<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 7, 2000
REGISTRATION NO. 333-
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549,
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FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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CHESAPEAKE ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
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OKLAHOMA 1311 73-1395733
(State or Other Jurisdiction of (Primary Standard Industrial (I.R.S. Employer
Incorporation or Organization) Classification Code Number) Identification Number)
</TABLE>
6100 NORTH WESTERN AVENUE, OKLAHOMA CITY, OKLAHOMA 73118
(405) 848-8000
(Address, Including Zip Code, and Telephone Number, Including Area Code, of
Registrant's Principal Executive Offices)
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AUBREY K. MCCLENDON Copies to:
CHAIRMAN OF THE BOARD AND CONNIE S. STAMETS
CHIEF EXECUTIVE OFFICER WINSTEAD SECHREST & MINICK P.C.
6100 NORTH WESTERN AVENUE 5400 RENAISSANCE TOWER
OKLAHOMA CITY, OKLAHOMA 73118 1201 ELM STREET
(405) 848-8000 DALLAS, TEXAS 75270
(Name, Address, Including Zip Code, and (214) 745-5400
Telephone Number, Including Area Code,
of Agent for Service)
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO PUBLIC: As soon as
practicable after the effective date of this Registration Statement.
If any of the securities being registered on this form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]
If this form is filed to register additional securities for an offering pursuant
to Rule 462(b) under the Securities Act, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule 462(c) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule 462(d) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434, check
the following box. [ ]
CALCULATION OF REGISTRATION FEE
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<CAPTION>
==========================================================================================================================
TITLE OF EACH CLASS OF AMOUNT TO BE PROPOSED MAXIMUM OFFERING PROPOSED MAXIMUM AMOUNT OF
SECURITIES TO BE REGISTERED REGISTERED PRICE PER UNIT AGGREGATE OFFERING PRICE(1) REGISTRATION FEE
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<S> <C> <C> <C> <C>
Common Stock, par value
$0.01 per share 20,000,000 (1) $ 136,900,000 $ 36,142
==========================================================================================================================
</TABLE>
(1) Estimated solely for purposes of calculating the registration fee pursuant
to Rule 457(c) of the Securities Act of 1933, based on the average of the high
and low prices reported on the New York Stock Exchange on June 29, 2000 of
$6.845 per share.
The Registrant hereby amends this Registration Statement on such date or dates
as may be necessary to delay its effective date until the Registrant shall file
a further amendment which specifically states that this Registration Statement
shall thereafter become effective in accordance with Section 8(a) of the
Securities Act of 1933 or until the Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
<PAGE> 2
SUBJECT TO COMPLETION DATED JULY 7, 2000
PROSPECTUS
___________, 2000
CHESAPEAKE ENERGY CORPORATION
20,000,000 SHARES OF COMMON STOCK
The selling shareholders described in this prospectus may offer and
sell from time to time 9,468,985 shares of common stock they received in
connection with their sale of 14?% Series B Senior Secured Discount Notes due
2006 of Gothic Energy Corporation to our wholly owned subsidiary Chesapeake
Energy Marketing, Inc. CEMI acquired the Discount Notes on June 27, 2000 for a
combination of those shares and cash.
This prospectus also relates to shares of common stock we may issue in
connection with an adjustment to be made to the purchase price paid to the
selling shareholders for the Discount Notes. The adjustment will occur on ____
__, 2000 and may be settled in cash or common stock by the selling shareholders
or CEMI, as the case may be. The selling shareholders will receive additional
cash or shares of common stock only if the average trading price of the common
stock for the 30 calendar days following the date of this prospectus is less
than $5.825 per share.
Additional shares covered by this prospectus may be issued in
connection with future purchases by CEMI of other Gothic Energy Corporation
Discount Notes of the same series. Presently, approximately 4% of the series is
not held by CEMI.
We will not receive any proceeds from the sale of shares of common
stock by the selling shareholders, but we will bear all of the expenses, other
than commissions or discounts of broker-dealers.
On _________, 2000, the last reported sale price of the common stock
(symbol "CHK") on the New York Stock Exchange was __________.
SEE "RISK FACTORS" BEGINNING ON PAGE 3 FOR FACTORS THAT YOU SHOULD
CONSIDER BEFORE BUYING SHARES OF OUR COMMON STOCK.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
accuracy or adequacy of this prospectus. Any representation to the contrary is a
criminal offense.
<PAGE> 3
TABLE OF CONTENTS
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PAGE
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Forward-Looking Statements..................................................................2
The Company.................................................................................3
Risk Factors................................................................................3
Use of Proceeds.............................................................................7
Dividend Policy.............................................................................7
Market Price of Common Stock................................................................8
Selected Financial Data.....................................................................9
Management's Discussion and Analysis of Financial Condition and Results of Operations......11
Quantitative and Qualitative Disclosures About Market Risks................................17
Business...................................................................................19
Management.................................................................................31
Executive Compensation.....................................................................34
Certain Transactions.......................................................................39
Security Ownership.........................................................................41
Selling Shareholders.......................................................................43
Description of the Capital Stock...........................................................44
Plan of Distribution.......................................................................52
Legal Matters..............................................................................53
Experts....................................................................................53
Where You Can Find More Information About Us...............................................53
Glossary...................................................................................54
Index to Financial Statements.............................................................F-1
</TABLE>
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FORWARD-LOOKING STATEMENTS
This prospectus 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. Forward-looking statements include 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,
realization of deferred tax assets, the proposed acquisition of Gothic Energy
Corporation and the combined entity's future operations. Although we believe
that the expectations reflected in these and other forward-looking statements
are reasonable, we can give no assurance that our 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," are substantial indebtedness; impairment of
asset value; need to replace reserves; substantial capital requirements;
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; operating risks; restrictions imposed by
lenders; the effects of governmental and environmental regulation; pending
litigation; importance of our CEO and COO to Company operations and shareholder
votes and conflicts of interest they may have; and uncertainties relating to the
proposed business combination with Gothic. You are cautioned not to place undue
reliance on these forward-looking statements, which speak only as of the date of
this prospectus, and we undertake no obligation to update this information. You
are urged to review carefully and consider the various disclosures made by us in
this prospectus, in any subsequent prospectus supplement and in our other
reports filed with the Securities and Exchange Commission that attempt to advise
interested parties of the risks and factors that may affect our business.
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<PAGE> 4
THE COMPANY
Chesapeake Energy Corporation 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. We began operations in
1989 and completed our initial public offering in 1993. Our common stock trades
on the New York Stock Exchange under the symbol CHK. Our principal offices are
located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 (telephone
405/848-8000 and website address of www.chkenergy.com).
At year-end 1999, we owned interests in approximately 4,700 producing
oil and gas wells concentrated in three primary operating areas:
o the Mid-Continent region of Oklahoma, western Arkansas,
southwestern Kansas and the Texas Panhandle;
o the Gulf Coast region consisting primarily of the Austin
Chalk Trend in Texas and Louisiana and the Tuscaloosa Trend
in Louisiana; and
o the Helmet area of northeastern British Columbia.
During 1999, we produced 133.5 Bcfe, making Chesapeake one of the 15 largest
public independent oil and gas producers in the United States.
RECENT DEVELOPMENTS
On June 30, 2000, we entered into a letter of intent to acquire Gothic
Energy Corporation (OTC Bulletin Board "GOTH") for 4.0 million shares of common
stock. Upon the closing of the transaction, Gothic's shareholders will own
approximately 2.7% of Chesapeake's common stock. In addition, on June 27, 2000,
we purchased in a series of private transactions 96% of Gothic's $104 million of
14 1/8% Series B Senior Secured Discount Notes for consideration of $77 million,
comprised of $22 million in cash and 9,468,985 shares of Chesapeake common stock
(valued at $5.825 per share), subject to adjustment.
The total acquisition cost to Chesapeake will be approximately $345
million, including $235 million of Senior Secured Notes issued by Gothic's
operating subsidiary. This values Gothic's 310 Bcfe of proved reserves at $1.05
per Mcfe after allocation of $20 million of the purchase price to Gothic's
leasehold inventory, 3-D seismic inventory, lease operating telemetry system and
other assets. Gothic's proved reserves are 96% natural gas, 78% proved
developed, have an average lifting cost of less than $0.20 per Mcfe, are located
exclusively in Chesapeake's core Mid-Continent operating area and are unhedged
after October 2000. Based on its current production rate of 80,000 Mcfe per day
(or 30 Bcfe per year), Gothic has an 11-year reserves-to-production index.
Considering other announced transactions in the industry, we believe Chesapeake
will be the 10th largest independent producer of natural gas in the U.S. after
the transaction.
The Gothic acquisition is subject to the completion of definitive
documentation, normal regulatory approvals and a Gothic shareholder vote.
Completion of the transaction is expected by year-end 2000.
BUSINESS STRATEGY
From inception as a start-up in 1989 through today, our business
strategy has been to aggressively build and develop one of the largest onshore
natural gas resource bases in the U.S. We have executed our strategy through a
combination of active drilling and acquisition programs during the past 11
years.
RISK FACTORS
Before you invest in our common stock, you should be aware that there
are various risks. In addition to other information included in this prospectus
and any subsequent prospectus supplement, you should carefully consider the
following risk factors before you decide to purchase the common stock offered by
this prospectus.
3
<PAGE> 5
This prospectus contains statements that constitute forward-looking
statements. They include statements about the intent, belief or current
expectations of Chesapeake, our directors or our officers with respect to the
future operating performance of Chesapeake and the proposed business combination
with Gothic Energy Corporation. See "Business - Recent Developments."
Prospective purchasers of our common stock are cautioned that any such
forward-looking statements are not guaranties of future performance and involve
risks and uncertainties, and that actual results may differ materially from
those in the forward-looking statements as a result of various factors.
Information set forth below and elsewhere in this prospectus identifies
important factors that could cause such differences. See "Forward-Looking
Statements."
SUBSTANTIAL DEBT LEVELS COULD AFFECT OPERATIONS
As of March 31, 2000, we had long-term indebtedness of $960.4 million
(which included bank indebtedness of $40.0 million) and stockholders' equity was
a deficit of $196.6 million. Our ability to meet our debt service requirements
throughout the life of our 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
o our ability to obtain additional capital in the future may be
impaired.
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. 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.
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<PAGE> 6
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.
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, and the year ended June 30, 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 decline significantly, 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 March 31, 2000, we did not meet a debt incurrence test contained in
two of the senior note indentures. However, we did meet the debt incurrence test
as of June 30, 2000, and therefore are able to incur unsecured non-bank debt and
we are eligible to resume the payment of dividends on our preferred stock.
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 our audited consolidated
financial statements included at the end of this prospectus. Also, note 11 of
the audited consolidated financial statements provides disclosures about our
Canadian oil and gas producing activities. Our operations in
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<PAGE> 7
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,
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 June 30, 2000, Messrs. McClendon and Ward had payables to
Chesapeake of $1.5 million and $1.4 million, respectively, in connection with
such participation. 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 June 30, 2000, our Board of Directors and senior management
beneficially owned an aggregate of 24,659,514 shares of common stock (including
outstanding vested options), which represented approximately 17% of our
outstanding shares. The beneficial ownership of Messrs. McClendon and Ward
accounted for 15% 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.
THE PROPOSED ACQUISITION OF GOTHIC ENERGY CORPORATION MAY NOT OCCUR OR COULD BE
DELAYED
There are significant conditions to be satisfied before Chesapeake is
able to acquire Gothic as contemplated by the letter of intent they executed on
June 30, 2000. These conditions include the following:
o execution of a definitive merger agreement;
o filings under the Hart-Scott-Rodino Antitrust Improvements Act
and the expiration or termination of the waiting period;
o registration under the Securities Act of 1933 of the Chesapeake
common stock to be issued in the merger;
o approval of the merger by Gothic's shareholders; and
o the consent by any regulatory agencies or parties to existing
contracts deemed necessary by Chesapeake.
We cannot assure you that these conditions will be satisfied or, if
they are satisfied, that the terms and timing of each will be as presently
contemplated.
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THE TWO COMPANIES MAY NOT BE SUCCESSFULLY COMBINED INTO A SINGLE ENTITY
If we cannot successfully combine our operations, we may experience a
material adverse effect on our business, financial condition or results of
operations. The merger involves the combining of two companies that have
previously operated separately. The combining of companies such as Chesapeake
and Gothic involves a number of risks, including:
o the diversion of management's attention to the combining of
operations;
o difficulties in the combining of operations and systems;
o difficulties in the assimilation and retention of employees;
and
o potential adverse short-term effects on operating results.
We believe opportunities for economies of scale and scope,
opportunities for growth and operating efficiencies could result from the
merger. Because of difficulties in combining operations, however, we may not be
able to achieve the cost savings and other size-related benefits that we hope to
achieve after the merger.
USE OF PROCEEDS
We will not receive any proceeds from this offering. We are registering
our common stock on behalf of the selling shareholders. If and when the selling
shareholders sell their stock, they will receive the proceeds.
DIVIDEND POLICY
We paid quarterly dividends of $0.02 per share of common stock from
July 1997 to July 1998. The payment of future cash dividends on common stock, if
any, will be reviewed periodically by the Board of Directors and will depend
upon, among other things, our financial condition, funds from operations, the
level of capital and development expenditures, our future business prospects and
any contractual restrictions.
Two of the indentures governing our outstanding senior notes contain
restrictions on our ability to declare and pay dividends. Under these
indentures, the Company may not pay any cash dividends on its common or
preferred stock if
o 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;
o the Company would not be able to incur at least $1 of additional
indebtedness under the terms of the indentures; or
o 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 March 31, 2000, the Company did not meet
the debt incurrence tests under these indentures and was not able to pay
dividends on its common or preferred stock. The Company did meet the tests as of
June 30, 2000, and is therefore able to incur unsecured non-bank debt and is
eligible to resume the payment of dividends on our preferred stock.
During the first six months of 2000, we entered into a number of
unsolicited transactions whereby we issued approximately 34.2 million shares of
common stock, plus cash of $8.3 million, in exchange for 3,039,363 shares of
preferred stock. This reduced the liquidation amount of preferred stock
outstanding by $152.0 million to $77.9 million, and reduced the amount of
preferred dividends in arrears by $16.8 million to $9.5 million as of June 30,
2000.
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MARKET PRICE 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
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HIGH LOW
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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
Six months ended June 30, 2000:
First Quarter 3.31 1.94
Second Quarter 8.00 2.75
</TABLE>
At July 3, 2000 there were 1,076 holders of record of common stock and
approximately 24,234 beneficial owners.
