -- --
------------ ------------ ------------ ------------ ------------
311,834 14,645 185,665 -- 512,144
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash
equivalents ..................................... (10,678) 1,695 81,362 -- 72,379
Cash, beginning of period ......................... 4,144 2,668 44,826 -- 51,638
------------ ------------ ------------ ------------ ------------
Cash, end of period ............................... $ (6,534) $ 4,363 $ 126,188 $ -- $ 124,017
============ ============ ============ ============ ============
</TABLE>
-47-
<PAGE> 48
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999:
Net income (loss) ............................... $ 27,957 $ 6,270 $ (961) $ -- $ 33,266
Other comprehensive income (loss) -
foreign currency translation .................. 4,922 -- -- -- 4,922
------------ ------------ ------------ ------------ ------------
Comprehensive income ............................ $ 32,879 $ 6,270 $ (961) $ -- $ 38,188
============ ============ ============ ============ ============
FOR THE YEAR ENDED DECEMBER 31, 1998:
Net income (loss) ............................... $ (945,614) $ (3,618) $ 15,378 $ -- $ (933,854)
Other comprehensive income (loss) -
foreign currency translation .................. (4,689) -- -- -- (4,689)
------------ ------------ ------------ ------------ ------------
Comprehensive income (loss) ..................... $ (950,303) $ (3,618) $ 15,378 $ -- $ (938,543)
============ ============ ============ ============ ============
FOR THE SIX MONTHS ENDED DECEMBER 31, 1997:
Net income (loss) ............................... $ (105,226) $ (13,571) $ 87,223 $ -- $ (31,574)
Other comprehensive income (loss) -
foreign currency translation .................. (37) -- -- -- (37)
------------ ------------ ------------ ------------ ------------
Comprehensive income (loss) ..................... $ (105,263) $ (13,571) $ 87,223 $ -- $ (31,611)
============ ============ ============ ============ ============
FOR THE YEAR ENDED JUNE 30, 1997:
Net income (loss) ............................... $ (205,039) $ 2,340 $ 19,322 $ -- $ (183,377)
Other comprehensive income (loss) -
foreign currency translation .................. -- -- -- -- --
------------ ------------ ------------ ------------ ------------
Comprehensive income (loss) ..................... $ (205,039) $ 2,340 $ 19,322 $ -- $ (183,377)
============ ============ ============ ============ ============
</TABLE>
-48-
<PAGE> 49
3. NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt consist of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1999 1998
------------ ------------
($ IN THOUSANDS)
<S> <C> <C>
7.875% Senior Notes (see Note 2) ...................... $ 150,000 $ 150,000
Discount on 7.875% Senior Notes ....................... (73) (90)
8.5% Senior Notes (see Note 2) ........................ 150,000 150,000
Discount on 8.5% Senior Notes ......................... (715) (774)
9.125% Senior Notes (see Note 2) ...................... 120,000 120,000
Discount on 9.125% Senior Notes ....................... (52) (60)
9.625% Senior Notes (see Note 2) ...................... 500,000 500,000
Note payable .......................................... 2,200 --
Other collateralized .................................. 43,500 25,000
------------ ------------
Total notes payable and long-term debt ................ 964,860 944,076
Less-- current maturities ............................. (763) (25,000)
------------ ------------
Notes payable and long-term debt, net of current
maturities ......................................... $ 964,097 $ 919,076
============ ============
</TABLE>
The aggregate scheduled maturities of notes payable and long-term debt for
the next five fiscal years ending December 31, 2004 and thereafter were as
follows as of December 31, 1999 (in thousands of dollars):
<TABLE>
<S> <C>
2000............................................... $ 763
2001............................................... 44,336
2002............................................... 601
2003............................................... --
2004............................................... 149,927
After 2004......................................... 769,233
---------
$ 964,860
=========
</TABLE>
4. CONTINGENCIES AND COMMITMENTS
Bayard Securities Litigation
A purported class action alleging violations of the Securities Act of 1933
and the Oklahoma Securities Act was first filed in February 1998 against the
Company and others on behalf of investors who purchased common stock of Bayard
Drilling Technologies, Inc. ("Bayard") in, or traceable to, its initial public
offering in November 1997. Total proceeds of the offering were $254 million, of
which the Company received net proceeds of $90 million as a selling shareholder.
Plaintiffs allege that the Company, a major customer of Bayard's drilling
services and the owner of 30.1% of Bayard's common stock outstanding prior to
the offering, was a controlling person of Bayard. 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 court dismissed plaintiffs' claims against the
Company under Section 15 of the Securities Act of 1933 alleging that the Company
was a "controlling person" of Bayard. Claims under Section 11 of the Securities
Act of 1933 and Section 408 of the Oklahoma Securities Act continue to be
asserted against the Company. 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
On September 21, 1999, judgment was entered in favor of the Company in a
patent infringement lawsuit tried to the U.S. District Court for the Northern
District of Texas, Fort Worth Division. Filed in October 1996, the lawsuit
asserted that the Company had infringed a patent belonging to Union Pacific
Resources Company. The court declared the patent invalid, held that the Company
could not have infringed the patent, dismissed all of UPRC's claims with
prejudice and assessed court costs against UPRC. Appeals of the judgment by both
the Company and UPRC are pending in the Federal Circuit Court of Appeals. The
Company has appealed the trial
-49-
<PAGE> 50
court's ruling denying the Company's request for attorneys' fees. Management is
unable to predict the outcome of these appeals but believes the invalidity of
the patent will be upheld on appeal.
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. The Company acquired MC Panhandle, Inc. on April 28, 1998. MC
Panhandle, Inc. has owned the leases since January 1, 1997, and 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.
Of the ten cases filed in the District Court of Moore County, Texas, 69th
Judicial District, three have been tried to a jury. Judgment has been entered
against CP and its co-defendants in all three cases, although there was a jury
verdict in two of the cases in favor of defendants. The Company's aggregate
liability for these judgments is $1.3 million of actual damages and $1.2 million
of exemplary damages and, jointly and severally with the other two defendants,
$1.5 million of actual damages and $337,000 of attorneys' fees in the event of
an appeal, sanctions, interest and court costs. The court also quieted title to
the leases in dispute in plaintiffs. CP and the other defendants have each
appealed the judgments and posted supersedeas bonds in two of these cases and
post-trial motions are pending in the other one. One of the other Moore County,
Texas cases has been set for trial in May 2000. There are three related cases
pending in other courts. One is set for trial in June 2000, and another, in the
U.S. District Court, Northern District of Texas, Amarillo Division, resulted in
a jury verdict for CP and its co-defendants. Judgment has not yet been entered
in this case.
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.
The Company is currently involved in various other routine disputes
incidental to its business operations. While it is not possible to determine the
ultimate disposition of these matters, management, after consultation with legal
counsel, is of the opinion that the final resolution of all such currently
pending or threatened litigation is not likely to have a material adverse effect
on the consolidated financial position or results of operations of the Company.
The Company has employment contracts with its two principal shareholders and
its chief financial officer and various other senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for varying terms
in the event of termination of employment without cause. These agreements expire
at various times from June 30, 2000 through June 30, 2003.
Due to the nature of the oil and gas business, the Company and its
subsidiaries are exposed to possible environmental risks. The Company has
implemented various policies and procedures to avoid environmental contamination
and risks from environmental contamination. The Company is not aware of any
potential material environmental issues or claims.
5. INCOME TAXES
The components of the income tax provision (benefit) for each of the periods
are as follows:
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<PAGE> 51
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
--------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
--------- --------- --------- -------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Current............................ $ -- $ -- $ -- $ --
Deferred........................... 1,764 -- -- (3,573)
--------- --------- --------- -------
Total.................... $ 1,764 $ -- $ -- $(3,573)
========= ========= ========= =======
</TABLE>
The effective income tax expense (benefit) differed from the computed
"expected" federal income tax expense (benefit) on earnings before income taxes
for the following reasons:
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
---------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
--------- --------- -------- --------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Computed "expected" income tax
provision (benefit).................... $ 12,720 $(322,182) $(11,051) $(63,116)
Tax percentage depletion................. (240) (430) (48) (294)
Change in valuation allowance............ (10,956) 380,969 13,818 64,116
State income taxes and other............. 240 (58,357) (2,719) (4,279)
--------- --------- -------- --------
$ 1,764 $ -- $ -- $ (3,573)
========= ========= ======== ========
</TABLE>
Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The tax
effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
------------------------------
1999 1998
------------ ------------
($ IN THOUSANDS)
<S> <C> <C>
Deferred tax liabilities:
Acquisition, exploration and development
costs and related depreciation, depletion and
amortization ........................................ $ (13,251) $ --
------------ ------------
Deferred tax assets:
Acquisition, exploration and development
costs and related depreciation, depletion and
amortization ........................................ 218,728 242,765
Net operating loss carryforwards ...................... 228,279 214,602
Percentage depletion carryforward ..................... 1,776 1,536
------------ ------------
448,783 458,903
------------ ------------
Net deferred tax asset (liability) .................... 435,532 458,903
Less: Valuation allowance ............................. (442,016) (458,903)
------------ ------------
Total deferred tax asset (liability) .................. $ (6,484) $ --
============ ============
</TABLE>
SFAS 109 requires that the Company record a valuation allowance when it is
more likely than not that some portion or all of the deferred tax assets will
not be realized. In 1998, the Company recorded an $826 million writedown related
to the impairment of oil and gas properties. The writedown and significant tax
net operating loss carryforwards (caused primarily by expensing intangible
drilling costs for tax purposes) resulted in a net deferred tax asset at
December 31, 1999 and 1998. The Company expects to generate future U.S. tax net
operating losses for the foreseeable future. Management has determined that it
is more likely than not that the net U.S. deferred tax assets will not be
realized and has recorded a valuation allowance equal to the net U.S. deferred
tax asset.
At December 31, 1998, $5.7 million of the valuation allowance was related to
the Company's Canadian deferred tax assets. During 1999, this valuation
allowance was eliminated as part of a purchase price reallocation related to a
1999 acquisition.
At December 31, 1999, the Company had a U.S. regular tax net operating loss
carryforward of approximately $613 million and a U.S. alternative minimum tax
net operating loss carryforward of approximately $267 million. The U.S. loss
carryforward amounts will expire during the years 2007 through 2019. The Company
also had a U.S. percentage depletion carryforward of approximately $5 million at
December 31, 1999, which is available to offset future U.S. federal income taxes
payable and has no expiration date.
In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") would place an annual limitation on
the Company's ability to utilize its existing tax carryforwards. Under
regulations issued by the
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<PAGE> 52
Internal Revenue Service, the Company has had two Ownership Changes. However,
these ownership changes have not resulted in a significant limitation of the tax
carryforwards.
6. RELATED PARTY TRANSACTIONS
Certain directors, shareholders and employees of the Company have acquired
working interests in certain of the Company's oil and gas properties. The owners
of such working interests are required to pay their proportionate share of all
costs. As of December 31, 1999 and 1998, the Company had accounts receivable
from related parties, primarily related to such participation, of $4.6 million
and $5.6 million, respectively.
As of December 31, 1998, the Chief Executive Officer and Chief Operating
Officer of the Company had notes payable to CEMI in the principal amount of $9.9
million. In November 1999, the Chief Executive Officer and the Chief Operating
Officer tendered to CEMI 2,320,107 shares of Chesapeake common stock in full
satisfaction of the notes payable to CEMI with a combined outstanding balance of
$7.6 million. The common stock was valued at $3.29 per share, which was the
market value of the stock at the time of the transaction.
During 1999, 1998, the Transition Period and fiscal 1997, the Company
incurred legal expenses of $398,000, $493,000, $388,000 and $207,000,
respectively, for legal services provided by a law firm of which a director is a
member.
7. EMPLOYEE BENEFIT PLANS
The Company maintains the Chesapeake Energy Corporation Savings and
Incentive Stock Bonus Plan, a 401(k) profit sharing plan. Eligible employees may
make voluntary contributions to the plan which are matched by the Company for up
to 10% of the employee's annual salary with the Company's common stock purchased
in the open-market. The amount of employee contribution is limited as specified
in the plan. The Company may, at its discretion, make additional contributions
to the plan. The Company contributed $1,163,000, $1,359,000, $418,000 and
$603,000 to the plan during 1999, 1998, the Transition Period and fiscal 1997,
respectively.
8. MAJOR CUSTOMERS AND SEGMENT INFORMATION
Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:
<TABLE>
<CAPTION>
PERCENT OF
YEAR ENDED DECEMBER 31, AMOUNT OIL AND GAS SALES
- ----------------------------------------------- ---------------- -----------------
($ IN THOUSANDS)
<S> <C> <C>
1999 Aquila Southwest Pipeline Corporation $31,505 11%
1998 Koch Oil Company $30,564 12%
Aquila Southwest Pipeline Corporation 28,946 11
SIX MONTHS ENDED DECEMBER 31,
- -----------------------------------------------
1997 Aquila Southwest Pipeline Corporation $20,138 21%
Koch Oil Company 18,594 19
GPM Gas Corporation 12,610 13
FISCAL YEAR ENDED JUNE 30,
- -----------------------------------------------
1997 Aquila Southwest Pipeline Corporation $53,885 28%
Koch Oil Company 29,580 15
GPM Gas Corporation 27,682 14
</TABLE>
Management believes that the loss of any of the above customers would not
have a material impact on the Company's results of operations or its financial
position.
The Company believes all of its material operations are part of the oil and
gas industry, and therefore reports as a single industry segment. Beginning in
1998, the Company began foreign operations in Canada. The geographic
-52-
<PAGE> 53
distribution of the Company's revenue, operating income and identifiable assets
are summarized below ($ in thousands):
<TABLE>
<CAPTION>
UNITED
STATES CANADA CONSOLIDATED
--------- --------- ------------
<S> <C> <C> <C>
1999:
Revenue......................... $ 340,969 $ 13,977 $ 354,946
Operating income (loss)......... 103,188 4,332 107,520
Identifiable assets............. 735,320 115,213 850,533
1998:
Revenue......................... $ 369,968 $ 7,978 $ 377,946
Operating income (loss)......... (842,798) (13,399) (856,197)
Identifiable assets............. 724,713 87,902 812,615
</TABLE>
9. STOCKHOLDERS' EQUITY AND STOCK BASED COMPENSATION
In November 1999, the Chief Executive Officer and the Chief Operating
Officer of Chesapeake tendered to CEMI 2,320,107 shares of Chesapeake common
stock in full satisfaction of two notes payable to CEMI with a combined
outstanding balance of $7.6 million. See Note 6.
During 1998, the Company's Board of Directors approved the expenditure of up
to $30 million to purchase outstanding Company common stock. As of August 25,
1998, the Company had purchased approximately 8.5 million shares of common stock
for an aggregate amount of $30 million pursuant to such authorization.
On April 28, 1998, the Company acquired by merger the Mid-Continent
operations of DLB Oil & Gas, Inc. ("DLB") for $17.5 million in cash, 5 million
shares of the Company's common stock, and the assumption of $90 million in
outstanding debt and working capital obligations.
On April 22, 1998, the Company issued $230 million (4.6 million shares) of
its 7% Cumulative Convertible Preferred Stock, $50 per share liquidation
preference, resulting in net proceeds to the Company of $223 million.
On March 10, 1998, the Company acquired Hugoton Energy Corporation
("Hugoton") pursuant to a merger by issuing approximately 25.8 million shares of
the Company's common stock in exchange for 100% of Hugoton's common stock.
On December 16, 1997, the Company acquired AnSon Production Corporation.
Consideration for this merger was approximately $43 million consisting of the
issuance of approximately 3.8 million shares of Company common stock and cash
consideration in accordance with the terms of the merger agreement.
On December 2, 1996, the Company completed a public offering of
approximately 9.0 million shares of common stock at a price of $33.63 per share,
resulting in net proceeds to the Company of approximately $288.1 million.
A 2-for-1 stock split of the common stock in December 1996 has been given
retroactive effect in these financial statements.
Stock Option Plans
The Company's 1992 Incentive Stock Option Plan (the "ISO Plan") terminated
on December 16, 1994. Until then, the Company granted incentive stock options to
purchase common stock under the ISO Plan to employees. Subject to any adjustment
as provided by the ISO Plan, the aggregate number of shares which may be issued
and sold may not exceed 3,762,000 shares. The maximum period for exercise of an
option may not be more than 10 years (or five years for an optionee who owns
more than 10% of the common stock) from the date of grant, and the exercise
price may not be less than the fair market value of the shares underlying the
options on the date of grant
-53-
<PAGE> 54
(or 110% of such value for an optionee who owns more than 10% of the common
stock). Options granted become exercisable at dates determined by the Stock
Option Committee of the Board of Directors.
Under the Company's 1992 Nonstatutory Stock Option Plan (the "NSO Plan"),
non-qualified options to purchase common stock may be granted only to directors
and consultants of the Company. Subject to any adjustment as provided by the NSO
Plan, the aggregate number of shares which may be issued and sold may not exceed
3,132,000 shares. The maximum period for exercise of an option may not be more
than 10 years from the date of grant, and the exercise price may not be less
than the fair market value of the shares underlying the options on the date of
grant. Options granted become exercisable at dates determined by the Stock
Option Committee of the Board of Directors. The NSO Plan also contains a formula
award provision pursuant to which each director who is not an executive officer
receives every quarter a ten-year immediately exercisable option to purchase
6,250 shares of common stock at an option price equal to the fair market value
of the shares on the date of grant. The amount of the award was changed
increased from 20,000 shares (post-split) to 15,000 shares per year in 1998 and
to 25,000 shares per year in 1999. No options can be granted under the NSO Plan
after December 10, 2002.
Under the Company's 1994 Stock Option Plan (the "1994 Plan"), and its 1996
Stock Option Plan (the "1996 Plan"), incentive and nonqualified stock options to
purchase Common Stock may be granted to employees and consultants of the Company
and its subsidiaries. Subject to any adjustment as provided by the respective
plans, the aggregate number of shares which may be issued and sold may not
exceed 4,886,910 shares under the 1994 Plan and 6,000,000 shares under the 1996
Plan. The maximum period for exercise of an option may not be more than 10 years
from the date of grant and the exercise price of nonqualified stock options may
not be less than par value and, under the 1996 Plan, 85% of the fair market
value of the shares underlying the options on the date of grant. Options granted
become exercisable at dates determined by the Stock Option Committee of the
Board of Directors. No options can be granted under the 1994 Plan after October
17, 2004 or under the 1996 Plan after October 14, 2006.
Under the Company's 1999 Stock Option Plan (the "1999 Plan"), nonqualified
stock options to purchase Common Stock may be granted to employees and
consultants of the Company and its subsidiaries. Subject to any adjustment as
provided by the plan, the aggregate number of shares which may be issued and
sold may not exceed 3,000,000 shares. The maximum period for exercise of an
option may not be more than 10 years from the date of grant and the exercise
price may not be less than the fair market value of the shares underlying the
options on the date of grant; provided, however, nonqualified stock options not
exceeding 10% of the options issuable under the 1999 Plan may be granted at an
exercise price which is not less than 85% of the grant date fair market value.
Options granted become exercisable at dates determined by the Stock Option
Committee of the Board of Directors. No options can be granted under the 1999
Plan after March 4, 2009.
The Company has elected to follow APB No. 25, Accounting for Stock Issued to
Employees and related interpretations in accounting for its employee stock
options. Under APB No. 25, compensation expense is recognized for the difference
between the option price and market value on the measurement date. No
compensation expense has been recognized because the exercise price of the stock
options granted under the plans equaled the market price of the underlying stock
on the date of grant.
Pro forma information regarding net income and earnings per share is
required by SFAS No. 123 and has been determined as if the Company had accounted
for its employee stock options under the fair value method of the statement. The
fair value for these options was estimated at the date of grant using a
Black-Scholes option pricing model with the following weighted-average
assumptions for 1999, 1998, the Transition Period and fiscal 1997, respectively:
interest rates (zero-coupon U.S. government issues with a remaining life equal
to the expected term of the options) of 5.88%, 5.20%, 6.45% and 6.74%; dividend
yields of 0.0%, 0.0%, 0.9% and 0.9%; volatility factors of the expected market
price of the Company's common stock of .82, .96, .67 and .60; and
weighted-average expected life of the options of five years.
The Black-Scholes option valuation model was developed for use in estimating
the fair value of traded options which have no vesting restrictions and are
fully transferable. In addition, option valuation models require the input of
highly subjective assumptions including the expected stock price volatility.
Because the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion the existing models do not necessarily provide a reliable single measure
of the fair value of its employee stock options.