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SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of
the Company for the three months ended March 31, 2000 and 1999, the twelve
months ended December 31, 1999, 1998 and 1997, the six-month transition period
ended December 31, 1997, the six months ended December 31, 1996 and the two
fiscal years ended June 30, 1997. The data are derived from the audited
consolidated financial statements of the Company, except for periods for the
three months ended March 31, 2000 and 1999, the year ended December 31, 1997 and
the six months ended December 31, 1996, which are derived from unaudited
consolidated financial statements of the Company. 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 this prospectus.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
------------------------
2000 1999
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($ IN THOUSANDS, EXCEPT PER
SHARE DATA)
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STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales ....................... $ 87,293 $ 51,806
Oil and gas marketing sales ............. 27,368 13,871
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Total revenues ..................... 114,661 65,677
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Operating costs:
Production expenses ..................... 12,545 13,992
Production taxes ........................ 5,216 1,990
General and administrative .............. 3,032 4,024
Oil and gas marketing expenses .......... 26,544 13,285
Oil and gas depreciation,
depletion and amortization .......... 24,483 23,153
Depreciation and amortization of
other assets .......................... 1,866 2,166
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Total operating costs .............. 73,686 58,610
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Income from operations ..................... 40,975 7,067
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Other income (expense):
Interest and other income ............... 1,192 873
Interest expense ........................ (20,864) (19,890)
--------- ---------
(19,672) (19,017)
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Income (loss) before income taxes .......... 21,303 (11,950)
Provision (benefit) for income taxes ....... 101 --
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Net income (loss) .......................... 21,202 (11,950)
Preferred stock dividends .................. (4,042) (4,026)
Gain on redemption of preferred stock ...... 10,414 --
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Net income (loss) available to common
shareholders .......................... $ 27,574 $ (15,976)
========= =========
Earnings (loss) per common share:
Basic ................................. $ 0.27 $ (0.17)
Assuming Dilution ..................... $ 0.15 $ (0.17)
Cash dividends declared per common share ..... $ -- $ --
CASH FLOW DATA:
Cash provided by operating activities before
changes in working capital ............ $ 47,692 $ 13,468
Cash provided by operating activities ...... 38,215 26,298
Cash used in investing activities .......... (46,890) (45,831)
Cash used in financing activities .......... (3,274) --
Effect of exchange rate changes on cash .... (478) 816
BALANCE SHEET DATA (at end of period):
Total assets ............................... $ 865,371 N/A
Long-term debt, net of current maturities .. 960,416 N/A
Stockholders' equity (deficit) ............. (196,590) N/A
</TABLE>
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<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS ENDED YEARS ENDED
DECEMBER 31, DECEMBER 31, JUNE 30,
--------------------------------- --------------------- ---------------------
1999 1998 1997 1997 1996 1997 1996
--------- --------- --------- --------- --------- --------- ---------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales...................... $ 280,445 $ 256,887 $ 198,410 $ 95,657 $ 90,167 $ 192,920 $ 110,849
Oil and gas marketing sales............ 74,501 121,059 104,394 58,241 30,019 76,172 28,428
Oil and gas service operations......... -- -- -- -- -- -- 6,314
--------- --------- --------- --------- --------- --------- ---------
Total revenues.................... 354,946 377,946 302,804 153,898 120,186 269,092 145,591
--------- --------- --------- --------- --------- --------- ---------
Operating costs:
Production expenses.................... 46,298 51,202 14,737 7,560 4,268 11,445 6,340
Production taxes....................... 13,264 8,295 4,590 2,534 1,606 3,662 1,963
General and administrative............. 13,477 19,918 10,910 5,847 3,739 8,802 4,828
Oil and gas marketing expenses......... 71,533 119,008 103,819 58,227 29,548 75,140 27,452
Oil and gas service operations......... -- -- -- -- -- -- 4,895
Oil and gas depreciation,
depletion and amortization......... 95,044 146,644 127,429 60,408 36,243 103,264 50,899
Depreciation and amortization of
other assets........................ 7,810 8,076 4,360 2,414 1,836 3,782 3,157
Impairment of oil and gas properties... -- 826,000 346,000 110,000 -- 236,000 --
Impairment of other assets............. -- 55,000 -- -- -- -- --
--------- --------- --------- --------- --------- --------- ---------
Total operating costs............. 247,426 1,234,143 611,845 246,990 77,240 442,095 99,534
--------- --------- --------- --------- --------- --------- ---------
Income (loss) from operations............. 107,520 (856,197) (309,041) (93,092) 42,946 (173,003) 46,057
--------- --------- --------- --------- --------- --------- ---------
Other income (expense):
Interest and other income.............. 8,562 3,926 87,673 78,966 2,516 11,223 3,831
Interest expense....................... (81,052) (68,249) (29,782) (17,448) (6,216) (18,550) (13,679)
--------- --------- --------- --------- --------- --------- ---------
(72,490) (64,323) 57,891 61,518 (3,700) (7,327) (9,848)
--------- --------- --------- --------- --------- --------- ---------
Income (loss) before income taxes
and extraordinary item............... 35,030 (920,520) (251,150) (31,574) 39,246 (180,330) 36,209
Provision (benefit) for income taxes...... 1,764 -- (17,898) -- 14,325 (3,573) 12,854
--------- --------- --------- --------- --------- --------- ---------
Income (loss) before extraordinary item... 33,266 (920,520) (233,252) (31,574) 24,921 (176,757) 23,355
Extraordinary item:
Loss on early extinguishment of
debt, net of applicable income taxes -- (13,334) (177) -- (6,443) (6,620) --
--------- --------- --------- --------- --------- --------- ---------
Net income (loss)......................... 33,266 (933,854) (233,429) (31,574) 18,478 (183,377) 23,355
Preferred stock dividends................. (16,711) (12,077) -- -- -- -- --
--------- --------- --------- --------- --------- --------- ---------
Net income (loss) available to
common shareholders.................. $ 16,555 $(945,931) $(233,429) $ (31,574) $ 18,478 $(183,377) $ 23,355
========= ========= ========= ========= ========= ========= =========
Earnings (loss) per common share -
Basic:
Income (loss) before extraordinary
item................................. $ 0.17 $ (9.83) $ (3.30) $ (0.45) $ 0.40 $ (2.69) $ 0.43
Extraordinary item........................ -- (0.14) -- -- (0.10) (0.10) --
--------- --------- --------- --------- --------- --------- ---------
Net income (loss)......................... $ 0.17 $ (9.97) $ (3.30) $ (0.45) $ 0.30 $ (2.79) $ 0.43
========= ========= ========= ========= ========= ========= =========
Earnings (loss) per common share -
Assuming dilution:
Income (loss) before extraordinary item... $ 0.16 $ (9.83) $ (3.30) $ (0.45) $ 0.38 $ (2.69) $ 0.40
Extraordinary item........................ -- (0.14) -- -- (0.10) (0.10) --
--------- --------- --------- --------- --------- --------- ---------
Net income (loss)......................... $ 0.16 $ (9.97) $ (3.30) $ (0.45) $ 0.28 $ (2.79) $ 0.40
========= ========= ========= ========= ========= ========= =========
Cash dividends declared
per common share..................... $ -- $ 0.04 $ 0.06 $ 0.04 $ -- $ 0.02 $ --
CASH FLOW DATA:
Cash provided by operating
activities before changes in
working capital...................... $ 138,727 $ 117,500 $ 152,196 $ 67,872 $ 76,816 $ 161,140 $ 88,431
Cash provided by
operating activities................. 145,022 94,639 181,345 139,157 41,901 84,089 120,972
Cash used in investing activities......... 159,773 548,050 476,209 136,504 184,149 523,854 344,389
Cash provided by (used in)
financing activities................. 18,967 363,797 277,985 (2,810) 231,349 512,144 219,520
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 $ 949,068 $ 572,335
Long-term debt, net of current
maturities........................... 964,097 919,076 508,992 508,992 220,149 508,950 268,431
Stockholders' equity (deficit)............ (217,544) (248,568) 280,206 280,206 484,062 286,889 177,767
</TABLE>
10
<PAGE> 12
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>
THREE MONTHS ENDED YEARS ENDED
MARCH 31, DECEMBER 31,
-------------------------- -----------------------------------------
2000 1999 1999 1998 1997
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (MBbl)................................. 864 1,273 4,147 5,976 3,511
Gas (MMcf)................................. 28,747 25,674 108,610 94,421 59,236
Gas equivalent (MMcfe)..................... 33,931 33,312 133,492 130,277 80,302
OIL AND GAS SALES ($ IN 000'S):
Oil........................................ $ 21,237 $ 13,902 $ 66,413 $ 75,877 $ 68,079
Gas........................................ 66,056 37,904 214,032 181,010 130,331
----------- ----------- ----------- ----------- -----------
Total oil and gas sales............ $ 87,293 $ 51,806 $ 280,445 $ 256,887 $ 198,410
=========== =========== =========== =========== ===========
AVERAGE SALES PRICE:
Oil ($ per Bbl)............................ $ 24.58 $ 10.92 $ 16.01 $ 12.70 $ 19.39
Gas ($ per Mcf)............................ $ 2.30 $ 1.48 $ 1.97 $ 1.92 $ 2.20
Gas equivalent ($ per Mcfe)................ $ 2.57 $ 1.56 $ 2.10 $ 1.97 $ 2.47
OIL AND GAS COSTS ($ PER MCFE):
Production expenses and taxes.............. $ .52 $ .48 $ .45 $ .45 $ .24
General and administrative................. $ .09 $ .12 $ .10 $ .15 $ .14
Depreciation, depletion and amortization... $ .72 $ .70 $ .71 $ 1.13 $ 1.59
</TABLE>
RESULTS OF OPERATIONS
Three Months Ended March 31, 2000 and March 31, 1999
General. For the three months ended March 31, 2000 (the "Current
Quarter"), the Company realized net income of $21.2 million, or $0.15 per
diluted common share. This compares to a net loss of $12.0 million, or a loss of
$0.17 per diluted common share, in the three months ended March 31, 1999 (the
"Prior Quarter"). The loss in the Prior Quarter was primarily caused by low oil
and gas prices.
Oil and Gas Sales. During the Current Quarter, oil and gas sales
increased 69% to $87.3 million from $51.8 million in the Prior Quarter. For the
Current Quarter, the Company produced 33.9 billion cubic feet equivalent
("bcfe"), consisting of 0.9 million barrels of oil ("mmbo") and 28.7 billion
cubic feet of natural gas ("bcf"), compared to 1.3 mmbo and 25.7 bcf, or 33.3
bcfe, in the Prior Quarter. Average oil prices realized were $24.58 per barrel
of oil ("bo") in the Current Quarter compared to $10.92 per bo in the Prior
Quarter, an increase of 125%. Average gas prices realized were $2.30 per
thousand cubic feet ("mcf") in the Current Quarter compared to $1.48 per mcf in
the Prior Quarter, an increase of 55%.
For the Current Quarter, the Company realized an average price of $2.57
per thousand cubic feet equivalent ("mcfe"), compared to $1.56 per mcfe in the
Prior Quarter. The Company's hedging activities resulted in decreased oil and
gas revenues of $2.2 million, or $0.06 per mcfe, in the Current Quarter,
compared to increases in oil and gas revenues of $0.3 million, or $0.01 per
mcfe, in the Prior Quarter.
The following table shows the Company's production by region for the
Current Quarter and the Prior Quarter:
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED MARCH 31,
----------------------------------------
2000 1999
-------------------- -----------------
OPERATING AREAS (MMcfe) PERCENT (MMcfe) PERCENT
----------------------------------------- -------- ------- ------- -------
<S> <C> <C> <C> <C>
Mid-Continent............................ 18,772 55% 16,184 49%
Gulf Coast............................... 10,182 30 11,400 34
Canada................................... 2,925 9 2,431 7
Other Areas.............................. 2,052 6 3,297 10
-------- --- ------ ---
Total.............................. 33,931 100% 33,312 100%
======== === ====== ===
</TABLE>
Natural gas production represented approximately 85% of the Company's
total production volume on an equivalent basis in the Current Quarter, compared
to 77% in the Prior Quarter.
11
<PAGE> 13
Oil and Gas Marketing Sales. The Company realized $27.4 million in oil
and gas marketing sales for third parties in the Current Quarter, with
corresponding oil and gas marketing expenses of $26.5 million, for a margin of
$0.9 million. This compares to sales of $13.9 million, expenses of $13.3
million, and a margin of $0.6 million in the Prior Quarter. The increase in
marketing sales and cost of sales was due primarily to higher oil and gas prices
in the Current Quarter as compared to the Prior Quarter.
Production Expenses. Production expenses decreased to $12.5 million in
the Current Quarter, a $1.5 million decrease from the $14.0 million of
production expenses incurred in the Prior Quarter. On a unit of production
basis, production expenses were $0.37 and $0.42 per mcfe in the Current and
Prior Quarters, respectively. The decrease in production expenses between
periods is due primarily to the sale of certain oil and gas properties with high
per-unit operating costs as well as other cost cutting measures such as staff
reductions and office closings. The Company anticipates production expenses will
not vary significantly from current levels during the remainder of 2000.
Production Taxes. Production taxes, which consist primarily of wellhead
severance taxes, were $5.2 million and $2.0 million in the Current and Prior
Quarters, respectively. On a per unit basis, production taxes were $0.15 per
mcfe in the Current Quarter compared to $0.06 per mcfe in the Prior Quarter. The
increase in the Current Quarter is due to higher oil and gas prices. In general,
production taxes are calculated using value-based formulas that produce higher
per unit costs when oil and gas prices are higher.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization of oil and gas properties ("DD&A") for the Current
Quarter was $24.5 million, compared to $23.2 million in the Prior Quarter. The
DD&A rate per mcfe increased from $0.70 in the Prior Quarter to $0.72 in the
Current Quarter. The Company expects DD&A will increase moderately from current
levels during the remainder of 2000.
Depreciation and Amortization of Other Assets. Depreciation and
amortization of other assets ("D&A") was $1.9 million in the Current Quarter
compared to $2.2 million in the Prior Quarter. The Company anticipates D&A will
continue at current levels during the remainder of 2000.
General and Administrative. General and administrative expenses
("G&A"), which are net of capitalized internal payroll and non-payroll expenses,
were $3.0 million in the Current Quarter compared to $4.0 million in the Prior
Quarter. The decrease was due primarily to various actions taken to lower
corporate overhead, including staff reduction and office closings, which
occurred throughout 1999, and an increase in capitalized internal costs between
periods. The Company capitalized $1.9 million of internal costs in the Current
Quarter directly related to the Company's oil and gas exploration and
development efforts, compared to $1.2 million in the Prior Quarter. The Company
anticipates that G&A costs during the remainder of 2000 will remain at
approximately the same level as the Current Quarter.
Interest and Other Income. Interest and other income for the Current
Quarter was $1.2 million compared to $0.9 million in the Prior Quarter.
Interest Expense. Interest expense increased to $20.9 million in the
Current Quarter from $19.9 million in the Prior Quarter. In addition to the
interest expense reported, the Company capitalized $0.7 million of interest
during the Current Quarter compared to $1.1 million capitalized in the Prior
Quarter.
Provision for Income Taxes. The Company recorded income tax expense of
$0.1 million for the Current Quarter and none in the Prior Quarter. The income
tax expense recorded in the Current Quarter is related to the Company's Canadian
operations. At March 31, 2000, the Company had a net operating loss carryforward
of approximately $636 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 generated for U.S. income tax purposes, comprised primarily of
the net operating loss carryforward, will be realizable in future years, and
therefore a valuation allowance of $434 million has been recorded.
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
12
<PAGE> 14
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.
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
13
<PAGE> 15
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 ($1.17 in U.S. and $0.43 in
Canada) and $1.59 in 1999, 1998 and 1997, respectively. The Company did not have
operations in Canada prior to 1998. 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.
14
<PAGE> 16
LIQUIDITY AND CAPITAL RESOURCES
Financial Flexibility and Liquidity
The Company had working capital of $11.4 million at March 31, 2000 and
a cash balance of $29.3 million. The Company has a $75 million revolving bank
credit facility, which matures in July 2002, with a committed borrowing base of
$75 million. As of June 30, 2000, the Company had borrowed $63.0 million under
this facility. Borrowings under the facility are secured by certain producing
oil and gas properties and bear interest at variable rates, which averaged 10.0%
per annum as of June 30, 2000. The Company has received a commitment from its
bank to increase the borrowing base to $100 million. It is expected that the
addition to the borrowing base will be available to the Company in August 2000.
At March 31, 2000, the Company's senior notes represented $919.2
million of its $960.4 million of long-term debt. Debt ratings for the senior
notes are B2 by Moody's Investors Service and B by Standard & Poor's Corporation
as of June 30, 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. This restriction does
not affect the Company's ability to borrow under or expand its secured
commercial bank facility. As of March 31, 2000, the Company estimates that
secured commercial bank indebtedness of $149 million could have been incurred
under the indentures. 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 March
31, 2000, 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 $20.3 million related to its preferred stock as of March
31, 2000. Including accrued dividends from April 1 through June 30, 2000, this
amount has subsequently been reduced to approximately $9.5 million as of June
30, 2000 as a result of stock exchange transactions described below. The Company
was unable to pay a dividend on the preferred stock on May 1, 2000, the sixth
consecutive dividend payment date on which dividends have not been paid. If the
Company fails to pay dividends for six quarterly periods, the holders of
preferred stock are entitled to elect two new directors to the Board. Based on
current projections of cash flow and fixed charges, the Company expects to be
able to pay a dividend on the preferred stock on August 1, 2000, although there
are no assurances the Board of Directors will declare a dividend, even if the
Company is able to resume paying dividends.
Between January 1 and March 31, 2000, the Company engaged in a number
of separate stock exchange transactions with institutional investors. The
Company exchanged a total of 9.5 million shares of common stock (both newly
issued and treasury shares) for 675,000 shares of its issued and outstanding
preferred stock with a liquidation value of $33.8 million plus dividends in
arrears of $3.2 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.
Between April 1 and June 30, 2000, the Company engaged in additional
transactions in which a total of 24.7 million shares of common stock, plus cash
of $8.3 million, were exchanged for 2,364,363 shares of its issued and
outstanding preferred stock with a liquidation value of $118.2 million plus
dividends in arrears of $13.6 million. Including the stock exchange transactions
through June 30, 2000, a total of 34.2 million shares of common stock have been
exchanged for 3,039,363 shares of preferred stock. These transactions have
reduced (i) the number of preferred shares from 4.6 million to 1.6 million, (ii)
the liquidation value of the preferred stock from $229.8 million to $77.9
million, and (iii) dividends in arrears from $25.0 million to $9.5 million. A
gain on redemption of all preferred shares exchanged through June 30, 2000 of
$11.9 million ($10.4 million related to the quarter ended March 31, 2000) will
be reflected in net income available to common shareholders in determining
earnings per share.
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-$150 million. However, low oil and gas prices or unfavorable drilling
results could cause the Company to reduce its drilling
15
<PAGE> 17
program, which is largely discretionary. Based on current oil and gas prices,
the Company expects to generate excess cash flow that will be available to fund
acquisitions, reduce debt, make preferred stock dividend payments, or a
combination of the above.
Three Months Ended March 31, 2000 and 1999
Cash Flows from Operating Activities. The Company's cash provided by
operating activities increased 45% to $38.2 million during the Current Quarter
compared to $26.3 million during the Prior Quarter. The increase was due
primarily to higher oil and gas prices realized during the Current Quarter.
Cash Flows from Investing Activities. Cash used in investing activities
increased to $46.9 million during the Current Quarter from $45.8 million in the
Prior Quarter. During the Current Quarter the Company expended approximately
$34.8 million to initiate drilling on 51 gross (27.7 net) wells and invested
approximately $5.4 million in leasehold acquisitions. This compares to $40.2
million to initiate drilling on 41 gross (25.6 net) wells and $4.4 million to
purchase leasehold in the Prior Quarter. During the Current Quarter, the Company
had acquisitions of oil and gas properties of $4.6 million and divestitures of
oil and gas properties of $1.0 million. This compares to acquisitions of $4.0
million and divestitures of $2.1 million in the Prior Quarter.
Cash Flows from Financing Activities. There was $3.3 million of cash
used in financing activities in the Current Quarter, compared to none in the
Prior Quarter. The activity in the Current Quarter reflects the net reduction in
borrowings under the Company's commercial bank credit facility of $3.5 million,
partially offset by cash received through the exercise of stock options.
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.
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.
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
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 and FAS 138) is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000.
16
<PAGE> 18
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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
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 March 31, 2000, 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 March 2000:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBtu) (PER MMBtu)
------ --------- ------------
<S> <C> <C>
April 2000............................................................. 8,900,000 $ 2.59
May 2000............................................................... 3,410,000 2.74
June 2000.............................................................. 3,300,000 2.74
July 2000.............................................................. 3,410,000 2.74
August 2000............................................................ 3,410,000 2.74
September 2000......................................................... 2,100,000 2.70
October 2000........................................................... 2,170,000 2.70
</TABLE>
If the swap arrangements listed above had been settled on March 31,
2000, the Company would have incurred a loss of $7.0 million. Subsequent to
March 31, 2000 the Company settled the natural gas swaps for April and May 2000.
A loss of $2.7 million and $1.2 million will be recognized as price adjustments
in April and May, respectively. Additionally, the Company has closed certain of
its natural gas swaps that were open at March 31, 2000. The Company has closed
hedges on 5,530,000 MMBTU and will recognize a loss of $1.8 million, which will
be recognized as price adjustments, from June through October, 2000.
17
<PAGE> 19
As of March 31, 2000, the Company had the following open crude oil swap
arrangement designed to hedge a portion of the Company's domestic crude oil
production for periods after March 2000:
<TABLE>
<CAPTION>
MONTHLY VOLUME NYMEX-INDEX STRIKE
MONTHS (Bbls) PRICE (PER Bbl)
------ -------------- ------------------
<S> <C> <C>
April 2000............................................................. 89,000 $ 27.251
</TABLE>
If the swap arrangement listed above had been settled on March 31,
2000, the Company would have incurred a loss of $67,000.
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, $1.7 million as of March 31, 2000,
will be recognized as price adjustments in the months of related production.