-54-
<PAGE> 55
The Company's pro forma information follows:
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
----------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
------------- ------------- ----------------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Net Income (Loss)
As reported............................ $ 33,266 $ (933,854) $ (31,574) $(183,377)
Pro forma.............................. 24,802 (948,014) (35,084) (190,160)
Basic Earnings (Loss) per Share
As reported............................ $ 0.17 $ (9.97) $ (0.45) $ (2.79)
Pro forma.............................. 0.08 (10.12) (0.50) (2.89)
Diluted Earnings (Loss) per Share
As reported............................ $ 0.16 $ (9.97) $ (0.45) $ (2.79)
Pro forma.............................. 0.08 (10.12) (0.50) (2.89)
</TABLE>
For purposes of the pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period, which is four
years. Because the Company's stock options vest over four years and additional
awards are typically made each year, the above pro forma disclosures are not
likely to be representative of the effects on pro forma net income for future
years. A summary of the Company's stock option activity and related information
follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------- SIX MONTHS ENDED DECEMBER 31,
1999 1998 1997
-------------------------- -------------------------- ---------------------------
WEIGHTED-AVG WEIGHTED-AVG WEIGHTED-AVG
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
----------- -------------- --------- -------------- ---------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding Beginning of Period........ 11,260,375 $ 1.86 8,330,381 $ 5.49 7,903,659 $ 7.09
Granted................................ 3,210,493 1.11 14,580,063 2.78 3,362,207 8.29
Exercised.............................. (622,120) 0.99 (108,761) 1.35 (219,349) 3.13
Cancelled/Forfeited.................... (990,319) 1.87 (11,541,308) 5.64 (2,716,136) 13.87
---------- -------- ----------- ------- ---------- -------
Outstanding End of Period.............. 12,858,429 $ 1.76 11,260,375 $ 1.86 8,330,381 $ 5.49
---------- -------- ----------- ------- ---------- -------
Exercisable End of Period.............. 5,040,302 3,535,126 3,838,869
---------- ----------- ----------
Shares Authorized for Future Grants ... 2,560,687 1,761,359 4,585,973
---------- ----------- ----------
Fair Value of Options Granted During
the Period........................... $ 0.77 $ 2.34 $ 4.98
-------- ------- -------
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
1997
-------------------------------
WEIGHTED-AVG
OPTIONS EXERCISE PRICE
------------ --------------
<S> <C> <C>
Outstanding Beginning of Year .......... 7,602,884 $ 4.66
Granted ................................ 3,564,884 19.35
Exercised .............................. (1,197,998) 1.95
Cancelled/Forfeited .................... (2,066,111) 22.26
------------ ------------
Outstanding End of Year ................ 7,903,659 $ 7.09
------------ ------------
Exercisable End of Year ................ 3,323,824
------------
Shares Authorized for Future Grants .... 5,212,056
------------
Fair Value of Options Granted During
the Year ............................. $ 7.51
------------
</TABLE>
The following table summarizes information about stock options outstanding
at December 31, 1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------------------------- ------------------------------
NUMBER WEIGHTED-AVG. NUMBER
RANGE OF OUTSTANDING REMAINING WEIGHTED-AVG. EXERCISABLE WEIGHTED-AVG.
EXERCISE PRICES @ 12/31/99 CONTRACTUAL LIFE EXERCISE PRICE @ 12/31/99 EXERCISE PRICE
--------------- ------------ ------------------ -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
$ 0.08 - $ 0.78 897,982 4.02 $ 0.62 897,982 $ 0.62
$ 0.94 - $ 0.94 2,538,000 9.04 0.94 42,500 0.94
$ 1.00 - $ 1.00 31,250 9.01 1.00 31,250 1.00
$ 1.13 - $ 1.13 6,679,130 8.68 1.13 1,627,898 1.13
$ 1.33 - $ 2.25 1,320,204 4.34 2.00 1,320,204 2.00
$ 2.38 - $10.69 1,263,300 6.74 4.75 1,005,405 4.97
$14.25 - $14.25 27,000 7.32 14.25 13,500 14.25
$17.67 - $17.67 938 0.08 17.67 938 17.67
$25.88 - $25.88 625 0.08 25.88 625 25.88
$30.63 - $30.63 100,000 6.77 30.63 100,000 30.63
---------- ---- -------- ---------- --------
$ 0.08 - $30.63 12,858,429 7.77 $ 1.76 5,040,302 $ 2.66
========== ==========
</TABLE>
The exercise of certain stock options results in state and federal income
tax benefits to the Company related to the difference between the market price
of the common stock at the date of disposition and the option price. During
fiscal 1997, $4,808,000 was recorded as an adjustment to additional paid-in
capital and deferred income
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<PAGE> 56
taxes with respect to such tax benefits. During 1999, 1998 and the Transition
Period, the Company did not recognize any such tax benefits.
10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company has only limited involvement with derivative financial
instruments, as defined in Statement of Financial Accounting Standards No. 119
"Disclosure About Derivative Financial Instruments and Fair Value of Financial
Instruments", and does not use them for trading purposes. The Company's primary
objective is to hedge a portion of its exposure to price volatility from
producing crude oil and natural gas. These arrangements may expose the Company
to credit risk from its counterparties and to basis risk. The Company does not
expect that the counterparties will fail to meet their obligations given their
high credit ratings.
Hedging Activities
Periodically the Company utilizes hedging strategies to hedge the price of a
portion of its future oil and gas production. These strategies include:
(i) swap arrangements that establish an index-related price above
which the Company pays the counterparty and below which the
Company is paid by the counterparty,
(ii) the purchase of index-related puts that provide for a "floor"
price below which the counterparty pays the Company the amount by
which the price of the commodity is below the contracted floor,
(iii) the sale of index-related calls that provide for a "ceiling" price
above which the Company pays the counterparty the amount by which
the price of the commodity is above the contracted ceiling, and
(iv) basis protection swaps, which are arrangements that guarantee the
price differential of oil or gas from a specified delivery point
or points.
Results from commodity hedging transactions are reflected in oil and gas
sales to the extent related to the Company's oil and gas production. The Company
only enters into commodity hedging transactions related to the Company's oil and
gas production volumes or CEMI's physical purchase or sale commitments. Gains or
losses on crude oil and natural gas hedging transactions are recognized as price
adjustments in the months of related production.
As of December 31, 1999, the Company had the following open natural gas swap
arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1999:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------- -------------
<S> <C> <C>
April 2000....................................................................... 600,000 $ 2.50
May 2000......................................................................... 620,000 2.50
June 2000........................................................................ 600,000 2.50
July 2000........................................................................ 620,000 2.50
August 2000...................................................................... 620,000 2.50
September 2000................................................................... 600,000 2.50
October 2000..................................................................... 620,000 2.50
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1999,
the Company would have incurred a gain of $0.5 million.
As of December 31, 1999, the Company had no open oil swap arrangements.
The Company has also closed transactions designed to hedge a portion of the
Company's domestic oil and natural gas production. The net unrecognized losses
resulting from these transactions, $3.9 million as of December 31, 1999, will be
recognized as price adjustments in the months of related production. These
hedging gains and losses are set forth below ($ in thousands):
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<PAGE> 57
<TABLE>
<CAPTION>
HEDGING GAINS (LOSSES)
--------------------------------------
MONTH GAS OIL TOTAL
- ----- -------- ------- --------
<S> <C> <C> <C>
January 2000................... $ -- $ (995) $ (995)
February 2000.................. -- (1,061) (1,061)
March 2000..................... 689 (851) (162)
April 2000..................... 71 (647) (576)
May 2000....................... 73 (668) (595)
June 2000...................... 71 (647) (576)
July 2000...................... 73 (231) (158)
August 2000.................... 73 -- 73
September 2000................. 71 -- 71
October 2000................... 73 -- 73
-------- ------- --------
$ 1,194 $(5,100) $ (3,906)
======== ======= ========
</TABLE>
Subsequent to December 31, 1999, the Company entered into the following natural
gas swap arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1999:
<TABLE>
<CAPTION>
NYMEX - INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------- --------------
<S> <C> <C>
April 2000........................................................ 8,900,000 $2.593
May 2000.......................................................... 3,410,000 2.737
June 2000......................................................... 3,300,000 2.737
July 2000......................................................... 3,410,000 2.741
August 2000....................................................... 3,410,000 2.741
September 2000.................................................... 2,100,000 2.696
October 2000...................................................... 2,170,000 2.696
</TABLE>
Subsequent to December 31, 1999, the Company entered into the following
crude oil swap arrangements designed to hedge a portion of the Company's
domestic crude oil production for periods after December 1999:
<TABLE>
<CAPTION>
MONTHLY NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (BBLS) (PER BBL)
- ------ --------------- -------------
<S> <C> <C>
March 2000............................................................... 183,000 $27.512
April 2000............................................................... 89,000 27.251
</TABLE>
In addition to commodity hedging transactions related to the Company's oil
and gas production, CEMI periodically enters into various hedging transactions
designed to hedge against physical purchase and sale commitments made by CEMI.
Gains or losses on these transactions are recorded as adjustments to oil and gas
marketing sales in the consolidated statements of operations and are not
considered by management to be material.
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<PAGE> 58
Interest Rate Risk
The Company also utilizes hedging strategies to manage fixed-interest rate
exposure. Through the use of a swap arrangement, the Company believes it can
benefit from stable or falling interest rates and reduce its current interest
expense. During 1999, the Company's interest rate swap resulted in a $2.0
million reduction of interest expense. The terms of the swap agreement are as
follows:
<TABLE>
<CAPTION>
Months Notional Amount Fixed Rate Floating Rate
- ------ --------------- ---------- -------------
<S> <C> <C> <C>
May 1998 - April 2001 $230,000,000 7% Average of three-month Swiss Franc LIBOR,
Deutsche Mark and Australian Dollar
plus 300 basis points
May 2001 - April 2008 $230,000,000 7% U.S. three-month LIBOR plus 300 basis points
</TABLE>
If the floating rate is less than the fixed rate, the counterparty will pay
the Company accordingly. If the floating rate exceeds the fixed rate, the
Company will pay the counterparty.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the long-term debt
has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
-----------------------------------------------------------------------------------------
YEARS OF MATURITY
-----------------------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
-------- -------- -------- -------- -------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES: ($ IN MILLIONS)
Long-term debt, including current
portion - fixed rate .............. $ 0.8 $ 0.8 $ 0.6 $ -- $ 150.0 $ 770.0 $ 922.2 $ 838.7
Average interest rate ............. 9.1% 9.1% 9.1% -- 7.9% 9.3% 9.1% --
Long-term debt - variable rate ...... $ -- $ 43.5 $ -- $ -- $ -- $ -- $ 43.5 $ 43.5
Average interest rate ............. -- 9.75% -- -- -- -- 9.75% --
</TABLE>
Concentration of Credit Risk
Other financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of cash, short-term
investments in debt instruments and trade receivables. The Company's accounts
receivable are primarily from purchasers of oil and natural gas products and
exploration and production companies which own interests in properties operated
by the Company. The industry concentration has the potential to impact the
Company's overall exposure to credit risk, either positively or negatively, in
that the customers may be similarly affected by changes in economic, industry or
other conditions. The Company generally requires letters of credit for
receivables from customers which are judged to have sub-standard credit, unless
the credit risk can otherwise be mitigated. The cash and cash equivalents are
deposited with major banks or institutions with high credit ratings.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, "Disclosures About Fair Value of
Financial Instruments". The estimated fair value amounts have been determined by
the Company using available market information and valuation methodologies.
Considerable judgment is required in interpreting market data to develop the
estimates of fair value. The use of different market assumptions or valuation
methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. The Company estimates the fair value of its long-term (including
current maturities), fixed-rate debt using primarily quoted market prices. The
Company's carrying amount for such debt at December 31, 1999 and 1998 was $921.4
million and $919.1 million, respectively, compared to approximate fair values of
$838.7 million and $654.7 million, respectively. The carrying value of other
long-term
-58-
<PAGE> 59
debt approximates its fair value as interest rates are primarily variable, based
on prevailing market rates. The Company estimates the fair value of its
convertible preferred stock, which was issued in April 1998, using quoted market
prices. The Company's carrying amount for such preferred stock at December 31,
1999 and 1998 was $229.8 million and $230.0 million, compared to an approximate
fair value of $119.0 million and $48.9 million, respectively.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to the Company's oil and
gas producing activities are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Proved ........................................................ $ 2,193,492 $ 121,856 $ 2,315,348
Unproved ...................................................... 36,225 3,783 40,008
------------ ------------ ------------
Total ................................................. 2,229,717 125,639 2,355,356
Less accumulated depreciation, depletion and amortization ....... (1,645,185) (25,357) (1,670,542)
------------ ------------ ------------
Net capitalized costs ........................................... $ 584,532 $ 100,282 $ 684,814
============ ============ ============
<CAPTION>
DECEMBER 31, 1998
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Proved ........................................................ $ 2,060,076 $ 82,867 $ 2,142,943
Unproved ...................................................... 44,780 7,907 52,687
------------ ------------ ------------
Total ................................................. 2,104,856 90,774 2,195,630
Less accumulated depreciation, depletion and amortization ....... (1,556,284) (17,998) (1,574,282)
------------ ------------ ------------
Net capitalized costs ........................................... $ 548,572 $ 72,776 $ 621,348
============ ============ ============
</TABLE>
Unproved properties not subject to amortization at December 31, 1999 and
1998 consisted mainly of lease acquisition costs. The Company capitalized
approximately $3.5 million, $6.5 million, $5.1 million and $12.9 million of
interest during 1999, 1998, the Transition Period and fiscal 1997, respectively,
on significant investments in unproved properties that were not yet included in
the amortization base of the full-cost pool. The Company will continue to
evaluate its unevaluated properties; however, the timing of the ultimate
evaluation and disposition of the properties has not been determined.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development and leasehold costs ................................. $ 95,329 $ 31,536 $ 126,865
Exploration costs ............................................... 23,651 42 23,693
Acquisition costs ............................................... 47,993 4,100 52,093
Sales of oil and gas properties ................................. (44,822) (813) (45,635)
Capitalized internal costs ...................................... 2,710 -- 2,710
------------ ------------ ------------
Total ................................................. $ 124,861 $ 34,865 $ 159,726
============ ============ ============
</TABLE>
-59-
<PAGE> 60
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development and leasehold costs ................................. $ 169,491 $ 7,119 $ 176,610
Exploration costs ............................................... 63,245 5,427 68,672
Acquisition costs ............................................... 662,104 78,176 740,280
Sales of oil and gas properties ................................. (15,712) -- (15,712)
Capitalized internal costs ...................................... 5,262 -- 5,262
------------ ------------ ------------
Total ................................................. $ 884,390 $ 90,722 $ 975,112
============ ============ ============
<CAPTION>
SIX MONTHS ENDED DECEMBER 31, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development and leasehold costs ................................. $ 144,283 $ -- $ 144,283
Exploration costs ............................................... 40,534 -- 40,534
Acquisition costs ............................................... 39,245 -- 39,245
Capitalized internal costs ...................................... 2,435 -- 2,435
------------ ------------ ------------
Total ................................................. $ 226,497 $ -- $ 226,497
============ ============ ============
<CAPTION>
YEAR ENDED JUNE 30, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development and leasehold costs ................................. $ 324,989 $ -- $ 324,989
Exploration costs ............................................... 136,473 -- 136,473
Capitalized internal costs ...................................... 3,905 -- 3,905
------------ ------------ ------------
Total ................................................. $ 465,367 $ -- $ 465,367
============ ============ ============
</TABLE>
Results of Operations from Oil and Gas Producing Activities (unaudited)
The Company's results of operations from oil and gas producing activities
are presented below for 1999, 1998, the Transition Period and fiscal 1997. The
following table includes revenues and expenses associated directly with the
Company's oil and gas producing activities. It does not include any allocation
of the Company's interest costs and, therefore, is not necessarily indicative of
the contribution to consolidated net operating results of the Company's oil and
gas operations.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................... $ 266,468 $ 13,977 $ 280,445
Production expenses ............................................. (44,165) (2,133) (46,298)
Production taxes ................................................ (13,264) -- (13,264)
Depletion and depreciation ...................................... (88,901) (6,143) (95,044)
Imputed income tax (provision) benefit (a) ...................... (45,052) (2,565) (47,617)
------------ ------------ ------------
Results of operations from oil and gas producing activities ..... $ 75,086 $ 3,136 $ 78,222
============ ============ ============
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................... $ 248,909 $ 7,978 $ 256,887
Production expenses ............................................. (49,368) (1,834) (51,202)
Production taxes ................................................ (8,295) -- (8,295)
Impairment of oil and gas properties ............................ (810,610) (15,390) (826,000)
Depletion and depreciation ...................................... (143,283) (3,361) (146,644)
Imputed income tax (provision) benefit (a) ...................... 285,981 5,673 291,654
------------ ------------ ------------
Results of operations from oil and gas producing activities ..... $ (476,666) $ (6,934) $ (483,600)
============ ============ ============
</TABLE>
-60-
<PAGE> 61
<TABLE>
<CAPTION>
SIX MONTHS ENDED DECEMBER 31, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................... $ 95,657 $ -- $ 95,657
Production expenses ............................................. (7,560) -- (7,560)
Production taxes ................................................ (2,534) -- (2,534)
Impairment of oil and gas properties ............................ (110,000) -- (110,000)
Depletion and depreciation ...................................... (60,408) -- (60,408)
Imputed income tax (provision) benefit (a) ...................... 31,817 -- 31,817
------------ ------------ ------------
Results of operations from oil and gas producing activities ..... $ (53,028) $ -- $ (53,028)
============ ============ ============
<CAPTION>
YEAR ENDED JUNE 30, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................... $ 192,920 $ -- $ 192,920
Production expenses ............................................. (11,445) -- (11,445)
Production taxes ................................................ (3,662) -- (3,662)
Impairment of oil and gas properties ............................ (236,000) -- (236,000)
Depletion and depreciation ...................................... (103,264) -- (103,264)
Imputed income tax (provision) benefit (a) ...................... 60,544 -- 60,544
------------ ------------ ------------
Results of operations from oil and gas producing activities ..... $ (100,907) $ -- $ (100,907)
============ ============ ============
</TABLE>
- ----------
(a) The imputed income tax provision is hypothetical (at the statutory rate) and
determined without regard to the Company's deduction for general and
administrative expenses, interest costs and other income tax credits and
deductions, nor whether the hypothetical tax benefits will be realized.
Capitalized costs, less accumulated amortization and related deferred income
taxes, cannot exceed an amount equal to the sum of the present value (discounted
at 10%) of estimated future net revenues less estimated future expenditures to
be incurred in developing and producing the proved reserves, less any related
income tax effects. At December 31, 1998 and 1997 and June 30, 1997, capitalized
costs of oil and gas properties exceeded the estimated present value of future
net revenues for the Company's proved reserves, net of related income tax
considerations, resulting in writedowns in the carrying value of oil and gas
properties of $826 million, $110 million and $236 million, respectively.
Oil and Gas Reserve Quantities (unaudited)
The reserve information presented below is based upon reports prepared by
independent petroleum engineers and the Company's petroleum engineers.
o As of December 31, 1999, Williamson Petroleum Consultants, Inc.
("Williamson"), Ryder Scott Company ("Ryder Scott"), and the
Company's internal reservoir engineers evaluated 50%, 16%, and 34%
of the Company's combined discounted future net revenues from the
Company's estimated proved reserves, respectively.
o As of December 31, 1998, Williamson, Ryder Scott, H.J. Gruy and
Associates, Inc. and the Company's internal reservoir engineers
evaluated 63%, 12%, 1% and 24% of the Company's combined discounted
future net revenues from the Company's estimated proved reserves,
respectively.
o As of December 31, 1997, Williamson, Porter Engineering Associates,
Netherland, Sewell & Associates, Inc. and internal reservoir
engineers evaluated approximately 53%, 42%, 3% and 2% of the
Company's combined discounted future net revenues from the Company's
estimated proved reserves, respectively.
o As of June 30, 1997, the reserves evaluated by Williamson
constituted approximately 41% of the Company's combined discounted
future net revenues from the Company's estimated proved reserves,
with the remaining reserves being evaluated internally. The reserves
evaluated internally in fiscal 1997 were subsequently evaluated by
Williamson with a variance of approximately 4% of total proved
reserves.
The information is presented in accordance with regulations prescribed by
the Securities and Exchange Commission. The Company emphasizes that reserve
estimates are inherently imprecise. The Company's reserve estimates were
generally based upon extrapolation of historical production trends, analogy to
similar properties and
-61-
<PAGE> 62
volumetric calculations. Accordingly, these estimates are expected to change,
and such changes could be material and occur in the near term as future
information becomes available.
Proved oil and gas reserves represent the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods. As of December 31,
1997 and June 30, 1997, all of the Company's oil and gas reserves were located
in the United States.