These hedging gains and losses are set forth below ($ in thousands):
<TABLE>
<CAPTION>
HEDGING GAINS (LOSSES)
-------------------------------------------------
MONTH GAS OIL TOTAL
----- ------- ---------- ----------
<S> <C> <C> <C>
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
------- ---------- ---------
$ 505 $ (2,193) $ (1,688)
======= ========== =========
</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 has reduced
its interest expense by $2.7 million from May 1998 through December 1999. During
the Current Quarter, the Company's interest rate swap resulted in a $147,000
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% Three-month LIBOR (USD) 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 interest rate swap agreement contains a
"knockout provision" whereby the agreement will terminate on or after May 1,
2001 if the average closing price for the previous twenty business days for the
shares of the Company's common stock is greater than or equal to $7.50 per
share. The agreement also provides for a maximum floating rate of 8.5% from May
2001 through April 2008.
If the interest rate swap agreement had been settled on March 31, 2000,
the Company would have been required to pay the counterparty approximately $16.7
million. However, because of the knock-out provision discussed above and the
volatility of interest rates, the Company does not believe that this worst-case
scenario is a fair measure of the market value of the swap agreement and,
therefore, would not pay this amount to cancel the transaction. Results from
interest rate hedging transactions are reflected as adjustments to interest
expense in the corresponding months covered by the swap agreement.
The table below presents principal cash flows and related weighted
average interest rates by expected maturity dates. The fair value of the
long-term debt has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
MARCH 31, 2000
-----------------------------------------------------------------------------------
YEARS OF MATURITY
-----------------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
------ ------ ------ ------ -------- ---------- ------- ----------
($ IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES:
Long-term debt, including current
portion - fixed rate........... $ 0.6 $ 0.8 $ 0.6 $ -- $ 150.0 $ 770.0 $ 922.0 $ 827.4
Average interest rate............ 9.1% 9.1% 9.1% -- 7.9% 9.3% 9.1% --
Long-term debt - variable rate...... $ -- $ -- $ 40.0 $ -- $ -- $ -- $ 40.0 $ 40.0
Average interest rate............ -- -- 9.4% -- -- -- 9.4% --
</TABLE>
18
<PAGE> 20
BUSINESS
GENERAL
Chesapeake Energy Corporation 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. We began
operations in 1989 and completed our initial public offering in 1993. Our 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
www.chkenergy.com).
At year-end 1999, Chesapeake owned interests in approximately 4,700
producing oil and gas wells concentrated in three primary operating areas:
o the Mid-Continent region of Oklahoma, western Arkansas,
southwestern Kansas and the Texas Panhandle;
o the Gulf Coast region consisting primarily of the Austin Chalk
Trend in Texas and Louisiana and the Tuscaloosa Trend in
Louisiana; and
o the Helmet area of northeastern British Columbia.
During 1999, we produced 133.5 Bcfe, making Chesapeake one of the 15 largest
public independent oil and gas producers in the United States. We participated
in 211 gross (119.7 net) wells, 135 of which were Company operated. A summary of
the Company's 1999 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 audited consolidated financial
statements).
For 2000, we have established a capital expenditure budget of $170-$190
million, including approximately $130-$150 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.
RECENT DEVELOPMENTS
On June 30, 2000, we entered into a letter of intent to acquire Gothic
Energy Corporation (OTC Bulletin Board "GOTH") for 4.0 million shares of common
stock. Following the transaction, Gothic's shareholders will own approximately
2.7% of Chesapeake's common stock. In addition, on June 27, 2000, we purchased
in a series of private transactions 96% of Gothic's $104 million of 14 1/8%
Series B Senior Secured Discount Notes for consideration of $77 million,
comprised of $22 million in cash and 9,468,985 shares of Chesapeake common stock
(valued at $5.825 per share), subject to adjustment.
The total acquisition cost to Chesapeake will be approximately $345
million, including $235 million of Senior Secured Notes issued by Gothic's
operating subsidiary. This values Gothic's 310 Bcfe of proved reserves at $1.05
per Mcfe after allocation of $20 million of the purchase price to Gothic's
leasehold inventory, 3-D seismic inventory, lease operating telemetry system and
other assets. Gothic's proved reserves are 96% natural gas, 78% proved
developed, have an average lifting cost of less than $0.20 per Mcfe, are located
exclusively in Chesapeake's core Mid-Continent operating area and are unhedged
after October 2000. Based on its current production rate of 80,000 Mcfe per day
(or 30 Bcfe per year), Gothic has an 11-year reserves-to-production index.
19
<PAGE> 21
Gothic's previously announced plan of restructuring, which contemplated
the redemption of Chesapeake's holdings of Gothic's preferred and common stock
for oil and gas properties and other considerations, the exchange of the $104
million Senior Discount Note issue for 94% of Gothic's equity and an equity
rights offering of $15 million, has been terminated in anticipation of this
transaction.
Gothic presently has 18.6 million common shares outstanding, plus
employee and director options of 4.4 million shares. Of the outstanding shares,
Chesapeake owns 2.4 million shares and will not participate in the exchange for
the 4.0 million Chesapeake common shares to be received by Gothic's other
shareholders. Gothic's management and directors have agreed to vote in favor of
the agreement.
The Gothic acquisition is subject to the execution of a definitive
merger agreement, normal regulatory approvals and a Gothic shareholder vote.
Completion of the transaction is expected by year-end 2000. Chesapeake will
record the transaction using purchase accounting. Gothic has agreed to provide
Chesapeake with a $10 million break-up fee in the event the transaction is not
completed. Bear, Stearns & Co., Inc. advised Chesapeake and CIBC World Markets
advised Gothic.
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.
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. During 1999,
the Company invested approximately $22 million to drill 10 gross (3.7 net) wells
in the Gulf Coast.
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 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.
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.
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 L.P. 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.
20
<PAGE> 22
<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
-------------------------- ----------- ----------- -----------
<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.
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.
The following table sets forth the Company's estimated proved reserves
by area and the related 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 $2.25 per Mcf of gas):
21
<PAGE> 23
<TABLE>
<CAPTION>
PERCENT PRESENT
GAS OF VALUE
OIL GAS EQUIVALENT PROVED (DISC. @ 10%)
(MBbl) (MMcf) (MMcfe) RESERVES ($ 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. See note 11 of notes to consolidated
financial statements for other disclosures about the Company's oil and gas
producing activities.
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>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
-------------------------------------- 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:
22
<PAGE> 24
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
------------------------------ 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 $0.24 per Mcfe, respectively.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated:
<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS
DECEMBER 31, ENDED YEAR ENDED
--------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
---------- ---------- ------------ ----------
($ 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>
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
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<PAGE> 25
Pipeline Corporation of $31.5 million accounted for more than 10% of the
Company's total oil and gas sales. Management believes that the loss of this
customer would not have a material adverse effect on the Company's results of
operations or its financial position.
Sales to individual customers constituting 10% or more of total oil and
gas sales were as follows from July 1, 1996 to December 31, 1999:
<TABLE>
<CAPTION>
PERCENT OF
YEAR ENDED DECEMBER 31, AMOUNT OIL AND GAS SALES
---------------------------------------------------------- ---------------- -----------------
($ 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.
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 "Quantitative and Qualitative Disclosures About Market Risk."
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
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
24
<PAGE> 26
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 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.
25
<PAGE> 27
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 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
26
<PAGE> 28
items but does not believe compliance with TSCA has had 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.
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 427 full-time employees as of June 30, 2000. No
employees are represented by organized labor unions. The Company considers its
employee relations to be good.
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
Dickinson, North Dakota. The Company also has leased office space in College
Station, Texas; Wichita, Kansas; and Calgary, Alberta, Canada, which has been
sub-leased.
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<PAGE> 29
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. Plaintiffs have filed a motion to amend their
consolidated complaint but no appeal has been filed.
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 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
28
<PAGE> 30
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; no trial
dates have 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 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
appealed and posted supersedeas bonds.
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.
29
<PAGE> 31
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.
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.
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.
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 payment
issues remain. A jury trial is set to commence August 21, 2000.
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.
30
<PAGE> 32
MANAGEMENT
INFORMATION REGARDING DIRECTORS
Aubrey K. McClendon, age 40, has served as Chairman of the Board, Chief
Executive Officer and a director since co-founding the Company in 1989. From
1982 to 1989, Mr. McClendon was an independent producer of oil and gas in
affiliation with Tom L. Ward, the Company's President and Chief Operating
Officer. Mr. McClendon is a member of the Board of Visitors of the Fuqua School
of Business at Duke University. Mr. McClendon is a 1981 graduate of Duke
University.
Tom L. Ward, age 40, has served as President, Chief Operating Officer
and a director of the Company since co-founding the Company in 1989. From 1982
to 1989, Mr. Ward was an independent producer of oil and gas in affiliation with
Aubrey K. McClendon, the Company's Chairman and Chief Executive Officer. Mr.
Ward is a member of the Board of Trustees of Anderson University in Anderson,
Indiana. Mr. Ward graduated from the University of Oklahoma in 1981.
Breene M. Kerr, age 71, has been a director of the Company since 1993.
He is President of Brookside Company, Easton, Maryland. In 1969, Mr. Kerr
founded Kerr Consolidated, Inc., which was sold in 1996. In 1969, Mr. Kerr
co-founded the Resource Analysis and Management Group and remained its senior
partner until 1982. From 1967 to 1969, he was Vice President of Kerr-McGee
Chemical Corporation. From 1951 through 1967, Mr. Kerr worked for Kerr-McGee
Corporation as a geologist and land manager. Mr. Kerr has served as chairman of
the Investment Committee for the Massachusetts Institute of Technology and is a
life member of the Corporation (Board of Trustees) of that university. He served
as a director of Kerr-McGee Corporation from 1957 to 1981. Mr. Kerr currently is
a trustee of the Brookings Institution in Washington, D.C., and has been an
associate director since 1987 of Aven Gas & Oil, Inc., an oil and gas property
management company located in Oklahoma City. Mr. Kerr graduated from the
Massachusetts Institute of Technology in 1951.
Edgar F. Heizer, Jr., age 70, has been a director of the Company since
1993. From 1985 to the present, Mr. Heizer has been a private venture
capitalist. He founded Heizer Corporation, a publicly traded business
development company, in 1969 and served as Chairman and Chief Executive Officer
from 1969 until 1986, when Heizer Corporation was reorganized into a number of
public and private companies. Mr. Heizer was Assistant Treasurer of the Allstate
Insurance Company from 1962 to 1969 in charge of Allstate's venture capital
operations. He was employed by Booz, Allen and Hamilton from 1958 to 1962,
Kidder, Peabody & Co. from 1956 to 1958, and Arthur Andersen & Co. from 1954 to
1956. He serves on the advisory board of the Kellogg School of Management at
Northwestern University. Mr. Heizer is a director of Material Science
Corporation, a New York Stock Exchange listed company in Elk Grove, Illinois,
and several private companies. Mr. Heizer graduated from Northwestern University
in 1951 and from Yale University Law School in 1954.
Frederick B. Whittemore, age 69, has been a director of the Company
since 1993. Mr. Whittemore has been an advisory director of Morgan Stanley Dean
Witter & Co. since 1989 and was a managing director or partner of the
predecessor firms of Morgan Stanley Dean Witter & Co. from 1967 to 1989. He was
Vice-Chairman of the American Stock Exchange from 1982 to 1984. Mr. Whittemore
is a director of Partner Reinsurance Company, Bermuda; Maxcor Financial Group
Inc., New York; SunLife of New York, New York; KOS Pharmaceuticals, Inc., Miami,
Florida; and Southern Pacific Petroleum, Australia, NL. Mr. Whittemore graduated
from Dartmouth College in 1953 and from the Amos Tuck School of Business
Administration in 1954.
Shannon T. Self, age 43, has been a director of the Company since 1993.
He is a shareholder in the law firm of Self, Giddens & Lees, Inc., a
professional corporation, in Oklahoma City, which he co-founded in 1991. Mr.
Self was an associate and shareholder in the law firm of Hastie and Kirschner,
Oklahoma City, from 1984 to 1991 and was employed by Arthur Young & Co. from
1979 to 1980. Mr. Self is a member of the Visiting Committee of Northwestern
University School of Law and for part of 1999 was a director of The Rock Island
Group, a private computer firm in Oklahoma City. Mr. Self is a Certified Public
Accountant. He graduated from the University of Oklahoma in 1979 and from
Northwestern University Law School in 1984.
INFORMATION REGARDING OFFICERS
Executive Officers
In addition to Messrs. McClendon and Ward, the following are also
executive officers of the Company.
31
<PAGE> 33
Marcus C. Rowland, age 47, was appointed Executive Vice President in
March 1998 and has been the Company's Chief Financial Officer since 1993. He
served as Senior Vice President from September 1997 to March 1998 and as Vice
President - Finance from 1993 until 1997. From 1990 until his association with
the Company, Mr. Rowland was Chief Operating Officer of Anglo-Suisse, L.P.
assigned to the White Nights Russian Enterprise, a joint venture of
Anglo-Suisse, L.P. and Phibro Energy Corporation, a major foreign operation
which was granted the right to engage in oil and gas operations in Russia. Prior
to his association with White Nights Russian Enterprise, Mr. Rowland owned and
managed his own oil and gas company and prior to that was Chief Financial
Officer of a private exploration company in Oklahoma City from 1981 to 1985. Mr.
Rowland is a Certified Public Accountant. Mr. Rowland graduated from Wichita
State University in 1975.
Steven C. Dixon, age 41, has been Senior Vice President - Operations
since 1995 and served as Vice President - Exploration from 1991 to 1995. Mr.
Dixon was a self-employed geological consultant in Wichita, Kansas from 1983
through 1990. He was employed by Beren Corporation in Wichita, Kansas from 1980
to 1983 as a geologist. Mr. Dixon graduated from the University of Kansas in
1980.
J. Mark Lester, age 47, has been Senior Vice President - Exploration
since 1995 and served as Vice President - Exploration from 1989 to 1995. From
1986 to 1989, Mr. Lester was self-employed and acted as a consultant to Messrs.
McClendon and Ward. He was employed by various independent oil companies in
Oklahoma City from 1980 to 1986, and was employed by Union Oil Company of
California from 1977 to 1980 as a geophysicist. Mr. Lester graduated from Purdue
University in 1975 and in 1977.
Henry J. Hood, age 40, was appointed Senior Vice President - Land and
Legal in 1997 and served as Vice President - Land and Legal from 1995 to 1997.
Mr. Hood was retained as a consultant to the Company during the two years prior
to his joining the Company, and he was associated with the law firm of White,
Coffey, Galt & Fite from 1992 to 1995. Mr. Hood was associated with or a partner
of the law firm of Watson & McKenzie from 1987 to 1992. Mr. Hood is a member of
the Oklahoma and Texas Bar Associations. Mr. Hood graduated from Duke University
in 1982 and from the University of Oklahoma College of Law in 1985.
Martha A. Burger, age 47, has served as Treasurer since 1995, as Senior
Vice President - Human Resources since March 2000 and as Secretary since
November 1999. She was the Company's Vice President - Human Resources from 1998
until March 2000 and Human Resources Manager from 1996 to 1998. From 1994 to
1995, she served in various accounting positions with the Company including
Assistant Controller - Operations. From 1989 to 1993, Ms. Burger was employed by
Hadson Corporation as Assistant Treasurer and from 1993 to 1994 served as Vice
President and Controller of Hadson Corporation. Prior to joining Hadson
Corporation, Ms. Burger was employed by The Phoenix Resource Companies, Inc. as
Assistant Treasurer and by Arthur Andersen & Co. Ms. Burger is a Certified
Public Accountant and graduated from the University of Central Oklahoma in 1982
and from Oklahoma City University in 1992.
Michael A. Johnson, age 35, has served as Senior Vice President -
Accounting since March 2000. He served as Vice President of Accounting and
Financial Reporting from March 1998 to March 2000 and as Assistant Controller to
the Company from 1993 to 1998. From 1991 to 1993 Mr. Johnson served as Project
Manager for Phibro Energy Production, Inc., a Russian joint venture. From 1987
to 1991 he served as audit manager for Arthur Andersen & Co. Mr. Johnson is a
Certified Public Accountant and graduated from the University of Texas at Austin
in 1987.
Other Officers
Thomas L. Winton, age 53, has served as Senior Vice President -
Information Technology and Chief Information Officer since July 1998. From 1985
until his association with the Company, Mr. Winton served as the Director,
Information Services Department, at Union Pacific Resources Company. Prior to
that period Mr. Winton held the positions of Regional Manager - Information
Services from 1984 until 1985 and Manager - Technical Applications Planning and
Development from 1980 until 1984 with UPRC. Mr. Winton also served as an analyst
and supervisor in the Operations Research Division, Conoco Inc., from 1973 until
1980. Mr. Winton graduated from Oklahoma Christian University in 1969, Creighton
University in 1973 and the University of Houston in 1980. Mr. Winton also
completed the Tuck Executive Program, Amos Tuck School of Business, Dartmouth
College in 1987.
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<PAGE> 34
Douglas J. Jacobson, age 46, has served as Senior Vice President -
Acquisitions & Divestitures since August 1999. Prior to joining Chesapeake, Mr.
Jacobson was employed by Samson Investment Company from 1980 until August 1999,
where he served as Senior Vice President - Project Development and Marketing
from 1996 until 1999. Mr. Jacobson has served on various Oklahoma legislative
commissions intended to address issues in the oil and gas industry, including
the Commission of Oil and Gas Production Practices and the Natural Gas Policy
Commission. Mr. Jacobson is a Certified Public Accountant and graduated from
John Brown University in 1976 and from the University of Arkansas in 1977.
Thomas S. Price, Jr., age 48, has served as Senior Vice President -
Corporate Development since March 2000, as Vice President - Corporate
Development since 1992 and was a consultant to the Company during the prior two
years. He was employed by Kerr-McGee Corporation, Oklahoma City, from 1988 to
1990 and by Flag-Redfern Oil Company from 1984 to 1988. Mr. Price is Vice
Chairman of the Mid-Continent Oil and Gas Association and a member of the
Petroleum Investor Relations Association and the National Investor Relations
Institute. Mr. Price graduated from the University of Central Oklahoma in 1983,
from the University of Oklahoma in 1989 and from the American Graduate School of
International Management in 1992.
James C. Johnson, age 42, was appointed President of Chesapeake Energy
Marketing, Inc., a wholly-owned subsidiary of Chesapeake Energy Corporation, in
January 2000. He served as Vice President - Contract Administration for the
Company from 1997 to January 2000 and as Manager - Contract Administration from
1996 to 1997. From 1980 to 1996, Mr. Johnson held various gas marketing and land
positions with Enogex, Inc., Delhi Gas Pipeline Corporation, TXO Production
Corp. and Gulf Oil Corporation. Mr. Johnson is a member of the Natural Gas
Association of Oklahoma and graduated from the University of Oklahoma in 1980.