Presented below is a summary of changes in estimated reserves of the Company
for 1999, 1998, the Transition Period and fiscal 1997:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
U.S. CANADA COMBINED
----------------------- ---------------------- -----------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ... 22,560 724,018 33 231,773 22,593 955,791
Extensions, discoveries and other
additions ............................ 4,593 158,801 -- 37,835 4,593 196,636
Revisions of previous estimates ........ 3,404 59,904 -- (98,571) 3,404 (38,667)
Production ............................. (4,147) (96,873) -- (11,737) (4,147) (108,610)
Sale of reserves-in-place .............. (4,371) (31,616) (33) (796) (4,404) (32,412)
Purchase of reserves-in-place .......... 2,756 64,350 -- 19,738 2,756 84,088
---------- ---------- ---------- ---------- ---------- ----------
Proved reserves, end of period ......... 24,795 878,584 -- 178,242 24,795 1,056,826
========== ========== ========== ========== ========== ==========
Proved developed reserves:
Beginning of period .................. 18,003 552,953 33 105,990 18,036 658,943
========== ========== ========== ========== ========== ==========
End of period ........................ 17,750 627,120 -- 136,203 17,750 763,323
========== ========== ========== ========== ========== ==========
<CAPTION>
DECEMBER 31, 1998
U.S. CANADA COMBINED
----------------------- ---------------------- -----------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ... 18,226 339,118 -- -- 18,226 339,118
Extensions, discoveries and other
additions ............................ 3,448 90,879 -- -- 3,448 90,879
Revisions of previous estimates ........ (4,082) (60,477) -- -- (4,082) (60,477)
Production ............................. (5,975) (86,681) (1) (7,740) (5,976) (94,421)
Sale of reserves-in-place .............. (30) (3,515) -- -- (30) (3,515)
Purchase of reserves-in-place .......... 10,973 444,694 34 239,513 11,007 684,207
---------- ---------- ---------- ---------- ---------- ----------
Proved reserves, end of period ......... 22,560 724,018 33 231,773 22,593 955,791
========== ========== ========== ========== ========== ==========
Proved developed reserves:
Beginning of period .................. 10,087 178,082 -- -- 10,087 178,082
========== ========== ========== ========== ========== ==========
End of period ........................ 18,003 552,953 33 105,990 18,036 658,943
========== ========== ========== ========== ========== ==========
<CAPTION>
DECEMBER 31, 1997
U.S. CANADA COMBINED
----------------------- ---------------------- -----------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ... 17,373 298,766 -- -- 17,373 298,766
Extensions, discoveries and other
additions ............................ 5,573 68,813 -- -- 5,573 68,813
Revisions of previous estimates ........ (3,428) (24,189) -- -- (3,428) (24,189)
Production ............................. (1,857) (27,327) -- -- (1,857) (27,327)
Sale of reserves-in-place .............. -- -- -- -- -- --
Purchase of reserves-in-place .......... 565 23,055 -- -- 565 23,055
---------- ---------- ---------- ---------- ---------- ----------
Proved reserves, end of period ......... 18,226 339,118 -- -- 18,226 339,118
========== ========== ========== ========== ========== ==========
Proved developed reserves:
Beginning of period .................. 7,324 151,879 -- -- 7,324 151,879
========== ========== ========== ========== ========== ==========
End of period ........................ 10,087 178,082 -- -- 10,087 178,082
========== ========== ========== ========== ========== ==========
</TABLE>
-62-
<PAGE> 63
<TABLE>
<CAPTION>
JUNE 30, 1997
U.S. CANADA COMBINED
----------------------- ---------------------- -----------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ... 12,258 351,224 -- -- 12,258 351,224
Extensions, discoveries and other
additions ............................ 13,874 147,485 -- -- 13,874 147,485
Revisions of previous estimates ........ (5,989) (137,938) -- -- (5,989) (137,938)
Production ............................. (2,770) (62,005) -- -- (2,770) (62,005)
Sale of reserves-in-place .............. -- -- -- -- -- --
Purchase of reserves-in-place .......... -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Proved reserves, end of period ......... 17,373 298,766 -- -- 17,373 298,766
========== ========== ========== ========== ========== ==========
Proved developed reserves:
Beginning of period .................. 3,648 144,721 -- -- 3,648 144,721
========== ========== ========== ========== ========== ==========
End of period ........................ 7,324 151,879 -- -- 7,324 151,879
========== ========== ========== ========== ========== ==========
</TABLE>
During 1999, the Company acquired approximately 101 Bcfe of proved reserves
through purchases of oil and gas properties for consideration of $52 million.
The Company also sold 59 Bcfe of proved reserves for consideration of
approximately $46 million. During 1999, the Company recorded upward revisions of
80 Bcfe to the December 31, 1998 estimates of its U.S. reserves, and downward
revisions of 99 Bcfe to the December 31, 1998 estimates of its Canadian
reserves, for a net Company wide revision of 19 Bcfe, or approximately 1.7%. The
upward revisions to its U.S. reserves were caused by higher oil and gas prices
at December 31, 1999, and actual performance in excess of predicted performance.
Higher prices extend the economic lives of the underlying oil and gas properties
and thereby increase the estimated future reserves. The downward revisions to
its Canadian reserves were caused by a reduction of the Company's proved
undeveloped locations and an increase in projected transportation and operating
costs in Canada, which decreased the economic lives of the underlying
properties.
During 1998, the Company acquired approximately 750 Bcfe of proved reserves
through mergers or through purchases of oil and gas properties. The total
consideration given for the acquisitions was 30.8 million shares of Company
common stock, $280 million of cash, the assumption of $205 million of debt, and
the incurrence of approximately $20 million of other acquisition related costs.
Also during 1998, the Company recorded downward revisions to the December 31,
1997 estimates of approximately 4,082 MBbl and 60,477 MMcf, or approximately 85
Bcfe. These reserve revisions were primarily attributable to lower oil and gas
prices at December 31, 1998. The weighted average prices used to value the
Company's reserves at December 31, 1998 were $10.48 per barrel of oil and $1.68
per Mcf of gas, as compared to the prices used at December 31, 1997 of $17.62
per barrel of oil and $2.29 per Mcf of gas.
For the six months ended December 31, 1997, the Company recorded downward
revisions to the June 30, 1997 reserve estimates of approximately 3,428 MBbl and
24,189 MMcf, or approximately 45 Bcfe. The reserve revisions were primarily
attributable to lower than expected results from development drilling and
production which eliminated certain previously established proved reserves.
On December 16, 1997, Chesapeake acquired AnSon Production Corporation, a
privately owned oil and gas producer based in Oklahoma City. Consideration for
this acquisition was approximately $43 million. The Company estimates that it
acquired approximately 26.4 Bcfe in connection with this acquisition.
For the fiscal year ended June 30, 1997, the Company recorded downward
revisions to the previous year's reserve estimates of approximately 5,989 MBbl
and 137,938 MMcf, or approximately 174 Bcfe. The reserve revisions were
primarily attributable to the decrease in oil and gas prices between periods,
higher drilling and completion costs, and unfavorable developmental drilling and
production results during fiscal 1997. Specifically, the Company recorded
aggregate downward adjustments to proved reserves of 159 Bcfe for the Knox,
Giddings and Louisiana Trend areas.
-63-
<PAGE> 64
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
Statement of Financial Accounting Standards No. 69 ("SFAS 69") prescribes
guidelines for computing a standardized measure of future net cash flows and
changes therein relating to estimated proved reserves. The Company has followed
these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated quantities of
oil and gas to be produced. Estimates are made of quantities of proved reserves
and the future periods during which they are expected to be produced based on
year-end economic conditions. Estimated future income taxes are computed using
current statutory income tax rates including consideration for the current tax
basis of the properties and related carryforwards, giving effect to permanent
differences and tax credits. The resulting future net cash flows are reduced to
present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect the Company's expectations of actual revenue to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process, as discussed previously, are equally
applicable to the standardized measure computations since these estimates are
the basis for the valuation process.
The following summary sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in SFAS 69:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (a) ......................................... $ 2,555,241 $ 437,928 $ 2,993,169
Future production costs ......................................... (671,431) (195,464) (866,895)
Future development costs ........................................ (209,921) (20,950) (230,871)
Future income tax provision ..................................... (219,866) (29,410) (249,276)
------------ ------------ ------------
Net future cash flows ........................................... 1,454,023 192,104 1,646,127
Less effect of a 10% discount factor ............................ (545,125) (94,390) (639,515)
------------ ------------ ------------
Standardized measure of discounted future net cash flows ........ $ 908,898 $ 97,714 $ 1,006,612
============ ============ ============
Discounted (at 10%) future net cash flows before income
taxes ........................................................... $ 991,748 $ 97,748 $ 1,089,496
============ ============ ============
<CAPTION>
DECEMBER 31, 1998
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (b) ......................................... $ 1,374,280 $ 474,143 $ 1,848,423
Future production costs ......................................... (432,876) (52,493) (485,369)
Future development costs ........................................ (124,717) (29,634) (154,351)
Future income tax provision ..................................... (6,464) (143,747) (150,211)
------------ ------------ ------------
Net future cash flows ........................................... 810,223 248,269 1,058,492
Less effect of a 10% discount factor ............................ (303,096) (132,281) (435,377)
------------ ------------ ------------
Standardized measure of discounted future net cash flows ........ $ 507,127 $ 115,988 $ 623,115
============ ============ ============
Discounted (at 10%) future net cash flows before income
taxes ........................................................... $ 504,148 $ 156,843 $ 660,991
============ ============ ============
</TABLE>
-64-
<PAGE> 65
<TABLE>
<CAPTION>
DECEMBER 31, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (c) ......................................... $ 1,100,807 $ -- $ 1,100,807
Future production costs ......................................... (223,030) -- (223,030)
Future development costs ........................................ (158,387) -- (158,387)
Future income tax provision ..................................... (108,027) -- (108,027)
------------ ------------ ------------
Net future cash flows ........................................... 611,363 -- 611,363
Less effect of a 10% discount factor ............................ (181,253) -- (181,253)
------------ ------------ ------------
Standardized measure of discounted future net cash flows ........ $ 430,110 $ -- $ 430,110
============ ============ ============
Discounted (at 10%) future net cash flows before income
taxes ........................................................... $ 466,509 $ -- $ 466,509
============ ============ ============
<CAPTION>
JUNE 30, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (d) ......................................... $ 954,839 $ -- $ 954,839
Future production costs ......................................... (190,604) -- (190,604)
Future development costs ........................................ (152,281) -- (152,281)
Future income tax provision ..................................... (104,183) -- (104,183)
------------ ------------ ------------
Net future cash flows ........................................... 507,771 -- 507,771
Less effect of a 10% discount factor ............................ (92,273) -- (92,273)
------------ ------------ ------------
Standardized measure of discounted future net cash flows ........ $ 415,498 $ -- $ 415,498
============ ============ ============
Discounted (at 10%) future net cash flows before income
taxes ........................................................... $ 437,386 $ -- $ 437,386
============ ============ ============
</TABLE>
- ----------
(a) Calculated using weighted average prices of $24.72 per barrel of oil and
$2.25 per Mcf of gas.
(b) Calculated using weighted average prices of $10.48 per barrel of oil and
$1.68 per Mcf of gas.
(c) Calculated using weighted average prices of $17.62 per barrel of oil and
$2.29 per Mcf of gas.
(d) Calculated using weighted average prices of $18.38 per barrel of oil and
$2.12 per Mcf of gas.
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ....................... $ 507,127 $ 115,988 $ 623,115
Sales of oil and gas produced, net of production costs .......... (209,039) (11,844) (220,883)
Net changes in prices and production costs ...................... 320,123 (55,156) 264,967
Extensions and discoveries, net of production and
development costs ........................................... 200,787 14,333 215,120
Changes in future development costs ............................. (15,011) 20,679 5,668
Development costs incurred during the period that reduced
future development costs .................................... 14,114 1,985 16,099
Revisions of previous quantity estimates ........................ 88,250 (49,034) 39,216
Purchase of reserves-in-place ................................... 66,895 18,476 85,371
Sales of reserves-in-place ...................................... (25,838) (920) (26,758)
Accretion of discount ........................................... 50,415 15,684 66,099
Net change in income taxes ...................................... (85,828) 40,821 (45,007)
Changes in production rates and other ........................... (3,097) (13,298) (16,395)
------------ ------------ ------------
Standardized measure, end of period ............................. $ 908,898 $ 97,714 $ 1,006,612
============ ============ ============
</TABLE>
-65-
<PAGE> 66
<TABLE>
<CAPTION>
DECEMBER 31, 1998
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ....................... $ 430,110 $ -- $ 430,110
Sales of oil and gas produced, net of production costs .......... (191,246) (6,144) (197,390)
Net changes in prices and production costs ...................... (189,817) -- (189,817)
Extensions and discoveries, net of production and
development costs ........................................... 85,464 -- 85,464
Changes in future development costs ............................. 72,279 -- 72,279
Development costs incurred during the period that reduced
future development costs .................................... 28,191 -- 28,191
Revisions of previous quantity estimates ........................ (64,770) -- (64,770)
Purchase of reserves-in-place ................................... 288,694 164,821 453,515
Sales of reserves-in-place ...................................... (3,079) -- (3,079)
Accretion of discount ........................................... 46,651 -- 46,651
Net change in income taxes ...................................... 39,377 (40,855) (1,478)
Changes in production rates and other ........................... (34,727) (1,834) (36,561)
------------ ------------ ------------
Standardized measure, end of period ............................. $ 507,127 $ 115,988 $ 623,115
============ ============ ============
<CAPTION>
DECEMBER 31, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ....................... $ 415,498 $ -- $ 415,498
Sales of oil and gas produced, net of production costs .......... (85,563) -- (85,563)
Net changes in prices and production costs ...................... 26,106 -- 26,106
Extensions and discoveries, net of production and
development costs ........................................... 92,597 -- 92,597
Changes in future development costs ............................. (7,422) -- (7,422)
Development costs incurred during the period that reduced
future development costs .................................... 47,703 -- 47,703
Revisions of previous quantity estimates ........................ (62,655) -- (62,655)
Purchase of reserves-in-place ................................... 25,236 -- 25,236
Sales of reserves-in-place ...................................... -- -- --
Accretion of discount ........................................... 43,739 -- 43,739
Net change in income taxes ...................................... (14,510) -- (14,510)
Changes in production rates and other ........................... (50,619) -- (50,619)
------------ ------------ ------------
Standardized measure, end of period ............................. $ 430,110 $ -- $ 430,110
============ ============ ============
<CAPTION>
JUNE 30, 1997
U.S. CANADA COMBINED
------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ....................... $ 461,411 $ -- $ 461,411
Sales of oil and gas produced, net of production costs .......... (177,813) -- (177,813)
Net changes in prices and production costs ...................... (99,234) -- (99,234)
Extensions and discoveries, net of production and
development costs .......................................... 287,068 -- 287,068
Changes in future development costs ............................. (12,831) -- (12,831)
Development costs incurred during the period that reduced
future development costs .................................... 46,888 -- 46,888
Revisions of previous quantity estimates ........................ (199,738) -- (199,738)
Purchase of reserves-in-place ................................... -- -- --
Sales of reserves-in-place ...................................... -- -- --
Accretion of discount ........................................... 54,702 -- 54,702
Net change in income taxes ...................................... 63,719 -- 63,719
Changes in production rates and other ........................... (8,674) -- (8,674)
------------ ------------ ------------
Standardized measure, end of period ............................. $ 415,498 $ -- $ 415,498
============ ============ ============
</TABLE>
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<PAGE> 67
12. TRANSITION PERIOD COMPARATIVE DATA
The following table presents certain financial information for the twelve
months ended December 31, 1998 and 1997, and the six months ended December 31,
1997 and 1996, respectively:
<TABLE>
<CAPTION>
TWELVE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
----------------------- -----------------------
1998 1997 1997 1996
---------- ---------- ---------- ----------
(UNAUDITED) (UNAUDITED)
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Revenues ................................................... $ 377,946 $ 302,804 $ 153,898 $ 120,186
========== ========== ========== ==========
Gross profit (loss)(a) ..................................... $ (856,197) $ (309,041) $ (93,092) $ 42,946
========== ========== ========== ==========
Income (loss) before income taxes
and extraordinary item ................................... $ (920,520) $ (251,150) $ (31,574) $ 39,246
Income taxes ............................................... -- (17,898) -- 14,325
---------- ---------- ---------- ----------
Income (loss) before extraordinary item .................... (920,520) (233,252) (31,574) 24,921
Extraordinary item ......................................... (13,334) (177) -- (6,443)
---------- ---------- ---------- ----------
Net income (loss) .......................................... $ (933,854) $ (233,429) $ (31,574) $ 18,478
========== ========== ========== ==========
Earnings per share - basic
Income (loss) before extraordinary item ................ $ (9.83) $ (3.30) $ (0.45) $ 0.40
Extraordinary item ..................................... (0.14) -- -- (0.10)
---------- ---------- ---------- ----------
Net income (loss) ...................................... $ (9.97) $ (3.30) $ (0.45) $ 0.30
========== ========== ========== ==========
Earnings per share - assuming dilution
Income (loss) before extraordinary item ................ $ (9.83) $ (3.30) $ (0.45) $ 0.38
Extraordinary item ..................................... (0.14) -- -- (0.10)
---------- ---------- ---------- ----------
Net income (loss) ...................................... $ (9.97) $ (3.30) $ (0.45) $ 0.28
========== ========== ========== ==========
Weighted average common shares outstanding (in 000's)
Basic .................................................. 94,911 70,672 70,835 61,985
========== ========== ========== ==========
Assuming dilution ...................................... 94,911 70,672 70,835 66,300
========== ========== ========== ==========
</TABLE>
- ----------
(a) Total revenue less total operating costs.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized unaudited quarterly financial data for 1999 and 1998 are as
follows ($ in thousands except per share data):
<TABLE>
<CAPTION>
QUARTERS ENDED
---------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1999 1999 1999 1999
---------- ---------- ------------ ----------
<S> <C> <C> <C> <C>
Net sales .................................................. $ 65,677 $ 80,892 $ 102,140 $ 106,237
Gross profit (loss)(a) ..................................... 7,067 25,765 36,498 38,190
Net income (loss) .......................................... (11,950) 8,147 18,115 18,954
Net income (loss) per share:
Basic .................................................... (0.17) 0.04 0.14 0.15
Diluted .................................................. (0.17) 0.04 0.13 0.14
<CAPTION>
QUARTERS ENDED
---------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1998 1998 1998 1998
---------- ---------- ------------ ----------
<S> <C> <C> <C> <C>
Net sales .................................................. $ 76,765 $ 109,310 $ 106,338 $ 85,533
Gross profit (loss)(a) ..................................... (246,036) (218,645) 13,650 (405,166)
Net income (loss) before extraordinary item ................ (256,500) (234,739) (4,149) (425,132)
Net income (loss) .......................................... (256,500) (248,073) (4,149) (425,132)
Net income (loss) per share before extraordinary item:
Basic .................................................... (3.19) (2.29) (0.08) (4.44)
Diluted .................................................. (3.19) (2.29) (0.08) (4.44)
</TABLE>
- ----------
(a) Total revenue less total operating costs.
Capitalized costs, less accumulated amortization and related deferred income
taxes, cannot exceed an amount equal to the sum of the present value of
estimated future net revenues less estimated future expenditures to be incurred
in developing and producing the proved reserves, less any related income tax
effects. At December 31, 1998, June 30, 1998 and March 31, 1998, capitalized
costs of oil and gas properties exceeded the estimated present
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<PAGE> 68
value of future net revenues for the Company's proved reserves, net of related
income tax considerations, resulting in writedowns in the carrying value of oil
and gas properties of $360 million, $216 million and $250 million, respectively.
During the fourth quarter of 1998, the Company incurred a $55 million
impairment charge to adjust certain non-oil and gas producing assets to their
estimated fair values. 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.
14. ACQUISITIONS
During 1998, the Company acquired approximately 750 Bcfe of proved reserves
through mergers or through purchases of oil and gas properties. The total
consideration given for the acquisitions was $280 million of cash, 30.8 million
shares of Company common stock, the assumption of $205 million of debt, and the
incurrence of approximately $20 million of other acquisition related costs.
In March 1998, the Company acquired Hugoton Energy Corporation ("Hugoton")
pursuant to a merger by issuing 25.8 million shares of the Company's common
stock in exchange for 100% of Hugoton's common stock. The acquisition of Hugoton
was accounted for using the purchase method as of March 1, 1998, and the results
of operations of Hugoton have been included since that date.
The following unaudited pro forma information has been prepared assuming
Hugoton had been acquired as of the beginning of the periods presented. The pro
forma information is presented for informational purposes only and is not
necessarily indicative of what would have occurred if the acquisition had been
made as of those dates. In addition, the pro forma information is not intended
to be a projection of future results and does not reflect the efficiencies
expected to result from the integration of Hugoton.
Pro Forma Information (Unaudited)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
--------- --------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C>
Revenues.......................................... $387,638 $379,546
Loss before extraordinary item.................... (921,969) (215,350)
Net loss.......................................... (935,303) (215,527)
Loss before extraordinary item per common share... (9.41) (2.23)
Net loss per common share......................... (9.55) (2.23)
</TABLE>
The Company acquired other businesses and oil and gas properties during 1999
and 1998. The results of operations of each of these businesses and properties,
taken individually, were not material in relation to the Company's consolidated
results of operations.
15. SUBSEQUENT EVENTS
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 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.
In connection with a potential restructuring of Gothic Energy Corporation
("Gothic"), Chesapeake and Gothic agreed in March 2000 to substantially revise
their joint venture originally entered into in March 1998. In addition,
Chesapeake granted Gothic an option to redeem the preferred and common shares of
Gothic held by Chesapeake in exchange for rights to certain undeveloped
leasehold interests covered by the joint venture agreement. The terms of the
agreement are subject to certain conditions, including the approval by certain
of Gothic's creditors. Significant terms of the proposed agreement are as
follows:
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<PAGE> 69
o the joint venture is extended for three years to April 30, 2006,
o Chesapeake is granted a right of first refusal on any property
disposition by Gothic,
o Chesapeake becomes operator of 28 wells currently operated by Gothic,
o Chesapeake will have the first right to drill, complete and operate
wells in certain areas covered by the joint venture,
o Chesapeake granted Gothic the option to redeem its investment in $50
million liquidation amount of Gothic Series B preferred stock, including
dividends in arrears, and 2.4 million shares of Gothic common stock, for
a permanent assignment to Chesapeake of certain undeveloped leasehold
interests that were originally subject to a reassignment obligation to
Gothic.
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<PAGE> 70
SCHEDULE II
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONS
----------------------
BALANCE AT CHARGED BALANCE AT
BEGINNING CHARGED TO OTHER END
DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD
- ---------------------------------------- --------- ---------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
December 31, 1999:
Allowance for doubtful accounts....... $ 3,209 $ 9 $ -- $ -- $ 3,218
Valuation allowance for deferred tax
assets............................. $458,903 $ -- $(5,731)(a) $(10,956) $442,016
December 31, 1998:
Allowance for doubtful accounts....... $ 691 $ 1,589 $ 1,000 $ 71 $ 3,209
Valuation allowance for deferred tax
assets............................. $77,934 $380,969 $ -- $ -- $458,903
December 31, 1997:
Allowance for doubtful accounts....... $ 387 $ 40 $ 264 $ -- $ 691
Valuation allowance for deferred tax
assets............................. $64,116 $ 13,818 $ -- $ -- $ 77,934
June 30, 1997:
Allowance for doubtful accounts....... $ 340 $ 299 $ -- $ 252 $ 387
Valuation allowance for deferred tax
assets............................. $ -- $ 64,116 $ -- $ -- $ 64,116
</TABLE>
(a) At December 31, 1998, $5.7 million of the valuation allowance was related
to the Company's Canadian deferred tax assets. During 1999, this valuation
allowance was eliminated as part of a purchase price reallocation related
to a 1998 acquisition.