Stephen W. Miller, age 43, has served as Vice President - Operations
since 1996 and served as District Manager - College Station District from 1994
to 1996. Mr. Miller held various engineering positions in the oil and gas
industry from 1980 to 1993. Mr. Miller is a registered Professional Engineer in
Texas, is a member of the Society of Petroleum Engineers and graduated from
Texas A & M University in 1980.
33
<PAGE> 35
EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
In 1997 the Company changed its fiscal year end to December 31 from
June 30. The following table sets forth for the fiscal years ended December 31,
1999 and 1998, the transition period for the six months ended December 31, 1997
and the fiscal year ended June 30, 1997 the compensation earned in each period
by (i) the Company's chief executive officer, and (ii) the four other most
highly compensated executive officers:
<TABLE>
<CAPTION>
ANNUAL COMPENSATION
-----------------------------------------------------
SECURITIES
UNDERLYING
OTHER OPTION ALL
NAME AND PRINCIPAL PERIOD ANNUAL AWARDS (# OTHER
POSITION ENDING SALARY BONUS COMPENSATION(a) OF SHARES)(b) COMPENSATION(c)
------------------ --------- ----------- ----------- --------------- ----------- ----------------
<S> <C> <C> <C> <C> <C> <C>
Aubrey K. McClendon
Chairman of the Board
and Chief Executive
Officer 12/31/99 $ 350,000 $300,000 $ 137,029 500,000 $ 19,500
12/31/98 $ 350,000 $325,000 $ 115,429 1,505,808(d) $ 10,000
12/31/97 $ 150,000 $200,000 $ 92,625 457,800(d) $ --
6/30/97 $ 250,000 $310,000 $ 76,950 463,000(d) $ 11,050
Tom L. Ward
President and Chief
Operating Officer 12/31/99 $ 350,000 $300,000 $ 113,331 500,000 $ 20,000
12/31/98 $ 350,000 $325,000 $ 115,977 1,505,808(d) $ 10,000
12/31/97 $ 150,000 $200,000 $ 93,026 457,800(d) $ --
6/30/97 $ 250,000 $310,000 $ 77,908 463,000(d) $ 13,700
Marcus C. Rowland
Executive Vice
President and Chief
Financial Officer 12/31/99 $ 262,500 $110,000 $ 41,428 125,000 $ 6,000
12/31/98 $ 250,000 $175,000 (e) 397,476(d) $ 10,000
12/31/97 $ 112,500 $100,000 (e) 131,600(d) $ --
6/30/97 $ 185,000 $155,000 (e) 36,000(d) $ 9,500
Steven C. Dixon
Senior Vice President
- Operations 12/31/99 $ 190,000 $ 55,000 (e) 40,000 $ 11,500
12/31/98 $ 190,000 $110,000 (e) 206,120(d) $ 10,000
12/31/97 $ 87,500 $ 50,000 (e) 92,000(d) $ --
6/30/97 $ 145,000 $105,000 (e) 30,000(d) $ 11,500
J. Mark Lester
Senior Vice President
- Exploration 12/31/99 $ 177,500 $ 55,000 (e) 40,000 $ 11,980
12/31/98 $ 175,000 $100,000 (e) 153,691(d) $ 10,000
12/31/97 $ 80,000 $ 40,000 (e) 69,700(d) $ 2,660
6/30/97 $ 132,500 $ 70,000 (e) 19,500(d) $ 10,400
</TABLE>
----------
(a) Represents the cost of personal benefits provided by the Company, including
for fiscal year 1999 personal accounting support ($65,175 for Messrs.
McClendon and Ward), personal vehicle ($18,000 for Messrs. McClendon and
Ward and $12,000 for Mr. Rowland), travel allowance ($50,000 for Mr.
McClendon, $25,904 for Mr. Ward and $25,000 for Mr. Rowland) and country
club membership dues ($3,854 for Mr. McClendon, $4,252 for Mr. Ward and
$4,428 for Mr. Rowland).
(b) No awards of restricted stock or payments under long-term incentive plans
were made by the Company to any of the named executives in any period
covered by the table.
(c) Represents Company matching contributions to the Chesapeake Energy
Corporation Savings and Incentive Stock Bonus Plan.
34
<PAGE> 36
(d) Includes both (i) option grants which were canceled and (ii) replacement
options which were granted at 60% of the original number of options
granted.
(e) Other annual compensation did not exceed the lesser of $50,000 ($25,000 for
the transition period) or 10% of the executive officer's salary and bonus
during the period.
STOCK OPTIONS GRANTED DURING 1999
The following table sets forth information concerning options to
purchase common stock granted during 1999 to the executive officers named in the
Summary Compensation Table. Amounts represent stock options granted under the
Company's 1994 and 1999 stock option plans and include both incentive and
non-qualified stock options. One-fourth of each option grant becomes exercisable
on each of the first four grant date anniversaries. The exercise price of each
option represents the market price of the common stock on the date of grant.
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
-------------------------------------------------------------
POTENTIAL REALIZABLE
PERCENT OF VALUE AT ASSUMED
NUMBER OF TOTAL OPTIONS ANNUAL RATE OF STOCK
SECURITIES GRANTED TO PRICE APPRECIATION
UNDERLYING EMPLOYEES IN EXERCISE FOR OPTION TERM(a)
OPTIONS YEAR ENDED PRICE PER EXPIRATION ----------------------------
NAME GRANTED 12/31/99 SHARE DATE 5% 10%
----------------------- ---------- ------------- --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Aubrey K. McClendon 500,000 17.9% $ 0.94 3/5/09 $ 295,580 $ 749,059
Tom L. Ward 500,000 17.9% $ 0.94 3/5/09 $ 295,580 $ 749,059
Marcus C. Rowland 125,000 4.5% $ 0.94 3/5/09 $ 73,895 $ 187,265
Steven C. Dixon 40,000 1.4% $ 0.94 3/5/09 $ 23,646 $ 59,925
J. Mark Lester 40,000 1.4% $ 0.94 3/5/09 $ 23,646 $ 59,925
</TABLE>
----------
(a) The assumed annual rates of stock price appreciation of 5% and 10% are set
by the Securities and Exchange Commission and are not intended as a
forecast of possible future appreciation in stock prices.
35
<PAGE> 37
AGGREGATED OPTION EXERCISES IN 1999 AND DECEMBER 31, 1999 OPTION VALUES
The following table sets forth information about options exercised by
the named executive officers during 1999 and the unexercised options to purchase
common stock held by them at December 31, 1999.
<TABLE>
<CAPTION>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY
ACQUIRED OPTIONS AT 12/31/99 OPTIONS AT 12/31/99(a)
ON VALUE ---------------------------- ----------------------------
NAME EXERCISE REALIZED(b) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
------------------- ---------- ----------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Aubrey K. McClendon -- $ -- 722,953 1,629,355 $ 585,434 $2,131,694
Tom L. Ward 315,000 $ 329,544 722,953 1,629,355 $ 585,434 $2,131,694
Marcus C. Rowland 139,871 $ 305,642 -- 423,105 $ -- $ 552,631
Steven C. Dixon -- $ -- 416,434 194,586 $ 504,871 $ 250,833
J. Mark Lester -- $ -- 115,827 155,264 $ 151,094 $ 201,680
</TABLE>
----------
(a) At December 31, 1999, the closing price of the common stock on the New York
Stock Exchange was $2.38. "In-the-money options" are stock options with
respect to which the market value of the underlying shares of common stock
exceeded the exercise price at December 31, 1999. The values shown were
determined by subtracting the aggregate exercise price of such options from
the aggregate market value of the underlying shares of common stock on
December 31, 1999.
(b) Represents amounts determined by subtracting the aggregate exercise price
of such options from the aggregate market value of the underlying shares of
common stock on the exercise date.
EMPLOYMENT AGREEMENTS
The Company has employment agreements with Messrs. McClendon and Ward,
each of which provides, among other things, for an annual base salary of not
less than $350,000, bonuses at the discretion of the Board of Directors,
eligibility for stock options and benefits, including an automobile and travel
allowance, club membership and personal accounting support. Each agreement has a
term of five years commencing July 1, 1998, which term is automatically extended
for one additional year on each June 30 unless one of the parties provides 30
days prior notice of non-extension. In addition, for each calendar year during
which the employment agreements are in effect, Messrs. McClendon and Ward each
agree to hold shares of the Company's common stock having an aggregate
investment value equal to 500% of his annual base salary and bonus.
Under the employment agreements, Messrs. McClendon and Ward are
permitted to participate in all of the wells spudded by or on behalf of the
Company during each calendar quarter. In order to participate, at least 30 days
prior to the beginning of a calendar quarter the executive must notify the
disinterested members of the Compensation Committee whether the executive elects
to participate and, if so, the percentage working interest the executive will
take in each well spudded by or on behalf of the Company during such quarter.
The participation election by Messrs. McClendon or Ward may not exceed a 2.5%
working interest in a well and is not effective for any well where the Company's
working interest after elections by Messrs. McClendon and Ward to participate
would be reduced to below 12.5%. Once an executive elects to participate, the
percentage cannot be adjusted during the calendar quarter without the prior
written consent of the disinterested directors, and no such adjustment has ever
been requested or granted. For each well in which the executive participates,
the Company bills to the executive an amount equal to the executive's
participation percentage multiplied by the costs of drilling and operating
incurred in drilling the well, together with leasehold costs in an amount
determined by the Company to approximate what third parties pay for similar
leasehold in the area of the well. Payment is due within 150 days for invoices
received prior to June 30, 2000 and within 90 days for invoices received
subsequent to such date. The executive also receives a proportionate share of
revenue from the well less certain charges by the Company for
36
<PAGE> 38
marketing the production. As a result of marketing arrangements with other
participants in the Company's wells to correct the timing of the receipt of
revenues, the Company has advanced to the executives an amount equal to two
months production on each of the wells based on a six-month trailing average of
production revenue. As a result of fluctuations in the price and volume of oil
and natural gas from the wells, such advance now exceeds two months production.
The Company and the executives have agreed that such amount will bear interest,
and have also agreed to a payment schedule to reduce such advance to equal one
month's production by December 31, 2000. In the event an executive is not in
compliance with the foregoing payment obligations, the right to participate in
the Company's wells automatically is suspended until the executive is in
compliance.
Messrs. McClendon and Ward have agreed that they will not engage in oil
and gas operations individually except pursuant to the aforementioned
participation in Company wells and as a result of subsequent operations on
properties owned by them or their affiliates as of July 1, 1995. Messrs.
McClendon and Ward participated in all wells drilled by the Company from its
initial public offering in February 1993 through December 1998 with either a
1.0%, 1.25% or 1.5% working interest. Messrs. McClendon and Ward did not
participate in the Company's wells during 1999 or the first quarter of 2000.
However, both resumed participation in the Company's wells on April 1, 2000.
The Company has a similar employment agreement with Mr. Rowland that is
in effect through July 31, 2000. It provides for an annual base salary of not
less than $250,000. The Company and Mr. Rowland have agreed to modify the terms
of Mr. Rowland's employment agreement effective August 1, 2000. The
modifications include a two-year contract term, which can be terminated by
either party and provides for a minimum annual base salary of $110,000.
Additionally, effective August 1, 2000, Mr. Rowland will reduce his work
schedule and his title will become Chief Financial Officer and Senior Vice
President - Finance. Mr. Rowland's employment agreement requires him to hold
shares of the Company's common stock having an aggregate investment value (as
defined) equal to 100% of his annual base salary and bonus; under his new
employment agreement, this requirement will not change. Mr. Rowland has been
permitted under his employment agreement to participate in the Company's oil and
gas drilling operations, although he has not done so since 1997. He will no
longer have the option to participate in the Company's wells, after July 31,
2000.
The Company also has employment agreements with Messrs. Dixon and
Lester. These agreements have a term of three years from July 1, 2000, with
minimum annual base salaries of $205,000. The agreements require each of them to
acquire and continue to hold at least 1,000 shares of the Company's common stock
throughout the term of their contract.
The Company may terminate any of the employment agreements with its
executive officers at any time without cause; however, upon such termination
Messrs. McClendon and Ward are entitled to continue to receive salary and
benefits for the balance of the contract term. Upon termination of Mr. Rowland's
existing employment agreement by the Company, he would be entitled to receive
salary and benefits for the balance of the contract term. The employment
agreement that becomes effective August 1, 2000 will provide for three months
compensation and benefits if terminated without cause by the Company. Messrs.
Dixon and Lester are entitled to three months compensation and benefits if their
employment is terminated without cause. Each of the employment agreements for
Messrs. McClendon, Ward, Rowland, Dixon and Lester further state that if, during
the term of the agreement, there is a change of control and (a) within one year
the agreement expires and is not extended, (b) within one year the executive
officer resigns as a result of (i) a reduction in the executive officer's
compensation, or (ii) a required relocation more than 25 miles from the
executive officer's then current place of employment or (c) within two years
from the effective date of the change of control (one year for Messrs. Dixon and
Lester) the executive officer is terminated other than for cause, death or
incapacity, then the executive officer will be entitled to a severance payment
in an amount equal to 60 months of base compensation (as that term is defined in
the agreements) for Messrs. McClendon and Ward and 6 months for Messrs. Dixon
and Lester and 36 months for Mr. Rowland. Change of control is defined in these
agreements to include (x) an event which results in a person acquiring
beneficial ownership of securities having 35% or more (51% for Messrs. Dixon and
Lester) of the voting power of the Company's outstanding voting securities, or
(y) within two years of a tender offer or exchange offer for the voting stock of
the Company or as a result of a merger, consolidation, sale of assets or
contested election, a majority of the members of the Company's Board of
Directors is replaced by directors who were not nominated and approved by the
Board of Directors. Mr. Rowland's employment agreement, which will become
effective August 1, 2000, does not provide for benefits payable upon a change of
control.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation Committee is composed of Messrs. Heizer and
Whittemore. Messrs. McClendon and Ward served on the Compensation Committee
until September 1999. Mr. McClendon is Chairman of the Board
37
<PAGE> 39
and Chief Executive Officer of the Company and Mr. Ward is the Company's
President and Chief Operating Officer. Messrs. McClendon and Ward administer the
Company's 1992 stock option plans. The 1992 Incentive Stock Option Plan was
terminated in December 1994 except with respect to the administration of
outstanding options. The only options issued under the 1992 NSO Plan during the
year ended December 31, 1999 were those to the Company's non-employee directors
pursuant to a formula award provision. See "-Directors' Compensation." Messrs.
McClendon and Ward also serve on committees which administer the Company's other
stock option plans with respect to employee participants who are not executive
officers. Messrs. Heizer and Whittemore serve on committees which administer
these plans with respect to employee participants who are executive officers.
Messrs. McClendon and Ward participate as working interest owners in the
Company's oil and gas wells pursuant to the terms of their employment agreements
with the Company. See "-Employment Agreements." Accounts receivable from Messrs.
McClendon and Ward are generated by joint interest billings relating to such
participation and as a result of miscellaneous expenses paid on their behalf by
the Company. A subsidiary of the Company extended loans of $5.0 million each to
Messrs. McClendon and Ward in 1998 which were paid in full in late 1999. See
"Certain Transactions."
DIRECTORS' COMPENSATION
During 1999, directors who were not employees of the Company
("non-employee directors") received cash compensation of $25,000, comprised of
an annual retainer of $5,000, payable in quarterly installments of $1,250, and
$5,000 for each meeting of the Board attended, not to exceed $20,000 per year
for Board meetings attended. Directors are reimbursed for travel and other
expenses. Officers who also serve as directors do not receive fees for serving
as directors. Under a formula award provision in the 1992 NSO Plan, non-employee
directors were granted ten-year non-qualified options to purchase 6,250 shares
of common stock at an exercise price equal to the market price on the first
business day of each quarter of 1999 and the first quarter of 2000. Commencing
with the second quarter in 2000, the quarterly option grant to non-employee
directors increased to 7,500 shares. The options are immediately exercisable
upon grant.
38
<PAGE> 40
CERTAIN TRANSACTIONS
Legal Counsel. Shannon T. Self, a director of the Company, is a
shareholder in the law firm of Self, Giddens & Lees, Inc., which provides legal
services to the Company. During 1997, 1998 and 1999, the firm billed the Company
approximately $414,314, $493,000 and $398,000, respectively for such legal
services.
Oil and Gas Operations. Prior to 1989, Messrs. McClendon and Ward and
their affiliates, as independent oil producers, acquired various leasehold and
working interests. In 1989, Chesapeake Operating, Inc. ("COI"), a wholly-owned
subsidiary of the Company, was formed to drill and operate wells in which
Messrs. McClendon and Ward or their affiliates owned working interests. COI
entered into joint operating agreements with Messrs. McClendon and Ward and
other working interest owners and billed each for their respective shares of
expenses and fees. COI continues to operate wells in which directors, executive
officers and related parties own working interests. In addition, directors,
executive officers and related parties have in the past acquired working
interests directly and indirectly from the Company and participated in wells
drilled by COI. The Company's non-employee directors have not acquired from the
Company interests in any new wells drilled by the Company since their election
as directors in 1993 and have no present intention to acquire from the Company
interests in any new wells of the Company.
The table below presents information about drilling, completion,
equipping and operating costs billed to the persons named in 1997, 1998 and
1999, the largest amount owed by them during those periods and the balances owed
by them at December 31, 1999, 1998, 1997 and 1996. No interest is charged on
amounts owing for such costs. The amounts for all other directors and executive
officers who are joint working interest owners in Company wells were
insignificant.
<TABLE>
<CAPTION>
AUBREY K. TOM L. MARCUS C.
MCCLENDON WARD ROWLAND
--------- -------- ---------
(in 000's)
<S> <C> <C> <C>
Amount billed in 1999 ................................. $ 1,421 $ 1,366 $ 68
Largest outstanding balance in 1999 (month end) ...... $ 1,503 $ 1,718 $ 29
Balance at December 31, 1999 .......................... $ 1,426 $ 868 $ 16
Amount billed in 1998 ................................. $ 3,950 $ 3,902 $ 106
Largest outstanding balance in 1998 (month end) ....... $ 2,581 $ 3,291 $ 62
Balance at December 31, 1998 .......................... $ 1,541 $ 1,444 $ 18
Amount billed in 1997 ................................. $ 6,784 $ 6,759 $ 142
Largest outstanding balance in 1997 (month end) ....... $ 4,745 $ 4,190 $ 60
Balance at December 31, 1997 .......................... $ 68 $ 2,203 $ 36
Balance at December 31, 1996 .......................... $ 1,224 $ 1,272 $ 35
</TABLE>
The amounts advanced to the executive officers during 1998 and 1999 to
correct the timing of the receipt of oil and gas revenues on the wells in which
the executive officers participated, including accrued interest, equaled
$984,000 and $959,208, respectively for Mr. McClendon, $958,000 and $932,223,
respectively for Mr. Ward and $29,060 and $25,000, respectively for Mr. Rowland.