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<PAGE> 71
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 29, 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 29, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 29, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 29, 2000.
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<PAGE> 72
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements. The Company's consolidated financial statements
are included in Item 8 of this report. Reference is made to the accompanying
Index to Consolidated Financial Statements.
2. Financial Statement Schedules. Schedule II is included in Item 8 of
this report with the Company's consolidated financial statements. No other
financial statement schedules are applicable or required.
3. Exhibits. The following exhibits are filed herewith pursuant to the
requirements of Item 601 of Regulation S-K:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <C>
3.1 -- Registrant's Certificate of Incorporation as amended.
Incorporated herein by reference to Exhibit 3.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235).
3.2 -- Registrant's Bylaws. Incorporated herein by reference to
Exhibit 3.2 to Registrant's registration statement on Form
8-B (No. 001-13726).
4.1 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, as Trustee, with respect to
7.875% Senior Notes due 2004. Incorporated herein by
reference to Exhibit 4.1 to Registrant's registration
statement on Form S-4 (No. 333-24995). First Supplemental
Indenture dated December 17, 1997 and Second Supplemental
Indenture dated February 16, 1998. Incorporated herein by
reference to Exhibit 4.1.1 to Registrant's transition
report on Form 10-K for the six months ended December 31,
1997. Second [Third] Supplemental Indenture dated April 22,
1998. Incorporated herein by reference to Exhibit 4.1.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.1.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.2 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, As Trustee, with respect to 8.5%
Senior Notes due 2012. Incorporated herein by reference to
Exhibit 4.1.3 to Registrant registration statement on Form
S-4 (No. 333-24995). First Supplemental Indenture dated
December 17, 1997 and Second Supplemental Indenture dated
February 16, 1998. Incorporated herein by reference to
Exhibit 4.2.1 to Registrant's transition report on Form
10-K for the six months ended December 31, 1997. Second
[Third] Supplemental Indenture dated April 22, 1998.
Incorporated herein by reference to Exhibit 4.2.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.2.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.3 -- Indenture dated as of April 1, 1998 among the Registrant,
as Subsidiary Guarantors, and United States Trust Company
of New York, As Trustee, with respect to 9.625% Senior
Notes due 2005. Incorporated herein by reference to Exhibit
4.3 to Registrant registration statement
</TABLE>
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<PAGE> 73
<TABLE>
<S> <C>
on Form S-3 (No. 333-57235). First Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.4.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.4 -- Indenture dated as of April 1, 1996 among the Registrant,
its subsidiaries signatory thereto, as Subsidiary
Guarantors, and United States Trust Company of New York, as
Trustee, with respect to 9.125% Senior Notes, due 2006.
Incorporated herein by reference to Exhibit 4.6 to
Registrant's registration statement on Form S-3 (No.
333-1588). First Supplemental Indenture dated December 30,
1996 and Second Supplemental Indenture dated December 17,
1997. Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Third Supplemental
Indenture dated April 22, 1998. Incorporated herein by
reference to Exhibit 4.4.1 to Registrant's Amendment No. 1
to Form S-3 registration statement (No. 333-57235). Fourth
Supplemental Indenture dated July 1, 1998. Incorporated
herein by reference to Exhibit 4.3.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
September 30, 1998.
4.5 -- Agreement to furnish copies of unfiled long-term debt
Instruments. Incorporated herein by reference to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997.
4.11 -- Registration Rights Agreement as of April 22, 1998 among
the Registrant and Donaldson, Lufkin & Jenrette Securities
Corporation, Morgan Stanley & Co. Incorporated, Bear
Stearns & Co. Inc., Lehman Brothers Inc. and J.P. Morgan
Securities Inc., with respect to 7% Cumulative Convertible
Preferred Stock. Incorporated herein by reference to
Exhibit 4.11 to Registrant's quarterly report on Form 10-Q
for the quarter ended March 31, 1998.
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated
herein by reference to Exhibit 10.1.1 to Registrant's
registration statement on Form S-4 (No. 33-93718).
10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as
Amended. Incorporated herein by reference to Exhibit 10.1.2
to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1996.
10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended.
Incorporated herein by reference to Exhibit 10.1.3 to
Registrant's quarterly report on Form 10-Q for the quarter
ended December 31, 1996.
10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein
by reference to Registrant's Proxy Statement for its 1996
Annual Meeting of Shareholders and to Registrant's
quarterly report on Form 10-Q for the quarter ended
December 31, 1996.
10.1.5+ -- Registrant's 1999 Stock Option Plan. Incorporated herein
by reference to Exhibit 10.1.5 to Registrant's quarterly
report on Form 10-Q for the quarter ended June 30, 1999.
10.2.1+ -- First Amendment to the Amended and Restated Employment
Agreement dated as of December 31, 1998 between Aubrey K.
McClendon and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended June
30, 1999.
10.2.2+ -- First Amendment to the Amended and Restated Employment
Agreement dated as of December 31, 1998 between Tom L. Ward
and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.2 to Registrant's quarterly
report on Form 10-Q for the quarter ended June 30, 1999.
10.2.3+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Marcus C. Rowland and Chesapeake
Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.3 to Registrant's annual report on Form 10-K
for the year ended December 31, 1998.
</TABLE>
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<PAGE> 74
<TABLE>
<S> <C>
10.2.4+ -- Employment Agreement dated as of July 1, 1997 between
Steven C. Dixon and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.4 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1997.
10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J.
Mark Lester and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.5 to Registrant's
annual report on Form 10-K for the year ended June 30,
1997.
10.2.6+ -- Employment Agreement dated as of July 1, 1997 between
Henry J. Hood and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.6 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.8+ -- Employment Agreement dated as of July 1, 1997 between
Martha A. Burger and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.9+ -- Amendment to Employment Agreements of Steven C. Dixon, J.
Mark Lester, Henry J. Hood and Martha A. Burger dated as of
July 1, 1997. Incorporated herein by reference to Exhibit
10.2.9 to Registrant's annual report on Form 10-K for the
year ended December 31, 1998.
10.3+ -- Form of Indemnity Agreement for officers and directors of
Registrant and its subsidiaries. Incorporated herein by
reference to Exhibit 10.30 to Registrant's registration
statement on Form S-1 (No. 33-55600).
10.5 -- Rights Agreement dated July 15, 1998 between the Registrant
and UMB Bank, N.A., as Rights Agent. Incorporated herein by
reference to Exhibit 1 to Registrant's registration
statement on Form 8-A filed July 16, 1998. Amendment No. 1
dated September 11, 1998. Incorporated herein by reference
to Exhibit 10.3 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1998.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake
Energy Corporation and Chesapeake Operating, Inc.
Incorporated herein by reference to Exhibit 10.10 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.11 -- Amended and Restated Limited Partnership Agreement of
Chesapeake Louisiana, L.P. dated June 30, 1997 between
Chesapeake Operating, Inc. and Chesapeake Energy Louisiana
Corporation.
12* -- Computation of Ratios
21* -- Subsidiaries of Registrant
23.1* -- Consent of PricewaterhouseCoopers LLP
23.2* -- Consent of Williamson Petroleum Consultants, Inc.
23.3* -- Consent of Ryder Scott Company Petroleum Engineers
27* -- Financial Data Schedule
</TABLE>
- ----------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
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<PAGE> 75
(b) Reports on Form 8-K
During the quarter ended December 31, 1999, the Company filed the following
Current Reports on Form 8-K:
On November 1, 1999, the Company filed a current report on Form 8-K
reporting under Item 5 that the Company issued a press release announcing
record earnings and cash flow for the third quarter 1999.
On December 8, 1999, the Company filed a current report on Form 8-K
reporting under Item 5 that the Company issued a press release reporting an
increase in its Mid-Continent asset base with property acquisition and
completion of a significant discovery well.
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<PAGE> 76
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION
By /s/ AUBREY K. McCLENDON
------------------------
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
Date: March 30, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- -------------------------------------- -------------------------------------- --------------
<S> <C> <C>
/s/ AUBREY K. McCLENDON Chairman of the Board, Chief Executive March 30, 2000
- -------------------------------------- Officer and Director
Aubrey K. McClendon (Principal Executive Officer)
/s/ TOM L. WARD President, Chief Operating Officer and March 30, 2000
- -------------------------------------- Director
Tom L. Ward (Principal Executive Officer)
/s/ MARCUS C. ROWLAND Executive Vice President and Chief March 30, 2000
- -------------------------------------- Financial Officer
Marcus C. Rowland (Principal Financial Officer)
/s/ MICHAEL A. JOHNSON Senior Vice President - Accounting, March 30, 2000
- -------------------------------------- Controller and Chief Accounting Officer
Michael A. Johnson (Principal Accounting Officer)
/s/ EDGAR F. HEIZER, JR. Director March 30, 2000
- --------------------------------------
Edgar F. Heizer, Jr.
/s/ BREENE M. KERR Director March 30, 2000
- --------------------------------------
Breene M. Kerr
/s/ SHANNON T. SELF Director March 30, 2000
- --------------------------------------
Shannon T. Self
/s/ FREDERICK B. WHITTEMORE Director March 30, 2000
- --------------------------------------
Frederick B. Whittemore
/s/ WALTER C. WILSON Director March 30, 2000
- --------------------------------------
Walter C. Wilson
</TABLE>
<PAGE> 77
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <C>
3.1 -- Registrant's Certificate of Incorporation as amended.
Incorporated herein by reference to Exhibit 3.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235).
3.2 -- Registrant's Bylaws. Incorporated herein by reference to
Exhibit 3.2 to Registrant's registration statement on Form
8-B (No. 001-13726).
4.1 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, as Trustee, with respect to
7.875% Senior Notes due 2004. Incorporated herein by
reference to Exhibit 4.1 to Registrant's registration
statement on Form S-4 (No. 333-24995). First Supplemental
Indenture dated December 17, 1997 and Second Supplemental
Indenture dated February 16, 1998. Incorporated herein by
reference to Exhibit 4.1.1 to Registrant's transition
report on Form 10-K for the six months ended December 31,
1997. Second [Third] Supplemental Indenture dated April 22,
1998. Incorporated herein by reference to Exhibit 4.1.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.1.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.2 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, As Trustee, with respect to 8.5%
Senior Notes due 2012. Incorporated herein by reference to
Exhibit 4.1.3 to Registrant registration statement on Form
S-4 (No. 333-24995). First Supplemental Indenture dated
December 17, 1997 and Second Supplemental Indenture dated
February 16, 1998. Incorporated herein by reference to
Exhibit 4.2.1 to Registrant's transition report on Form
10-K for the six months ended December 31, 1997. Second
[Third] Supplemental Indenture dated April 22, 1998.