The amount of these advances in excess of revenue received by the Company and
not disbursed bears interest at 9.125%.
Loans to Executives. In June 1998, the Company extended loans of $5.0
million each to Messrs. McClendon and Ward to pay a portion of the margin debt
incurred by them in connection with their purchase of 730,750 shares each of
Company common stock in the open market in February 1997 at an approximate
average price of $20.24 per share. Each loan initially had a maturity date of
December 31, 1998, which was extended to December 31, 1999. In each case the
terms of the loan and the documentation evidencing the loan were negotiated by a
committee of independent directors in conjunction with separate legal counsel.
Interest accrued on each of the loans at an annual rate of 9.125% and was
payable quarterly. Each of the loans was secured by collateral with an indicated
fair market value greater than 150% of the unpaid principal balance of the loan.
In November 1999, the borrowers repaid the loans in full by surrendering shares
of the Company's common stock having a market value equal to the respective
amounts owed (principal amount of $3,847,000 for Mr. McClendon and $3,688,000
for Mr. Ward).
Purchase of Oil and Gas Assets from Executive. In January 2000, the
Company purchased Mr. Rowland's interests in the oil and gas wells in which he
participated pursuant to his employment agreement. The purchase price for the
oil and gas assets was $465,000 and was determined using a methodology similar
to that used for similar acquisitions of assets from disinterested third
parties. See "Executive Compensation - Employment Agreements."
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<PAGE> 41
Miscellaneous. From time to time, the Company has paid various expenses
incurred on behalf of Messrs. McClendon and Ward and their affiliates, creating
accounts receivable of the Company. During 1997, 1998 and 1999 additions to
accounts receivable (excluding joint interest billings, which are described
above) from Messrs. McClendon and Ward and their affiliates were insignificant.
40
<PAGE> 42
SECURITY OWNERSHIP
The table below sets forth (i) the name and address of each person
known by management to own beneficially more than 5% of the Company's
outstanding common stock, the number of shares beneficially owned by each such
shareholder and the percentage of outstanding shares owned, and (ii) the number
and percentage of outstanding shares of common stock beneficially owned by each
of the Company's directors and executive officers listed in the Summary
Compensation Table in "Executive Compensation" and by all directors and
executive officers of the Company as a group. Unless otherwise noted,
information is given as of June 30, 2000 and the persons named below have sole
voting and/or investment power with respect to such shares.
<TABLE>
<CAPTION>
COMMON STOCK
--------------------------------------------------------------------------
OUTSTANDING OPTION TOTAL PERCENT OF
BENEFICIAL OWNER SHARES SHARES(a) OWNERSHIP CLASS
---------------------------------------- ----------- ------------ ---------- ----------
<S> <C> <C> <C> <C>
Tom L. Ward(1)(2) ...................... 10,384,551(b)(c) 847,953 11,232,504 8.0%
6100 North Western Avenue
Oklahoma City, OK 73118
Aubrey K. McClendon(1)(2) .............. 8,899,671(c)(d) 847,953 9,747,624 7.0%
6100 North Western Avenue
Oklahoma City, OK 73118
Franklin Advisers, Inc. ................ 10,491,300 -- 10,491,300 7.5%
777 Mariners Island Boulevard
San Mateo, CA 94404
Loomis, Sayles & Company, L.P. ......... -- 7,130,204(e) 7,130,204(e) 5.1%
One Financial Center
Boston, MA 02111
Edgar F. Heizer, Jr.(1) ................ 709,650 406,000 1,115,650 (3)
Breene M. Kerr(1) ...................... 423,250(f) 182,500(g) 605,750 (3)
Shannon T. Self(1) ..................... 31,458(h) 420,666 452,124 (3)
Frederick B. Whittemore(1) ............. 481,800(i) 1,185,250(g) 1,667,050 1.2%
Steven C. Dixon(2) ..................... 13,716(c) 411,434 425,150 (3)
J. Mark Lester(2) ...................... 37,845(c) 93,827 131,672 (3)
Marcus C. Rowland(2) ................... 32,548(c) -- 32,548 (3)
All directors and executive officers
as a group ........................... 21,061,813 3,597,701 24,659,514 17.2%
</TABLE>
----------
(1) Director
(2) Executive officer
(3) Less than 1%
(a) Represents shares of common stock which can be acquired on June 30, 2000 or
60 days thereafter through the exercise of options or conversion of the
Company's convertible preferred stock.
(b) Includes 1,646,860 shares held by TLW Investments, Inc., an Oklahoma
corporation of which Mr. Ward is sole shareholder and chief executive
officer; 1,098,600 shares held by the Aubrey K. McClendon Children's Trust
of which Mr. Ward is Trustee; and 21,435 shares held by Mr. Ward's
immediate family sharing the same household. Excluded are the shares of
common stock beneficially owned by Mr. McClendon which may be attributed to
Mr. Ward based on a jointly filed Schedule 13D. Mr. Ward disclaims such
ownership.
(c) Includes shares purchased on behalf of the executive officer in the
Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan (Tom
L. Ward, 34,042 shares; Aubrey K. McClendon, 81,123 shares; Steven C.
Dixon, 13,716 shares; J. Mark Lester, 13,345 shares; and Marcus C. Rowland,
16,403 shares).
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<PAGE> 43
(d) Includes 58,560 shares held by Chesapeake Investments, an Oklahoma limited
partnership of which Mr. McClendon is sole general partner. Excluded are
the shares beneficially owned by Mr. Ward which may be attributed to Mr.
McClendon based on a jointly filed Schedule 13D. Mr. McClendon disclaims
such ownership.
(e) Represents shares of the Company's preferred stock which is convertible
into 7,130,204 shares of the Company's common stock based upon Schedule 13G
filed February 1, 2000. Excludes any shares that might be issuable with
respect to accrued and unpaid dividends.
(f) Includes 250,000 shares held by Talbot Fairfield II Limited Partnership, of
which Mr. Kerr is a general partner.
(g) Includes options to purchase shares of the Company's common stock owned by
Messrs. Ward and McClendon issued to Messrs. Kerr, and Whittemore (Breene
M. Kerr, 93,750 shares from Aubrey K. McClendon; Frederick B. Whittemore,
394,688 shares from Aubrey K. McClendon and 355,312 shares from Tom L.
Ward).
(h) Consists of 12,382 shares held by Pearson Street Limited Partnership, an
Oklahoma limited partnership of which Mr. Self is sole general partner and
the remaining partner is Mr. Self's spouse.
(i) Includes 41,750 shares held by Mr. Whittemore as trustee of the Whittemore
Foundation.
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<PAGE> 44
SELLING SHAREHOLDERS
The following table sets forth the name of each of the selling
shareholders, the number of shares and percentage of common stock beneficially
owned by each selling shareholder before the offering, the number of shares of
common stock offered pursuant to this prospectus, and the number of shares of
common stock beneficially owned by each selling shareholder after the offering.
<TABLE>
<CAPTION>
SHARES, BENEFICIALLY
OWNED BEFORE OFFERING NUMBER OF SHARES
------------------------------ NUMBER OF SHARES BENEFICIALLY OWNED
NAME OF SELLING SHAREHOLDER (1) NUMBER PERCENT BEING OFFERED AFTER OFFERING
--------------------------------------------- ------------ ----------- --------------- ------------------
<S> <C> <C> <C> <C>
Appaloosa Investment Limited Partnership I(2) 1,940,963 1.39% 1,940,963 --
Palomino Fund Ltd.(2) 2,172,708 1.56% 2,172,708 --
Tersk LLC(2) 322,259 * 322,259 --
Oppenheimer Strategic Income Fund(3) 2,803,956(4) 1.99% 1,752,337 1,051,619(4)
Oppenheimer Champion Income Fund(3) 1,413,609(5) 1.01% 833,429 580,180(5)
Oppenheimer Variable Account Funds
f/a/o Oppenheimer Strategic Bond Fund(3) 170,004(6) * 26,119 143,885(6)
Oppenheimer High Yield Fund(3) 2,132,216(7) 1.52% 1,412,792 719,424(7)
Atlas Strategic Income Fund(3) 11,872 * 11,872 --
Ingalls & Snyder Value Partners, L.P.(8) 412,868 * 412,868 --
Heritage Mark Foundation(8) 94,978 * 94,978 --
Arthur R. Ablin(8) 13,772 * 13,772 --
John Hancock High Yield Bond Fund 473,938 * 473,938 --
John Hancock Variable Annuity High Yield Bond Fund 950 * 950 --
</TABLE>
----------
* Indicates less than 1%
(1) The term selling shareholders also includes their respective donees,
pledgees, transferees and other successors in interest. The information in
the table is as of July 7, 2000.
(2) Appaloosa Management L.P. is the general partner of Appaloosa Investment
Limited Partnership I, investment advisor of Palomino Fund Ltd., and the
managing member of Tersk LLC. The general partner of Appaloosa Management
is Appaloosa Partners Inc. David Tepper is the sole stockholder and
President of Appaloosa Partners and owns a majority of the limited
partnership interests of Appaloosa Management. Such persons may be deemed
to be beneficial owners.
(3) Each entity is a registered investment company. Oppenheimer Funds, Inc.
acts as the investment advisor for the Oppenheimer funds and as sub-advisor
for Atlas Strategic Income Fund, and has investment discretion on behalf of
these accounts. Therefore it may be deemed to be a beneficial owner of such
securities but disclaims beneficial ownership.
(4) Includes 1,051,619 shares of common stock issuable upon conversion of
146,175 shares of 7% convertible preferred stock.
(5) Includes 550,180 shares of common stock issuable upon conversion of 76,475
shares of 7% convertible preferred stock.
(6) Includes 143,885 shares of common stock issuable upon conversion of 20,000
shares of 7% convertible preferred stock.
(7) Includes 719,424 shares of common stock issuable upon conversion of
100,000 shares of 7% convertible preferred stock.
(8) Ingalls & Snyder LLC shares dispositive powers with respect to these
shares.
None of the selling shareholders listed above has, or within the past
three years has had, any position, office or other material relationship with
the Company or any of its predecessors or affiliates.
Because the selling shareholders may offer all or some portion of the
above shares pursuant to this prospectus or otherwise, no estimate can be given
as to the amount or percentage of such securities that will be held by the
selling shareholders upon termination of any such sale. In addition, the selling
shareholders identified above may have sold, transferred or otherwise disposed
of all or a portion of such securities since the date indicated in transactions
exempt from the registration requirements of the Securities Act. The selling
shareholders may sell all, part or none of the shares listed above.
43
<PAGE> 45
DESCRIPTION OF THE CAPITAL STOCK
The summary of the terms of the capital stock of the Company set forth below
does not purport to be complete and is qualified by reference to the Company's
Certificate of Incorporation and its Bylaws. Copies of the Company's Certificate
of Incorporation and Bylaws are available from the Company upon request. The
authorized capital stock of the Company consists of 250,000,000 shares of common
stock, par value $.01 per share, and 10,000,000 shares of preferred stock, par
value $.01 per share, of which 1,557,037 shares are designated the 7% Cumulative
Convertible Preferred Stock and 250,000 shares are designated the Series A
Junior Participating Preferred Stock ("Series A Preferred Stock"). As of June
30, 2000, the issued and outstanding capital stock of the Company consisted of
139,490,896 shares of common stock and 1,557,037 shares of 7% Cumulative
Convertible Preferred Stock. No shares of Series A Preferred Stock are currently
outstanding. Also, an additional 16,836,298 shares of common stock were reserved
for issuance upon the exercise of outstanding options granted under the
Company's stock option plans.
COMMON STOCK
The holders of common stock are entitled to one vote for each share held of
record on all matters submitted to a vote of shareholders. Subject to
preferences that may be applicable to any outstanding preferred stock, holders
of common stock are entitled to receive ratably such dividends as may be
declared by the Board of Directors out of funds legally available for dividends.
In the event of a liquidation or dissolution of the Company, holders of common
stock are entitled to share ratably in all assets remaining after payment of
liabilities and the liquidation preference of any outstanding preferred stock.
Holders of common stock have no preemptive rights and have no rights to
convert their common stock into any other securities. All of the outstanding
shares of common stock are duly authorized, validly issued, fully paid and
nonassessable.
PREFERRED STOCK
The 7% Cumulative Convertible Preferred Stock is described below under
"7% Cumulative Convertible Preferred Stock." The Series A Preferred Stock is
described below under "- Anti-Takeover Provisions - Share Rights Plan."
The Company has 8,192,963 shares of authorized preferred stock which
are undesignated. The Board of Directors is authorized, subject to any
limitations prescribed by law, without further shareholder approval, to issue
shares of preferred stock from time to time in one or more new series as from
time to time designated. Each such series of preferred stock would have such
number of shares, designations, preferences, voting powers, qualifications and
special or relative rights or privileges as determined by the Board of
Directors, which may include, among others, dividend rights, voting rights,
redemption and sinking fund provisions, liquidation preferences and conversion
rights.
While providing desirable flexibility in connection with possible
acquisitions and other corporate purposes, and eliminating delays associated
with a shareholder vote on specific issuances, the issuance of preferred stock
could adversely affect the voting power of holders of common stock and the
likelihood that such holders will receive dividend payments and payments upon
liquidation and could have the effect of delaying, deferring or preventing a
change in control of the Company.
7% Cumulative Convertible Preferred Stock
The Certificate of Designation for the 7% Cumulative Convertible
Preferred Stock (the "Preferred Stock") authorizes the issuance of 1,557,037
shares of Preferred Stock, all of which are issued and outstanding. The
Preferred Stock is, and any common stock issued upon the conversion or exchange
of Preferred Stock will be, fully paid and nonassessable.
Ranking. The Preferred Stock, with respect to dividend distributions
and distributions upon the liquidation, winding-up and dissolution of the
Company, ranks:
44
<PAGE> 46
o senior to all classes of common stock of the Company and to each other
class of capital stock or series of preferred stock established after April
22,1998, the issue date of the Preferred Stock (the "Issue Date"), by the
Board of Directors, the terms of which do not expressly provide that it
ranks senior to or on a parity with the Preferred Stock as to dividend
distributions and distributions upon the liquidation, winding-up and
dissolution of the Company;
o subject to certain conditions, on a parity with any class of capital stock
or series of preferred stock issued by the Company established after the
Issue Date by the Board of Directors, the terms of which expressly provide
that such class or series will rank on parity with the Preferred Stock as
to dividend distributions and distributions upon the liquidation,
winding-up and dissolution of the Company; and
o subject to certain conditions, junior to each class of capital stock or
series of preferred stock issued by the Company established after the Issue
Date by the Board of Directors, the terms of which expressly provide that
such class or series will rank senior to the Preferred Stock as to dividend
distributions and distributions upon liquidation, winding-up and
dissolution of the Company.
Dividends. Holders of the Preferred Stock are entitled to receive
cumulative annual cash dividends of $3.50 per share, payable quarterly in
arrears out of assets legally available for dividends, on February 1, May 1,
August 1 and November 1 of each year commencing August 1, 1998, when, as and if
declared by the Board of Directors. Dividends will accumulate and be cumulative
(whether or not declared) from the Issue Date. Dividends will be payable to
holders of record as they appear on the Company's stock register on such record
dates, not more than 60 days nor less than 10 days preceding the payment dates
thereof, as shall be fixed by the Board of Directors. Dividends payable on the
Preferred Stock for each full dividend period will be computed by dividing the
annual dividend rate by four. Dividends payable on the Preferred Stock for any
period less than a full dividend period (based upon the number of days elapsed
during the period) will be computed on the basis of a 360-day year consisting of
twelve 30-day months. No dividends or other distributions (other than a dividend
or distribution payable solely in stock of the Company ranking junior to the
Preferred Stock as to dividends and upon liquidation and cash in lieu of
fractional shares) may be declared, made or paid or set apart for payment upon
the common stock or upon any other stock of the Company ranking junior to or
pari passu with the Preferred Stock as to dividends, nor may any common stock or
any other stock of the Company ranking junior to or pari passu with the
Preferred Stock as to dividends or upon liquidation be redeemed, purchased or
otherwise acquired for any consideration (or any money paid to or made available
for a sinking fund for the redemption of any shares of any such stock) by the
Company (except by conversion into or exchange for stock of the Company ranking
junior to the Preferred Stock as to dividends and upon liquidation) unless full
cumulative dividends have been or contemporaneously are paid or declared and a
sum sufficient for the payment thereof is set apart for such payment on the
Preferred Stock for all dividend payment periods terminating on or prior to the
date of such declaration, payment, redemption, purchase or acquisition. Holders
of shares of the Preferred Stock will not be entitled to any dividend, whether
payable in cash, property or stock, in excess of full cumulative dividends. No
interest, or sum of money in lieu of interest, will be payable in respect of any
dividend payment or payments which may be in arrears.
The Company's ability to declare and pay cash dividends and make other
distributions with respect to its capital stock, including the Preferred Stock,
is limited by provisions contained in various financing agreements. Similarly,
the Company's ability to declare and pay dividends may be limited by applicable
Oklahoma law. See "Risk Factors - Existing Debt Covenants Restrict Our
Operations."
Liquidation Preference. In the event of any voluntary or involuntary
dissolution, liquidation or winding up of the Company, the holders of the
Preferred Stock will be entitled to receive and to be paid out of the Company's
assets available for distribution to its shareholders, before any payment or
distribution is made to holders of common stock or any other class or series of
stock of the Company ranking junior to the Preferred Stock upon liquidation, a
liquidation preference in the amount of $50 per share of the Preferred Stock,
plus accrued and unpaid dividends thereon. If upon any voluntary or involuntary
dissolution, liquidation or winding up of the Company, the amounts payable with
respect to the liquidation preference of the Preferred Stock and any other
shares of stock of the Company ranking as to any such distribution pari passu
with the Preferred Stock are not paid in full, the holders of the Preferred
Stock and of such other shares will share pro rata in proportion to the full
distributable amounts to which they are entitled. After payment of the full
amount of the liquidating distribution
45
<PAGE> 47
to which they are entitled, the holders of the Preferred Stock will have no
right or claim to any of the remaining assets of the Company. Neither the sale
of all or substantially all of the property or business of the Company (other
than in connection with the winding up of its business), nor the merger or
consolidation of the Company into or with any other corporation, will be deemed
to be dissolution, liquidation or winding up, voluntary or involuntary, of the
Company.