Incorporated herein by reference to Exhibit 4.2.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.2.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.3 -- Indenture dated as of April 1, 1998 among the Registrant,
as Subsidiary Guarantors, and United States Trust Company
of New York, As Trustee, with respect to 9.625% Senior
Notes due 2005. Incorporated herein by reference to Exhibit
4.3 to Registrant registration statement on Form S-3 (No.
333-57235). First Supplemental Indenture dated July 1,
1998. Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1998.
4.4 -- Indenture dated as of April 1, 1996 among the Registrant,
its subsidiaries signatory thereto, as Subsidiary
Guarantors, and United States Trust Company of New York, as
Trustee, with respect to 9.125% Senior Notes, due 2006.
Incorporated herein by reference to Exhibit 4.6 to
Registrant's registration
</TABLE>
<PAGE> 78
<TABLE>
<S> <C>
statement on Form S-3 (No. 333-1588). First Supplemental
Indenture dated December 30, 1996 and Second Supplemental
Indenture dated December 17, 1997. Incorporated herein by
reference to Exhibit 4.4.1 to Registrant's transition
report on Form 10-K for the six months ended December 31,
1997. Third Supplemental Indenture dated April 22, 1998.
Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.3.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.5 -- Agreement to furnish copies of unfiled long-term debt
Instruments. Incorporated herein by reference to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997.
4.11 -- Registration Rights Agreement as of April 22, 1998 among
the Registrant and Donaldson, Lufkin & Jenrette Securities
Corporation, Morgan Stanley & Co. Incorporated, Bear
Stearns & Co. Inc., Lehman Brothers Inc. and J.P. Morgan
Securities Inc., with respect to 7% Cumulative Convertible
Preferred Stock. Incorporated herein by reference to
Exhibit 4.11 to Registrant's quarterly report on Form 10-Q
for the quarter ended March 31, 1998.
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated
herein by reference to Exhibit 10.1.1 to Registrant's
registration statement on Form S-4 (No. 33-93718).
10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as
Amended. Incorporated herein by reference to Exhibit 10.1.2
to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1996.
10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended.
Incorporated herein by reference to Exhibit 10.1.3 to
Registrant's quarterly report on Form 10-Q for the quarter
ended December 31, 1996.
10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein
by reference to Registrant's Proxy Statement for its 1996
Annual Meeting of Shareholders and to Registrant's
quarterly report on Form 10-Q for the quarter ended
December 31, 1996.
10.1.5+ -- Registrant's 1999 Stock Option Plan. Incorporated herein
by reference to Exhibit 10.1.5 to Registrant's quarterly
report on Form 10-Q for the quarter ended June 30, 1999.
10.2.1+ -- First Amendment to the Amended and Restated Employment
Agreement dated as of December 31, 1998 between Aubrey K.
McClendon and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended June
30, 1999.
10.2.2+ -- First Amendment to the Amended and Restated Employment
Agreement dated as of December 31, 1998 between Tom L. Ward
and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.2 to Registrant's quarterly
report on Form 10-Q for the quarter ended June 30, 1999.
10.2.3+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Marcus C. Rowland and Chesapeake
Energy Corporation.
</TABLE>
<PAGE> 79
<TABLE>
<S> <C>
Incorporated herein by reference to Exhibit 10.2.3 to
Registrant's annual report on Form 10-K for the year ended
December 31, 1998.
10.2.4+ -- Employment Agreement dated as of July 1, 1997 between
Steven C. Dixon and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.4 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1997.
10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J.
Mark Lester and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.5 to Registrant's
annual report on Form 10-K for the year ended June 30,
1997.
10.2.6+ -- Employment Agreement dated as of July 1, 1997 between
Henry J. Hood and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.6 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.8+ -- Employment Agreement dated as of July 1, 1997 between
Martha A. Burger and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.9+ -- Amendment to Employment Agreements of Steven C. Dixon, J.
Mark Lester, Henry J. Hood and Martha A. Burger dated as of
July 1, 1997. Incorporated herein by reference to Exhibit
10.2.9 to Registrant's annual report on Form 10-K for the
year ended December 31, 1998.
10.3+ -- Form of Indemnity Agreement for officers and directors of
Registrant and its subsidiaries. Incorporated herein by
reference to Exhibit 10.30 to Registrant's registration
statement on Form S-1 (No. 33-55600).
10.5 -- Rights Agreement dated July 15, 1998 between the Registrant
and UMB Bank, N.A., as Rights Agent. Incorporated herein by
reference to Exhibit 1 to Registrant's registration
statement on Form 8-A filed July 16, 1998. Amendment No. 1
dated September 11, 1998. Incorporated herein by reference
to Exhibit 10.3 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1998.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake
Energy Corporation and Chesapeake Operating, Inc.
Incorporated herein by reference to Exhibit 10.10 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.11 -- Amended and Restated Limited Partnership Agreement of
Chesapeake Louisiana, L.P. dated June 30, 1997 between
Chesapeake Operating, Inc. and Chesapeake Energy Louisiana
Corporation.
12* -- Computation of Ratios
21* -- Subsidiaries of Registrant
23.1* -- Consent of PricewaterhouseCoopers LLP
23.2* -- Consent of Williamson Petroleum Consultants, Inc.
23.3* -- Consent of Ryder Scott Company Petroleum Engineers
27* -- Financial Data Schedule
</TABLE>
- ----------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
<PAGE> 1
EXHIBIT 12
<TABLE>
<CAPTION>
Year Six Months Year Year
Ended Ended Ended Ended
June 30, Dec 31, Dec 31, Dec 31,
1997 1997 1998 1999
-------- ---------- -------- --------
<S> <C> <C> <C> <C>
RATIO OF EARNINGS TO FIXED CHARGES
Income before income taxes and extraordinary item (180,330) (31,574) (920,520) 35,030
Interest 18,550 17,448 68,249 81,052
Preferred Stock Dividends -- -- 12,077 16,711
Bond discount amortization(a) -- -- -- --
Loan cost amortization 1,455 794 2,516 3,338
-------- -------- -------- --------
Earnings (160,325) (13,332) (837,678) 136,131
Interest expense 18,550 17,448 68,249 81,052
Capitalized interest 12,935 5,087 6,754 3,497
Preferred Stock Dividends -- -- 12,077 16,711
Bond discount amortization(a) -- -- -- --
Loan cost amortization 1,455 794 2,516 3,338
-------- -------- -------- --------
Fixed Charges 32,940 23,329 89,596 104,598
Ratio (4.9) (0.6) (9.3) 1.3
(A) Bond discount excluded since its included
in interest expense
Insufficient coverage 193,265 36,661 927,274 0
</TABLE>
Page 1
<PAGE> 1
EXHIBIT 21
SUBSIDIARIES OF CHESAPEAKE ENERGY CORPORATION
(AN OKLAHOMA CORPORATION)
Corporations State of Organization
- ------------ ---------------------
The Ames Company, Inc. Oklahoma
Arkoma Pittsburg Holding Corporation Oklahoma
Chesapeake Acquisition Corporation Oklahoma
Chesapeake Canada Corporation Alberta, Canada
Chesapeake Energy Louisiana Corporation Oklahoma
Chesapeake Energy Marketing, Inc. Oklahoma
Chesapeake Operating, Inc. Oklahoma
Chesapeake Royalty Company Oklahoma
Partnerships
- ------------
Chesapeake Exploration Limited Partnership Oklahoma
Chesapeake Louisiana, L.P. Oklahoma
Chesapeake Panhandle Limited Partnership Oklahoma
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (File Nos. 33-84256, 33-84258, 33-89282, 33-88196,
333-27525, 333-30478, 333-072555 and 333-30324) and Form S-3 (File No.
333-57235) of Chesapeake Energy Corporation of our report dated March 24, 2000
relating to the consolidated financial statements and financial statement
schedule, which appears in this Form 10-K.
PRICEWATERHOUSECOOPERS LLP
Oklahoma City, Oklahoma
March 24, 2000
<PAGE> 1
. EXHIBIT 23.2
CONSENT OF WILLIAMSON PETROLEUM CONSULTANTS, INC.
As independent oil and gas consultants, Williamson Petroleum
Consultants, Inc. hereby consents to (a) the use of our reserve report dated as
of December 31, 1999 and all references to our firm included in or made a part
of the Chesapeake Energy Corporation Annual Report on Form 10-K to be filed
with the Securities and Exchange Commission on or about March 30, 2000 and (b)
to the incorporation by reference of this Form 10-K for the year ended December
31, 1999 in the Registration Statements on Form S-8 (Nos. 33-84256, 33-84258,
33-88196, 333-07255, 33-89282, 333-27525, 333-46129, 333-48585, 333-30478 and
333-30324) and on Form S-3 (Nos. 333-50547 and 333-57235).
/s/ WILLIAMSON PETROLEUM CONSULTANTS, INC.
------------------------------------------
WILLIAMSON PETROLEUM CONSULTANTS, INC.
Midland, Texas
March 30, 2000
<PAGE> 1
EXHIBIT 23.3
CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINEERS
As independent oil and gas consultants, Ryder Scott Company Petroleum
Engineers hereby consents to (a) the use of our reserve report dated as of
December 31, 1999 and all references to our firm included in or made a part of
the Chesapeake Energy Corporation Annual Report on Form 10-K to be filed with
the Securities and Exchange Commission on or about March 30, 2000 and (b) to the
incorporation by reference of this Form 10-K for the year ended December 31,
1999 in the Registration Statements on Form S-8 (Nos. 33-84256, 33-84258,
33-88196, 333-07255, 33-89282, 333-27525, 333-46129, 333-48585, 333-30478, and
333-30324) and on Form S-3 (Nos. 333-50547 and 333-57235).
/s/ RYDER SCOTT COMPANY L.P.
----------------------------
RYDER SCOTT COMPANY L.P.
Houston, Texas
March 30, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BALANCE
SHEET AS OF DECEMBER 31, 1999, AND STATEMENT OF OPERATIONS FOR THE TWELVE MONTHS
ENDED DECEMBER 31, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 38,850
<SECURITIES> 0
<RECEIVABLES> 54,625
<ALLOWANCES> 3,218
<INVENTORY> 4,582
<CURRENT-ASSETS> 97,546
<PP&E> 2,423,068
<DEPRECIATION> 1,703,971
<TOTAL-ASSETS> 850,533
<CURRENT-LIABILITIES> 88,186
<BONDS> 964,097
0
229,820
<COMMON> 1,059
<OTHER-SE> (448,423)
<TOTAL-LIABILITY-AND-EQUITY> 850,533
<SALES> 354,946
<TOTAL-REVENUES> 363,508
<CGS> 247,426
<TOTAL-COSTS> 328,478
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 9
<INTEREST-EXPENSE> 81,052
<INCOME-PRETAX> 35,030
<INCOME-TAX> 1,764
<INCOME-CONTINUING> 33,266
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 33,266
<EPS-BASIC> 0.17
<EPS-DILUTED> 0.16
</TABLE>