Optional Redemption. The Preferred Stock may not be redeemed prior to
May 1, 2001. After May 1, 2001, the Company may redeem the Preferred Stock for
prices as set forth in the Certificate of Designation ($52.45 per share during
the first year).
From and after the applicable redemption date (unless the Company is in
default of payment of the redemption price), dividends on the shares of the
Preferred Stock to be redeemed on such redemption date will cease to accrue, the
shares will no longer be deemed to be outstanding, and all rights of the holders
of the shares as shareholders of the Company (except the right to receive the
redemption price) will cease.
If any dividends on the Preferred Stock are in arrears, no shares of
the Preferred Stock will be redeemed unless all outstanding shares of the
Preferred Stock are simultaneously redeemed.
Voting Rights. The holders of the Preferred Stock have no voting rights
except as set forth below or as otherwise required by law from time to time. If
the dividends payable on the Preferred Stock are in arrears for six quarterly
periods, the holders of the Preferred Stock voting separately as a class with
the shares of any other preferred stock or preference securities having similar
voting rights will be entitled at the next regular or special meeting of
shareholders of the Company to elect two directors of the Company (such voting
rights and the terms of the directors so elected to continue until such time as
the dividend arrearage on the Preferred Stock has been paid in full). The
affirmative vote or consent of the holders of at least 66 2/3% of the
outstanding Preferred Stock will be required for the issuance of any class or
series of stock (or security convertible into stock) of the Company ranking pari
passu or senior to the Preferred Stock as to dividends, liquidation rights or
voting rights and for amendments to the Company's Certificate of Incorporation
that would affect adversely the rights of holders of the Preferred Stock,
including, without limitation, any increase in the authorized number of shares
of preferred stock. In all such cases, each share of Preferred Stock shall be
entitled to one vote.
Conversion Rights. The Preferred Stock is convertible at any time at
the option of the holder thereof into such number of whole shares of common
stock as is equal to the aggregate liquidation preference, plus accrued and
unpaid dividends thereon to the date the shares of Preferred Stock are
surrendered for conversion, divided by an initial conversion price of $6.95,
subject to adjustment as described in the Certificate of Designation (such price
or adjusted price being referred to as the "Conversion Price"). A share of
Preferred Stock called for redemption will be convertible into shares of common
stock up to and including but not after, unless the Company defaults in the
payment of the amount payable upon redemption, the close of business on the date
fixed for redemption.
Change of Control. Notwithstanding the foregoing, upon a Change of
Control (as defined in the Certificate of Designation), holders of Preferred
Stock will, in the event that the Market Value at such time is less than the
Conversion Price, have a one-time option to convert all of their outstanding
shares of Preferred Stock into shares of common stock at an adjusted Conversion
Price equal to the greater of (i) the Market Value as of the Change of Control
Date and (ii) $3.66, which is 66 2/3% of the Market Value for the period ended
April 16, 1998. Such option will be exercisable during a period of not less than
30 days nor more than 60 days commencing on the third business day after notice
of the Change of Control is given by the Company in the manner specified. In
lieu of issuing the shares of common stock issuable upon conversion in the event
of a Change of Control, the Company may, at its option, make a cash payment
equal to the Market Value determined for the period ending on the Change of
Control Date of such common stock otherwise issuable. "Market Value" is defined
in the Certificate of Designation as the average closing price of the common
stock for a five consecutive trading day period on the New York Stock Exchange
or such other national securities exchange or automated quotation system on
which the common stock is then listed or authorized for quotation or, if the
common stock is not so listed or authorized for quotation, an amount determined
in good faith by the Board of Directors to be the fair value of the common
stock.
46
<PAGE> 48
ANTI-TAKEOVER PROVISIONS
The Certificate of Incorporation and Bylaws of the Company and the
Oklahoma General Corporation Act (the "OGCA") include a number of provisions
which may have the effect of encouraging persons considering unsolicited tender
offers or other unilateral takeover proposals to negotiate with the Board of
Directors rather than pursue non-negotiated takeover attempts. These provisions
include a classified Board of Directors, authorized blank check preferred stock
(described above under - "Preferred Stock"), restrictions on business
combinations and the availability of authorized but unissued common stock.
Classified Board of Directors
The Company's Certificate of Incorporation and Bylaws contain
provisions for a staggered Board of Directors with only one-third of the board
standing for election each year. Directors can only be removed for cause. A
staggered board makes it more difficult for shareholders to change the majority
of the directors and instead promotes a continuity of existing management.
Oklahoma Business Combination Statute
Section 1090.3 of the OGCA prevents an "interested shareholder" from
engaging in a "business combination" with an Oklahoma corporation for three
years following the date such person became an interested shareholder, unless
o prior to the date such person became an interested shareholder, the Board
of Directors of the corporation approved the transaction in which the
interested shareholder became an interested shareholder or approved the
business combination,
o upon consummation of the transaction that resulted in the interested
shareholder's becoming an interested shareholder, the interested
shareholder owns stock having at least 85% of all voting power of the
corporation at the time the transaction commenced, excluding stock held by
directors who are also officers of the corporation and stock held by
certain employee stock plans, or
o on or subsequent to the date of the transaction in which such person became
an interested shareholder, the business combination is approved by the
Board of Directors of the corporation and authorized at a meeting of
shareholders by the affirmative vote of the holders of two-thirds of all
voting power not attributable to shares owned by the interested
shareholder.
The statute defines a "business combination" to include
o any merger or consolidation involving the corporation and an interested
shareholder,
o any sale, lease, exchange, mortgage, pledge, transfer or other disposition
to or with an interested shareholder of 10% or more of the assets of the
corporation,
o subject to certain exceptions, any transaction which results in the
issuance or transfer by the corporation of any stock of the corporation to
an interested shareholder,
o any transaction involving the corporation which has the effect of
increasing the proportionate share of the stock of any class or series or
voting power of the corporation owned by the interested shareholder,
o the receipt by an interested shareholder of any loans, guarantees, pledges
or other financial benefits provided by or through the corporation, or
o any share acquisition by the interested shareholder pursuant to Section
1090.1 of the OGCA. For purposes of Section 1090.3, the term "corporation"
also includes the corporation's majority-owned subsidiaries.
In addition, Section 1090.3 defines an "interested shareholder," generally, as
any person that owns stock having 15% or more of all voting power of the
corporation, any person that is an affiliate or associate of the corporation and
owned stock having 15% or more of all voting power of the corporation at any
time within the three-year period prior to the time of determination of
interested shareholder status, and any affiliate or associate of such person.
47
<PAGE> 49
Stock Purchase Provisions
The Certificate of Incorporation includes a provision which requires
the affirmative vote of two-thirds of the votes cast by the holders, voting
together as a single class, of all then outstanding shares of capital stock,
excluding the votes by an interested shareholder, to approve the purchase of any
capital stock of the Company from the interested shareholder at a price in
excess of fair market value, unless such purchase is either (i) made on the same
terms offered to all holders of the same securities or (ii) made on the open
market and not the result of a privately negotiated transaction.
Share Rights Plan
The Rights. On July 7, 1998, the Board of Directors of the Company
declared a dividend distribution of one preferred stock purchase right (a
"Right") for each outstanding share of common stock. The distribution was paid
on July 27, 1998 (the "Record Date") to the shareholders of record on that date.
Each Right entitles the registered holder thereof to purchase from the Company
one one-thousandth of a share of Series A Preferred Stock at a price of $25.00,
subject to adjustment.
The following is a summary of the Rights. The full description and
terms of the Rights are set forth in a Rights Agreement (the "Rights Agreement")
between the Company and UMB Bank, N.A., as Rights Agent (the "Rights Agent").
Copies of the Rights Agreement and the Certificate of Designation for the Series
A Preferred Stock are available free of charge from the Company. This summary
description of the Rights and the Series A Preferred Stock does not purport to
be complete and is qualified in its entirety by reference to all the provisions
of the Rights Agreement and the Certificate of Designation for the Series A
Preferred Stock, including the definitions therein of certain terms.
Initially, the Rights attached to all certificates representing shares
of outstanding Company common stock, and no separate Rights certificates were
distributed. The Rights will separate from the common stock and the Distribution
Date will occur upon the earlier of
o 10 days following the date of public announcement that a person or
group of persons has become an Acquiring Person, or
o 10 business days (or such later date as may be determined by action of
the Board of Directors prior to the time a person becomes an Acquiring
Person) following the commencement of, or the announcement of an
intention to make, a tender offer or exchange offer upon consummation
of which the offeror would, if successful, become an Acquiring Person
(the earlier of such dates being called the "Distribution Date").
The term "Acquiring Person" means any person who or which, together with
all of its affiliates and associates, is the beneficial owner of 15% or
more of the outstanding common stock, but does not include:
o the Company or any subsidiary of the Company or any employee benefit
plan of the Company,
o Aubrey K. McClendon, his spouse, lineal descendants and ascendants,
heirs, executors or other legal representatives and any trusts
established for the benefit of the foregoing or any other person or
entity in which the foregoing persons or entities are at the time of
determination the direct record and beneficial owners of all
outstanding voting securities (each a "McClendon Shareholder"),
o Tom L. Ward, his spouse, lineal descendants and ascendants, heirs,
executors or other legal representatives and any trusts established for
the benefit of the foregoing, or any other person or entity in which
the foregoing persons or entities are at the time of determination the
direct record and beneficial owners of all outstanding voting
securities (each a "Ward Shareholder"),
o Morgan Guaranty Trust Company of New York, in its capacity as pledgee
(the "McClendon/Ward Pledgee") of shares ("Pledged Shares")
beneficially owned by a McClendon or Ward Shareholder, or both, under
pledge agreement(s) in effect on September 11, 1998, to the extent that
upon the exercise by the McClendon/Ward Pledgee of any rights or duties
thereunder other than the exercise of any voting power by the
McClendon/Ward Pledgee or the acquisition of ownership by the
McClendon/Ward Pledgee, such McClendon/Ward Pledgee becomes a
beneficial owner of Pledged Shares, or
48
<PAGE> 50
o any person (other than a McClendon/Ward Pledgee) that is neither a
McClendon nor Ward Shareholder, but who or which is the beneficial
owner of common stock beneficially owned by a McClendon or Ward
Shareholder (a "Second Tier Shareholder"), but only if the shares of
common stock otherwise beneficially owned by such Second Tier
Shareholder ("Second Tier Holder Shares") do not exceed the sum of (A)
such holder's Second Tier Holder Shares held on September 11, 1998 and
(B) 1% of the shares of common stock of the Company then outstanding
(collectively, "Exempt Persons").
The Rights Agreement provides that, until the Distribution Date, the
Rights will be transferred with and only with the common stock. Until the
Distribution Date (or earlier redemption or expiration of the Rights), new
common stock certificates issued after the Record Date, upon transfer or new
issuance of common stock, will contain a notation incorporating the Rights
Agreement by reference. Until the Distribution Date (or earlier redemption or
expiration of the Rights), the surrender for transfer of any certificates for
common stock, outstanding as of the Record Date, even without such notation or a
copy of a summary of the Rights being attached thereto, will also constitute the
transfer of the Rights associated with the common stock represented by such
certificate. As soon as practicable following the Distribution Date, separate
certificates evidencing the Rights ("Rights Certificates") will be mailed to
holders of record of the common stock as of the close of business on the
Distribution Date and such separate Rights Certificates alone will evidence the
Rights.
The Rights are not exercisable until the Distribution Date. The Rights
will expire on July 27, 2008 (the "Expiration Date").
The purchase price payable, and the number of one one-thousandths of a
share of Series A Preferred Stock or other securities or property issuable, upon
exercise of the Rights are subject to adjustment from time to time to prevent
dilution:
o in the event of a stock dividend on, or a subdivision, combination or
reclassification of, the Series A Preferred Stock;
o upon the grant to holders of the Series A Preferred Stock of certain
rights or warrants to subscribe for or purchase shares of Series A
Preferred Stock at a price, or securities convertible into Series A
Preferred Stock with a conversion price, less than the then current
market price of the Series A Preferred Stock; or
o upon the distribution to holders of the Series A Preferred Stock of
evidences of indebtedness or assets (excluding regular periodic cash
dividends paid or dividends payable in Series A Preferred Stock) or of
subscription rights or warrants (other than those referred to above).
The number of outstanding Rights and the number of one one-thousandths
of a share of Series A Preferred Stock issuable upon exercise of each Right are
also subject to adjustment in the event of a stock split of the common stock or
a stock dividend on the common stock payable in the common stock or
subdivisions, consolidations or combinations of the common stock occurring, in
any such case, prior to the Distribution Date.
In the event that following a Stock Acquisition Date (the date of
public announcement that an Acquiring Person has become such) the Company is
acquired in a merger or other business combination transaction or more than 50%
of its consolidated assets or earning power are sold, proper provision will be
made so that each holder of a Right will thereafter have the right to receive,
upon the exercise thereof at the then current exercise price of the Right, that
number of shares of common stock of the acquiring company which at the time of
such transaction will have a market value of two times the exercise price of the
Right (the "flip-over right").
In the event that a person (other than an Exempt Person) becomes an
Acquiring Person, proper provision will be made so that each holder of a Right
(other than the Acquiring Person and its affiliates and associates) will
thereafter have the right to receive upon exercise that number of shares of
common stock (or, under certain circumstances, cash, other equity securities or
property of the Company) having a market value equal to two times the purchase
price of the Rights (the "flip-In right"). Upon the occurrence of the foregoing
event giving rise to the exercisability of the Rights, any Rights that are or
were at any time owned by an Acquiring Person will become void.
49
<PAGE> 51
With certain exceptions, no adjustment in the purchase price will be
required until cumulative adjustments require an adjustment of at least 1% in
the purchase price. Upon exercise of the Rights, no fractional shares of Series
A Preferred Stock will be issued other than fractions which are integral
multiples of one one-hundredth of a share of Series A Preferred Stock. Cash will
be paid in lieu of fractional shares of Series A Preferred Stock that are not
integral multiples of one one-hundredth of a share of Series A Preferred Stock.
At any time prior to the earlier to occur of (i) 5:00 p.m., Oklahoma
City, Oklahoma time on the 10th day after the Stock Acquisition Date or (ii) the
expiration of the Rights, the Company may redeem the Rights in whole, but not in
part, at a price of $0.01 per Right (the "Redemption Price"); provided, that (i)
if the Board of Directors authorizes redemption on or after the time a person
becomes an Acquiring Person, then such authorization must be by board approval
and (ii) the period for redemption may, upon board approval, be extended by
amending the Rights Agreement. Board approval means the approval of a majority
of the directors of the Company. Immediately upon any redemption of the Rights
described in this paragraph, the right to exercise the Rights will terminate and
the only right of the holders of Rights will be to receive the Redemption Price.
The terms of the Rights may be amended by the Board of Directors
without the consent of the holders of the Rights at any time and from time to
time provided that such amendment does not adversely affect the interests of the
holders of the Rights. In addition, during any time that the Rights are subject
to redemption, the terms of the Rights may be amended by the approval of a
majority of the directors, including an amendment that adversely affects the
interests of the holders of the Rights, without the consent of the holders of
Rights.
Until a Right is exercised, a holder will have no rights as a
shareholder of the Company, including, without limitation, the right to vote or
to receive dividends. While the distribution of the Rights will not be taxable
to shareholders or to the Company, shareholders may, depending upon the
circumstances, recognize taxable income in the event that the Rights become
exercisable for Series A Preferred Stock (or other consideration).
The Series A Preferred Stock. Each one-thousandth of a share of the
Series A Preferred Stock ("Preferred Share Fraction") that may be acquired upon
exercise of the Rights will be nonredeemable and subordinate to any other shares
of preferred stock that may be issued by the Company.
Each Preferred Share Fraction will have a minimum preferential
quarterly dividend rate of $0.01 per Preferred Share Fraction but will, in any
event, be entitled to a dividend equal to the per share dividend declared on the
common stock.
In the event of liquidation, the holder of a Preferred Share Fraction
will receive a preferred liquidation payment equal to the greater of $0.01 per
Preferred Share Fraction or the per share amount paid in respect of a share of
common stock.
Each Preferred Share Fraction will have one vote, voting together with
the common stock. The holders of Preferred Share Fractions, voting as a separate
class, will be entitled to elect two directors if dividends on the Series A
Preferred Stock are in arrears for six fiscal quarters.
In the event of any merger, consolidation or other transaction in which
shares of common stock are exchanged, each Preferred Share Fraction will be
entitled to receive the per share amount paid in respect of each share of common
stock.
The rights of holders of the Series A Preferred Stock to dividends,
liquidation and voting, and in the event of mergers and consolidations, are
protected by customary antidilution provisions.
Because of the nature of the Series A Preferred Stock's dividend,
liquidation and voting rights, the economic value of one Preferred Share
Fraction that may be acquired upon the exercise of each Right should approximate
the economic value of one share of the common stock.
50
<PAGE> 52
SHAREHOLDER ACTION
With respect to any act or action required of or by the holders of the
common stock, the affirmative vote of a majority of the shares of common stock
present in person or represented by proxy at a meeting and entitled to vote
thereon is sufficient to authorize, affirm, ratify or consent to such act or
actions, except as otherwise provided by law or in the Certificate of
Incorporation. The OGCA requires the approval of the holders of a majority of
the outstanding stock entitled to vote for certain extraordinary corporate
transactions, such as a merger, sale of substantially all assets, dissolution or
amendment of the Certificate of Incorporation. The Certificate of Incorporation
provides for a vote of the holders of two-thirds of the issued and outstanding
stock having voting power, voting as a single class, to amend, repeal or adopt
any provision inconsistent with the provisions of the Certificate of
Incorporation limiting director liability and stock purchases by the Company,
and providing for staggered terms of directors and indemnity for directors. Such
vote is also required for shareholders to amend, repeal or adopt any provision
of the Bylaws. Pursuant to Oklahoma law, shareholders may take actions without
the holding of a meeting by written consent or consents signed by the holders of
a sufficient number of shares to approve the transaction had all of the
outstanding shares of the capital stock of the Company entitled to vote thereon
been present at a meeting. Pursuant to the rules and regulations of the
Securities and Exchange Commission, if shareholder action is taken by written
consent, the Company will be required to send each shareholder entitled to vote
on the matter acted on, but whose consent was not solicited, an information
statement containing information substantially similar to that which would have
been contained in a proxy statement.
TRANSFER AGENT AND REGISTRAR
UMB Bank, N.A. is the transfer agent and registrar for the common stock
and the preferred stock.
51
<PAGE> 53
PLAN OF DISTRIBUTION
The sale or distribution of the shares of common stock offered by this
prospectus may be effected directly to purchasers by the selling shareholders
(including their respective donees, pledgees, transferees or other successors in
interest) as principals or through one or more underwriters, brokers, dealers or
agents from time to time in one or more transactions (which may involve crosses
or block transactions)
o on any national securities exchange or quotation service on which the
shares may be listed or quoted at the time of sale or in the
over-the-counter market,
o in transactions otherwise than on such an exchange or service or in
the over-the-counter market or
o through the writing of options (whether such options are listed on an
options exchange or otherwise) on, or settlement of short sale of the
shares.
Any of such transactions may be effected at market prices prevailing at the time
of sale, at prices related to such prevailing market prices, at varying prices
determined at the time of sale or at negotiated or fixed prices, in each case as
determined by the selling shareholder or by agreement between any selling
shareholder and underwriters, brokers, dealers or agents, or purchasers. In
connection with sales of the shares or otherwise, the selling shareholders may
enter into hedging transactions with broker-dealers, which may in turn engage in
short sales of the shares in the course of hedging the positions they assume.
The selling shareholders may also sell shares short and deliver shares to close
out such short positions, or loan or pledge shares to broker-dealers that in
turn may sell such shares. The selling shareholders have advised us that they
have not entered into any agreements, understandings or arrangements with any
underwriters or broker-dealers regarding the sale of their securities, nor is
there any underwriter or coordinating broker acting in connection with the
proposed sale of shares by the selling shareholders.
If the selling shareholders effect such transactions by selling shares
to or through underwriters, brokers, dealers or agents, such underwriters,
brokers, dealers or agents may receive compensation in the form of discounts,
concessions or commissions from the selling shareholders or commissions from
purchasers of shares for whom they may act as agent (which discounts,
concessions or commissions as to particular underwriters, brokers, dealers or
agents may be in excess of those customary in the types of transactions
involved). The selling shareholders and any brokers, dealers or agents that
participate in the distribution of the shares may be deemed to be underwriters,
and any profit on the sale of shares by them and any discounts, concessions or
commission received by any such underwriters, brokers, dealers or agents may be
deemed to be underwriting discounts and commissions under the Securities Act. In
addition, the anti-manipulation provisions of Regulation M under the Securities
Exchange Act of 1934 may apply to sales by the selling shareholders.
Under the securities laws of certain states, the securities may be sold
in such states only through registered or licensed brokers or dealers. In
addition, in certain states the shares may not be sold unless the shares have
been registered or qualified for sale in such state or an exemption from
registration or qualification is available and is complied with.
The Company will pay all of the expenses incident to the registration,
offering and sale of the shares to the public hereunder other than commissions,
fees and discounts of underwriters, brokers, dealers and agents. The Company has
agreed to indemnify the selling shareholders and any underwriters against
certain liabilities, including liabilities under the Securities Act. The Company
will not receive any of the proceeds from the sale of any of the shares by the
selling shareholders.
To the extent required, this prospectus may be amended or supplemented
from time to time to describe a specific plan of distribution. We will make
copies of this prospectus, as amended or supplemented, available to the selling
shareholders and have informed them of the need for delivery of the prospectus
to purchasers at or prior to the time of any sale of their shares.
52
<PAGE> 54
LEGAL MATTERS
The legality of the common stock offered hereby has been passed upon
for the Company by Winstead Sechrest & Minick P.C., Dallas, Texas.
EXPERTS
The consolidated financial statements of the Company as of December 31,
1999 and 1998, and for the years ended December 31, 1999 and 1998, the six
months ended December 31, 1997 and the year ended June 30, 1997, included in
this prospectus have been so included in reliance on the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in accounting and auditing.
Certain estimates of oil and gas reserves included in this prospectus
were based upon reserve reports, dated December 31, 1999, prepared by Williamson
Petroleum Consultants, Inc. and Ryder Scott Company L.P., independent petroleum
engineers. Such estimates are included in reliance on the authority of each such
firm as experts in such matters.
WHERE YOU CAN FIND MORE INFORMATION ABOUT US
We have filed a registration statement with the Securities and Exchange
Commission relating to the shares of common stock to be offered pursuant to this
prospectus. As allowed by the rules of the SEC, this prospectus does not contain
all of the information that can be found in the registration statement or in the
exhibits to the registration statement. You should read the registration
statement and its exhibits for a complete understanding of all of the
information included in the registration statement.
We file annual, quarterly and current reports, proxy statements and
other information with the SEC. You may read and copy the registration
statement, including exhibits, any reports, statements or other information that
we file at the SEC's public reference room at 450 Fifth Street N.W., Washington,
D.C. 20549 or at its regional public reference rooms in New York, New York and
Chicago, Illinois. You may call the SEC at 1-800-SEC-0330 for further
information on the operations and locations of the public reference rooms. The
public filings of the Company are also available from commercial document
retrieval services and at the Web site maintained by the SEC at www.sec.gov and
at our Web site at www.chkenergy.com. Reports, proxy statements and other
information concerning the Company may also be inspected at the offices of The
New York Stock Exchange, 20 Broad Street, New York, New York 10005.
53
<PAGE> 55
GLOSSARY
The terms defined in this section are used throughout this prospectus.
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.
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.
54
<PAGE> 56
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.
55
<PAGE> 57
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Financial Statements:
Consolidated Balance Sheets at March 31, 2000 (unaudited) and December 31, 1999 .................... F-2
Consolidated Statements of Operations for the Three Months Ended March 31, 2000 and 1999
(unaudited) .................................................................................... F-3
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2000 and 1999
(unaudited) ..................................................................................... F-4
Condensed Consolidating Statements of Comprehensive Income (Loss) for the
Three Months Ended March 31, 2000 and 1999 (unaudited) .......................................... F-5
Notes to Consolidated Financial Statements (unaudited) ............................................. F-6
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 .................................... F-15
Consolidated Balance Sheets at December 31, 1999 and 1998 .......................................... F-16
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 ............................. F-17
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 ............................. F-18
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 .................................................................... F-20
Notes to Consolidated Financial Statements ......................................................... F-21
Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts .................................................... F-54
</TABLE>
F-1
<PAGE> 58
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
2000 1999
----------- ------------
(UNAUDITED)
($ IN THOUSANDS)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents .................................................. $ 26,231 $ 38,658
Restricted cash ............................................................ 3,073 192
Accounts receivable:
Oil and gas sales ........................................................ 20,790 17,045
Oil and gas marketing sales .............................................. 21,814 18,199
Joint interest and other, net of allowances of $3,249,000
and $3,218,000, respectively ........................................... 11,976 11,247
Related parties .......................................................... 3,805 4,574
Inventory .................................................................. 4,063 4,582
Other ...................................................................... 5,784 3,049
----------- -----------
Total Current Assets ................................................ 97,536 97,546
----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ......................................... 2,362,596 2,315,348
Unevaluated properties ................................................... 36,409 40,008
Less: accumulated depreciation, depletion and amortization ............... (1,694,927) (1,670,542)
----------- -----------
704,078 684,814
Other property and equipment ............................................... 68,724 67,712
Less: accumulated depreciation and amortization ............................ (34,325) (33,429)
----------- -----------
Total Property and Equipment ........................................ 738,477 719,097
----------- -----------
OTHER ASSETS ................................................................. 29,358 33,890
----------- -----------
TOTAL ASSETS ................................................................. $ 865,371 $ 850,533
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt ..................... $ 781 $ 763
Accounts payable ........................................................... 22,346 24,822
Accrued liabilities and other .............................................. 38,260 34,713
Revenues and royalties due others .......................................... 24,756 27,888
----------- -----------
Total Current Liabilities ........................................... 86,143 88,186
----------- -----------
LONG-TERM DEBT, NET .......................................................... 960,416 964,097
----------- -----------
REVENUES AND ROYALTIES DUE OTHERS ............................................ 8,752 9,310
----------- -----------
DEFERRED INCOME TAXES ........................................................ 6,650 6,484
----------- -----------
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Stock, $.01 par value, 10,000,000 shares authorized;
3,921,400 and 4,596,400 shares of 7% cumulative convertible
stock issued and outstanding at March 31, 2000 and December 31,
1999, respectively, entitled in liquidation (including
dividends in arrears) to $216.4 million and
$249.1 million, respectively ............................................. 196,070 229,820
Common Stock, par value of $.01, 250,000,000 shares authorized;
108,561,616 and 105,858,580 shares issued at March 31, 2000 and
December 31, 1999, respectively .......................................... 1,086 1,059
Paid-in capital ............................................................ 684,755 682,905
Accumulated earnings (deficit) ............................................. (1,065,465) (1,093,929)
Accumulated other comprehensive income (loss) .............................. (282) 196
Less: treasury stock, at cost; 3,806,185 and 10,856,185 common shares at
March 31, 2000 and December 31, 1999, respectively ....................... (12,754) (37,595)
----------- -----------
Total Stockholders' Equity (Deficit) ................................ (196,590) (217,544)
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) ......................... $ 865,371 $ 850,533
=========== ===========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-2
<PAGE> 59
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
------------------------
2000 1999
--------- ---------
<S> <C> <C>
REVENUES:
Oil and gas sales ....................................... $ 87,293 $ 51,806
Oil and gas marketing sales ............................. 27,368 13,871
--------- ---------
Total revenues ...................................... 114,661 65,677
--------- ---------
OPERATING COSTS:
Production expenses ..................................... 12,545 13,992
Production taxes ........................................ 5,216 1,990
General and administrative .............................. 3,032 4,024
Oil and gas marketing expenses .......................... 26,544 13,285
Oil and gas depreciation, depletion and amortization .... 24,483 23,153
Depreciation and amortization of other assets ........... 1,866 2,166
--------- ---------
Total operating costs ............................... 73,686 58,610
--------- ---------
INCOME FROM OPERATIONS ................................... 40,975 7,067
--------- ---------
OTHER INCOME (EXPENSE):
Interest and other income ............................... 1,192 873
Interest expense ........................................ (20,864) (19,890)
--------- ---------
Total other income (expense) ........................ (19,672) (19,017)
--------- ---------
INCOME (LOSS) BEFORE INCOME TAX .......................... 21,303 (11,950)
--------- ---------
INCOME TAX EXPENSE:
Current ................................................. -- --
Deferred ................................................ 101 --
--------- ---------
Total income tax expense ............................ 101 --
--------- ---------
NET INCOME (LOSS) ........................................ 21,202 (11,950)
Preferred stock dividends ............................... (4,042) (4,026)
Gain on redemption of preferred stock ................... 10,414 --
--------- ---------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS ....... $ 27,574 $ (15,976)
========= =========
EARNINGS (LOSS) PER COMMON SHARE:
Basic ................................................... $ 0.27 $ (0.17)
========= =========
Assuming Dilution ....................................... $ 0.15 $ (0.17)
========= =========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING:
Basic ................................................... 101,681 96,710
========= =========
Assuming Dilution ....................................... 140,130 96,710
========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
<PAGE> 60
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
----------------------
2000 1999
-------- --------
($ IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ..................................................... $ 21,202 $(11,950)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization ............................. 25,420 24,550
Amortization of loan costs ........................................... 909 769
Amortization of bond discount ........................................ 21 21
(Gain) loss on sale of fixed assets and other ........................ (80) 78
Equity in losses of equity investees ................................. 119 --
Income tax expense ................................................... 101 --
-------- --------
Cash provided by operating activities before changes in
current assets and liabilities .................................. 47,692 13,468
Changes in current assets and liabilities ............................ (9,477) 12,830
-------- --------
Cash provided by operating activities .............................. 38,215 26,298
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties ................. (40,252) (44,590)
Purchases of oil and gas properties ................................... (4,564) (3,988)
Sales of oil and gas properties ....................................... 985 2,070
Sales of non-oil and gas assets ....................................... 177 1,062
Additions to other property and equipment ............................. (1,191) (712)
Other ................................................................. (2,045) 327
-------- --------
Cash used in investing activities .................................. (46,890) (45,831)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings .................................... 45,000 --
Payments on long-term borrowings ...................................... (48,500) --
Cash received from exercise of stock options .......................... 226 --
-------- --------
Cash used in financing activities .................................. (3,274) --
-------- --------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH .............................. (478) 816
-------- --------
NET DECREASE IN CASH AND CASH EQUIVALENTS ............................... (12,427) (18,717)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD .......................... 38,658 29,520
-------- --------
CASH AND CASH EQUIVALENTS, END OF PERIOD ................................ $ 26,231 $ 10,803
======== ========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
<PAGE> 61
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
----------------------
2000 1999
-------- --------
($ in thousands)
<S> <C> <C>
Net income (loss) .................................................... $ 21,202 $(11,950)
Other comprehensive income (loss) - foreign currency translation
adjustments .......................................................... (478) 816
-------- --------
Comprehensive income (loss) .......................................... $ 20,724 $(11,134)
======== ========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
<PAGE> 62
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
(UNAUDITED)
1. ACCOUNTING PRINCIPLES
The accompanying unaudited consolidated financial statements of Chesapeake
Energy Corporation and Subsidiaries (the "Company") have been prepared in
accordance with the instructions to Form 10-Q as prescribed by the Securities
and Exchange Commission. All material adjustments (consisting solely of normal
recurring adjustments) which, in the opinion of management, are necessary for a
fair presentation of the results for the interim periods have been reflected.
The results for the three months ended March 31, 2000 are not necessarily
indicative of the results to be expected for the full year.
This Form 10-Q relates to the three months ended March 31, 2000 (the "Current
Quarter") and March 31, 1999 (the "Prior Quarter").
2. LEGAL PROCEEDINGS
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 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
F-6
<PAGE> 63
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
(UNAUDITED)
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 supersedes bonds in all of these cases. 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 in the U.S. District Court, Northern District of Texas, Amarillo Division.
The only other case pending in that court resulted in a jury verdict for CP and
its co-defendants. Judgment has not yet been entered in that 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.
3. 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 numerators
and denominators of the basic and diluted EPS computations. For the Prior
Quarter 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 14.8
million shares and 13.7 million shares of common stock at a weighted average
exercise price of $1.83 and $1.71 were outstanding during the Current Quarter
and Prior Quarter, respectively. In the Prior Quarter the outstanding options,
and the assumed conversion of the outstanding preferred stock (33.1 million
shares), were not included in the computation of diluted EPS because the effect
would be antidilutive. A reconciliation for the Current Quarter is as follows:
F-7
<PAGE> 64
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
(UNAUDITED)
<TABLE>
<CAPTION>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
<S> <C> <C> <C>
FOR THE QUARTER ENDED MARCH 31, 2000:
BASIC EPS
Income available to common stockholders ......... $ 27,574 101,681 $ 0.27
========
EFFECT OF DILUTIVE SECURITIES
Assumed conversion of preferred stock at
beginning of period ........................ 4,042 32,951
Gain on redemption of preferred stock ......... (10,414) --
Employee stock options ........................ -- 5,498
-------- --------
DILUTED EPS
Income available to common stockholders
and assumed conversions ...................... $ 21,202 140,130 $ 0.15
======== ======== ========
</TABLE>
In the Current Quarter, the Company engaged in a number of separate stock
exchange transactions with institutional investors. The Company exchanged a
total of 9.5 million shares of common stock (both newly issued and treasury
shares) for 675,000 shares of its issued and outstanding preferred stock with a
liquidation value of $33.8 million plus dividends in arrears of $3.2 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. A gain on redemption of the preferred shares equal to $10.4
million was recognized as an increase to net income in the Current Quarter in
determining basic earnings per share. The gain represented the excess of (i) the
liquidation value of the preferred shares that were retired plus dividends in
arrears which had reduced prior EPS over (ii) the market value of the common
stock issued in exchange for the preferred shares.
Between April 1 and May 9, 2000, the Company engaged in additional transactions
in which a total of 13.5 million shares of common stock were exchanged for
1,055,658 shares of its issued and outstanding preferred stock with a
liquidation value of $52.8 million plus dividends in arrears of $5.8 million.
Including the stock exchange transactions through May 9, 2000, a total of 23.0
million shares of common stock have been exchanged for 1,730,658 shares of
preferred stock. These transactions have reduced (i) the number of preferred
shares from 4.6 million to 2.9 million, (ii) the liquidation value of the
preferred stock from $229.8 million to $143.3 million, and (iii) dividends in
arrears from $25.0 million to $16.0 million. A gain on redemption of all
preferred shares exchanged through May 9, 2000 of $16.4 million ($10.4 million
related to the Current Quarter) will be reflected in net income available to
common shareholders in determining earnings per share.
4. SENIOR NOTES
9.625% Notes
The Company has outstanding $500 million in aggregate principal amount of 9.625%
Senior Notes which mature May 1, 2005. The 9.625% Notes bear interest at the
rate of 9.625%, payable semiannually on each May 1 and November 1. The 9.625%
Notes are senior, unsecured obligations of the Company and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
9.125% Notes
The Company has outstanding $120 million in aggregate principal amount of 9.125%
Senior Notes which mature April 15, 2006. The 9.125% Notes bear interest at an
annual rate of 9.125%, payable semiannually on each April 15 and October 15. The
9.125% Notes are senior, unsecured obligations of the Company and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
F-8
<PAGE> 65
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
(UNAUDITED)
7.875% Notes
The Company has outstanding $150 million in aggregate principal amount of 7.875%
Senior Notes which mature March 15, 2004. The 7.875% Notes bear interest at the
rate of 7.875%, payable semiannually on each March 15 and September 15. The
7.875% Notes are senior, unsecured obligations of the Company and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
8.5% Notes
The Company has outstanding $150 million in aggregate principal amount of 8.5%
Senior Notes which mature March 15, 2012. The 8.5% Notes bear interest at the
rate of 8.5%, payable semiannually on each March 15 and September 15. The 8.5%
Notes are senior, unsecured obligations of the Company and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
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 its 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. 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.
These 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 March 31, 2000, 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 $20.3 million related to its preferred stock as of March 31, 2000.
Including accrued dividends from April 1 through May 9, 2000, this amount has
subsequently been reduced to approximately $16.0 million as of May 9, 2000 as a
result of additional stock exchange transactions. This restriction does not
affect the Company's ability to borrow under or expand its secured commercial
bank facility. The Company was unable to pay a dividend on the preferred stock
on May 1, 2000, the sixth consecutive dividend payment date on which dividends
have not been paid. If the Company fails to pay dividends for six quarterly
periods, the holders of preferred stock are entitled to elect two new directors
to the Board. Based on current projections of cash flow and fixed charges, the
Company expects to be able to pay a dividend on the preferred stock on August 1,
2000, although there are no assurances the Board of Directors will declare a
dividend, even if the Company is able to resume paying dividends.
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, the Company's subsidiaries which are not guarantors of
the Senior Notes (the "Non-Guarantor Subsidiaries") and the Company. Separate
financial statements of each Guarantor Subsidiary have not been provided because
management has determined that they are not material to investors.
Chesapeake Energy Marketing, Inc. ("CEMI") was a Non-Guarantor Subsidiary for
all periods presented. All of the Company's other subsidiaries were Guarantor
Subsidiaries during all periods presented.
F-9
<PAGE> 66
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF MARCH 31, 2000
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- ----------- ------------ ------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ................... $ (10,964) $ 23,031 $ 17,237 $ -- $ 29,304
Accounts receivable, net .................... 51,313 21,629 95 (14,652) 58,385
Inventory ................................... 3,917 146 -- -- 4,063
Other ....................................... 4,602 815 367 -- 5,784
----------- ----------- ----------- ----------- -----------
Total Current Assets ..................... 48,868 45,621 17,699 (14,652) 97,536
----------- ----------- ----------- ----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties ...................... 2,362,596 -- -- -- 2,362,596
Unevaluated leasehold ....................... 36,409 -- -- -- 36,409
Other property and equipment ................ 29,655 20,537 18,532 -- 68,724
Less: accumulated depreciation,
depletion and amortization ................ (1,709,363) (17,892) (1,997) -- (1,729,252)
----------- ----------- ----------- ----------- -----------
Net Property and Equipment ............... 719,297 2,645 16,535 -- 738,477
----------- ----------- ----------- ----------- -----------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES ....................... 806,181 -- 493,738 (1,299,919) --
----------- ----------- ----------- ----------- -----------
OTHER ASSETS .................................. 10,699 8,389 17,956 (7,686) 29,358
----------- ----------- ----------- ----------- -----------
TOTAL ASSETS .................................. $ 1,585,045 $ 56,655 $ 545,928 $(1,322,257) $ 865,371
=========== =========== =========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt ......................... $ 781 $ -- $ -- $ -- $ 781
Accounts payable and other .................. 51,163 22,696 26,110 (14,607) 85,362
----------- ----------- ----------- ----------- -----------
Total Current Liabilities ................ 51,944 22,696 26,110 (14,607) 86,143
----------- ----------- ----------- ----------- -----------
LONG-TERM DEBT ................................ 41,235 -- 919,181 -- 960,416
----------- ----------- ----------- ----------- -----------
REVENUES AND ROYALTIES DUE
OTHERS ...................................... 8,752 -- -- -- 8,752
----------- ----------- ----------- ----------- -----------
DEFERRED INCOME TAXES ......................... 6,650 -- -- -- 6,650
----------- ----------- ----------- ----------- -----------
INTERCOMPANY PAYABLES ......................... 1,371,729 (2,773) (1,368,911) (45) --
----------- ----------- ----------- ----------- -----------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock ................................ 26 1 1,076 (17) 1,086
Other ....................................... 104,709 36,731 968,472 (1,307,588) (197,676)
----------- ----------- ----------- ----------- -----------
104,735 36,732 969,548 (1,307,605) (196,590)
----------- ----------- ----------- ----------- -----------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT) .............. $ 1,585,045 $ 56,655 $ 545,928 $(1,322,257) $ 865,371
=========== =========== =========== =========== ===========
</TABLE>
F-10
<PAGE> 67
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1999
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) 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>
F-11
<PAGE> 68
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED MARCH 31, 2000:
REVENUES:
Oil and gas sales ........................... $ 86,221 $ 347 $ -- $ 725 $ 87,293
Oil and gas marketing sales ................. -- 69,850 -- (42,482) 27,368
--------- --------- --------- --------- ---------
Total Revenues ........................... 86,221 70,197 -- (41,757) 114,661
--------- --------- --------- --------- ---------
OPERATING COSTS:
Production expenses and taxes ............... 17,681 80 -- -- 17,761
General and administrative .................. 2,720 291 21 -- 3,032
Oil and gas marketing expenses .............. -- 68,301 -- (41,757) 26,544
Oil and gas depreciation, depletion
and amortization .......................... 24,383 100 -- -- 24,483
Other depreciation and amortization ......... 1,026 20 820 -- 1,866
--------- --------- --------- --------- ---------
Total Operating Costs .................... 45,810 68,792 841 (41,757) 73,686
--------- --------- --------- --------- ---------
INCOME (LOSS) FROM OPERATIONS ................. 40,411 1,405 (841) -- 40,975
--------- --------- --------- --------- ---------
OTHER INCOME (LOSS):
Interest and other income ................... 798 336 20,967 (20,909) 1,192
Interest expense ............................ (20,955) (34) (20,784) 20,909 (20,864)
--------- --------- --------- --------- ---------
(20,157) 302 183 -- (19,672)
--------- --------- --------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES ............. 20,254 1,707 (658) -- 21,303
INCOME TAX EXPENSE (BENEFIT) .................. 101 -- -- -- 101
--------- --------- --------- --------- ---------
NET INCOME (LOSS) ............................. $ 20,153 $ 1,707 $ (658) $ -- $ 21,202
========= ========= ========= --------- =========
FOR THE THREE MONTHS ENDED MARCH 31, 1999:
REVENUES:
Oil and gas sales ........................... $ 51,209 $ -- $ -- $ 597 $ 51,806
Oil and gas marketing sales ................. -- 35,435 -- (21,564) 13,871
--------- --------- --------- --------- ---------
Total Revenues ........................... 51,209 35,435 -- (20,967) 65,677
--------- --------- --------- --------- ---------
OPERATING COSTS:
Production expenses and taxes ............... 15,982 -- -- -- 15,982
General and administrative .................. 3,522 457 45 -- 4,024
Oil and gas marketing expenses .............. -- 34,252 -- (20,967) 13,285
Oil and gas depreciation, depletion
and amortization .......................... 23,153 -- -- -- 23,153
Other depreciation and amortization ......... 1,338 20 808 -- 2,166
--------- --------- --------- --------- ---------
Total Operating Costs .................... 43,995 34,729 853 (20,967) 58,610
--------- --------- --------- --------- ---------
INCOME (LOSS) FROM OPERATIONS ................. 7,214 706 (853) -- 7,067
--------- --------- --------- --------- ---------
OTHER INCOME (LOSS):
Interest and other income ................... 267 437 29,140 (28,971) 873
Interest expense ............................ (28,406) -- (20,455) 28,971 (19,890)
--------- --------- --------- --------- ---------
(28,139) 437 8,685 -- (19,017)
--------- --------- --------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES ............. (20,925) 1,143 7,832 -- (11,950)
INCOME TAX EXPENSE (BENEFIT) .................. -- -- -- -- --
--------- --------- --------- --------- ---------
NET INCOME (LOSS) ............................. $ (20,925) $ 1,143 $ 7,832 $ -- $ (11,950)
========= ========= ========= --------- =========
</TABLE>
F-12
<PAGE> 69
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED MARCH 31, 2000:
CASH FLOWS FROM OPERATING ACTIVITIES ........... $ 29,595 $ (289) $ 8,909 $ -- $ 38,215
-------- -------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net .................. (47,546) 3,715 -- -- (43,831)
Proceeds from sale of assets ................. 177 -- -- -- 177
Additions to other property and equipment .... (753) (16) (422) -- (1,191)
Other additions .............................. (35) -- (2,010) -- (2,045)
-------- -------- -------- -------- --------
(48,157) 3,699 (2,432) -- (46,890)
-------- -------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES ........... 12,159 (788) (14,645) -- (3,274)
-------- -------- -------- -------- --------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH ..... (478) -- -- -- (478)
-------- -------- -------- -------- --------
NET INCREASE (DECREASE) IN CASH ................ (6,881) 2,622 (8,168) -- (12,427)
CASH, BEGINNING OF PERIOD ...................... (7,156) 20,409 25,405 -- 38,658
-------- -------- -------- -------- --------
CASH, END OF PERIOD ............................ $(14,037) $ 23,031 $ 17,237 $ -- $ 26,231
======== ======== ======== ======== ========
FOR THE THREE MONTHS ENDED MARCH 31, 1999:
CASH FLOWS FROM OPERATING ACTIVITIES ........... $ 1,617 $ 7,490 $ 17,191 $ -- $ 26,298
-------- -------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net .................. (46,508) -- -- -- (46,508)
Proceeds from sale of assets ................. 1,062 -- -- -- 1,062
Additions to other property and equipment .... 240 (195) (757) -- (712)
Other additions .............................. 327 -- -- -- 327
-------- -------- -------- -------- --------
(44,879) (195) (757) -- (45,831)
-------- -------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES ........... 44,819 (2,888) (41,931) -- --
-------- -------- -------- -------- --------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH ..... 816 -- -- -- 816
-------- -------- -------- -------- --------
NET INCREASE (DECREASE) IN CASH ................ 2,373 4,407 (25,497) -- (18,717)
CASH, BEGINNING OF PERIOD ...................... (17,319) 7,000 39,839 -- 29,520
-------- -------- -------- -------- --------
CASH, END OF PERIOD ............................ $(14,946) $ 11,407 $ 14,342 $ -- $ 10,803
======== ======== ======== ======== ========
</TABLE>
F-13
<PAGE> 70
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED MARCH 31, 2000:
Net income (loss) ............................ $ 20,153 $1,707 $ (658) $ -- $ 21,202
Other comprehensive income (loss) -
foreign currency translation ............... (478) -- -- -- (478)
-------- ------ ------- -------- --------
Comprehensive income ......................... $ 19,675 $1,707 $ (658) $ -- $ 20,724
-------- ====== ======= ======== ========
FOR THE THREE MONTHS ENDED MARCH 31, 1999:
Net income (loss) ............................ $(20,925) $1,143 $ 7,832 $ -- $(11,950)
Other comprehensive income (loss) -
foreign currency translation ............... 816 -- -- -- 816
-------- ------ ------- -------- --------
Comprehensive income (loss) .................. $(20,109) $1,143 $ 7,832 $ -- $(11,134)
-------- ====== ======= ======== ========
</TABLE>
5. Subsequent Event
On June 30, 2000, the Company entered into a letter of intent to
acquire Gothic Energy Corporation (OTC Bulletin Board "GOTH") for 4.0 million
shares of common stock. Upon the closing of the transaction, Gothic's
shareholders will own approximately 2.7% of Chesapeake's common stock. In
addition, on June 27, 2000, we purchased in a series of private transactions 96%
of Gothic's $104 million of 14 1/8% Series B Senior Secured Discount Notes for
consideration of $77 million, comprised of $22 million in cash and 9,468,985
shares of Chesapeake common stock (valued at $5.825 per share), subject to
adjustment.
Including our assumption of $235 million of Gothic's Senior Secured
Notes, The total acquisition cost to Chesapeake will be approximately $345
million, including $235 million of Senior Secured Notes issued by Gothic's
operating subsidiary. This values Gothic's 310 Bcfe of proved reserves at $1.05
per Mcfe after allocation of $20 million of the purchase price to Gothic's
leasehold inventory, 3-D seismic inventory, lease operating telemetry system and
other assets. Gothic's proved reserves are 96% natural gas, 78% proved
developed, have an average lifting cost of less than $0.20 per Mcfe, are located
exclusively in Chesapeake's core Mid-Continent operating area and are unhedged
after October 2000.
F-14
<PAGE> 71
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
In our opinion, the consolidated financial statements as of December 31,
1999 and 1998, for the years ended December 31, 1999 and 1998 and June 30, 1997
and the six months ended December 31, 1997 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
F-15
<PAGE> 72
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.
F-16
<PAGE> 73
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.
F-17
<PAGE> 74
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.
F-18
<PAGE> 75
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 $1,405,000, which was
paid on July 15, 1997.
The accompanying notes are an integral part of these
consolidated financial statements.
F-19
<PAGE> 76
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) AND
COMPREHENSIVE INCOME (LOSS)
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
-------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
------------ ------------ ------------ ------------
($ 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.
F-20
<PAGE> 77
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.
F-21
<PAGE> 78
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.
F-22
<PAGE> 79
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 in 1998, the
Transition Period and fiscal 1997, because the effect of these outstanding
options would be antidilutive. Also, the convertible preferred stock was not
included in the 1999 and 1998 calculation because the effect was anti-dilutive.
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.
F-23
<PAGE> 80
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.
F-24
<PAGE> 81
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 $19.3 million related to its preferred stock as of
February 29, 2000. Subsequent payments will be subject to the same restrictions
and are dependent upon variables that are beyond the Company's ability to
predict. This restriction does not affect the Company's ability to borrow under
or expand its secured commercial bank facility. If the Company fails to pay
dividends for six quarterly periods, the holders of preferred stock will be
entitled to elect two new directors to the Board. Based on current projections
of cash flow and fixed charges, the Company does not expect to be able to pay a
dividend on the preferred stock on May 1, 2000, which would be the sixth
consecutive dividend payment date on which dividends have not been paid.
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, the Company's subsidiaries which are not guarantors of
the Senior Notes (the "Non-Guarantor Subsidiaries") and the Company. Separate
audited financial statements of each Guarantor Subsidiary have not been provided
because management has determined that they are not material to investors.
Chesapeake Energy Marketing, Inc. ("CEMI") was a Non-Guarantor Subsidiary
for all periods presented. The following were additional Non-Guarantor
Subsidiaries: Chesapeake Acquisition Corporation during the Transition Period
and Chesapeake Canada Corporation during fiscal 1997. All of the Company's other
subsidiaries were Guarantor Subsidiaries during all periods presented.
F-25
<PAGE> 82
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1999
($ 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>
F-26
<PAGE> 83
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>
F-27
<PAGE> 84
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>
F-28
<PAGE> 85
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>
F-29
<PAGE> 86
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>
F-30
<PAGE> 87
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>
F-31
<PAGE> 88
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>
F-32
<PAGE> 89
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
F-33
<PAGE> 90
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:
F-34
<PAGE> 91
<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
F-35
<PAGE> 92
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 $53,885 28%
Koch Oil Company 29,580 15
GPM Gas Corporation 27,682 14
</TABLE>
Management believes that the loss of any of the above customers would not
have a material impact on the Company's results of operations or its financial
position.
The Company believes all of its material operations are part of the oil and
gas industry, and therefore reports as a single industry segment. Beginning in
1998, the Company began foreign operations in Canada. The geographic
F-36
<PAGE> 93
distribution of the Company's revenue, operating income and identifiable assets
are summarized below ($ 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
F-37
<PAGE> 94
(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.
F-38
<PAGE> 95
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
-------- ------- -------
<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
F-39
<PAGE> 96
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):
F-40
<PAGE> 97
<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.
F-41
<PAGE> 98
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 interest rate swap agreement contains a
"knockout provision" whereby the agreement will terminate on or after May 1,
2001 if the average closing price for the previous twenty business days for the
shares of the Company's common stock is greater than or equal to $7.50 per
share. The agreement also provides for a maximum floating rate of 8.5% from May
2001 through April 2008.
If the interest rate swap agreement had been settled on December 31, 1999,
the Company would have been required to pay the counterparty approximately
$16.7 million. However, because of the knock-out provision discussed above and
the volatility of interest rates, the Company does not believe that this
worst-case scenario is a fair measure of the market value of the swap agreement
and, therefore, would not pay this amount to cancel the transaction. Results
from interest rate hedging transactions are reflected as adjustments to
interest expense in the corresponding months covered by the swap agreement.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the long-term debt
has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
-----------------------------------------------------------------------------------------
YEARS OF MATURITY
-----------------------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
-------- -------- -------- -------- -------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES: ($ 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
F-42
<PAGE> 99
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>
F-43
<PAGE> 100
<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>
F-44
<PAGE> 101
<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
F-45
<PAGE> 102
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>
F-46
<PAGE> 103
<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.
F-47
<PAGE> 104
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>
F-48
<PAGE> 105
<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>
F-49
<PAGE> 106
<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>
F-50
<PAGE> 107
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
F-51
<PAGE> 108
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:
F-52
<PAGE> 109
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 $50
million liquidation amount of Gothic Series B preferred stock, including
dividends in arrears, and 2.4 million shares of Gothic common stock, for
a permanent assignment to Chesapeake of certain undeveloped leasehold
interests that were originally subject to a reassignment obligation to
Gothic.
F-53
<PAGE> 110
SCHEDULE II
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ 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 $ -- $(5,931)(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.
F-54
<PAGE> 111
No dealer, salesperson or other individual has been authorized to give any
information or to make any representations not contained in this prospectus in
connection with the offering covered by this prospectus. If given or made, such
information or representations must not be relied upon as having been authorized
by the company or any of the selling shareholders. This prospectus does not
constitute an offer to sell, or a solicitation of an offer to buy, the common
stock in any jurisdiction where, or to any person to whom, it is unlawful to
make such offer or solicitation. Neither the delivery of this prospectus nor any
sale made hereunder shall, under any circumstances, create an implication that
there has not been any change in the facts set forth in this prospectus or in
the affairs of the company since the date hereof.
----------
TABLE OF CONTENTS
PAGE
----
Forward-Looking Statements............................................. 2
The Company............................................................ 3
Risk Factors........................................................... 3
Use of Proceeds........................................................ 7
Dividend Policy........................................................ 7
Market Price of Common Stock........................................... 8
Selected Financial Data................................................ 9
Management's Discussion and Analysis................................... 11
Quantitative and Qualitative Disclosure About Market Risks............. 17
Business............................................................... 19
Management............................................................. 31
Executive Compensation................................................. 34
Certain Transactions................................................... 39
Security Ownership..................................................... 41
Selling Shareholders................................................... 43
Description of Capital Stock........................................... 44
Plan of Distribution................................................... 52
Legal Matters.......................................................... 53
Experts................................................................ 53
Where You Can Find More Information About Us........................... 53
Glossary............................................................... 54
Index to Financial Statements.......................................... F-1
----------
20,000,000 Shares
CHESAPEAKE ENERGY
CORPORATION
COMMON STOCK
----------
PROSPECTUS
----------
JULY 7, 2000
<PAGE> 112
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The Company has agreed to bear all expenses to be incurred in
connection with the registration of the shares being offered by the selling
shareholders. The selling shareholders will bear any underwriting discounts,
commissions and transfer taxes associated with the sale of the shares. The
Company has also agreed to indemnify the selling shareholders against certain
liabilities, including liabilities under the Securities Act of 1933, as amended
(the "Securities Act"). The following table sets forth the estimated expenses of
the offering. With the exception of the Securities Act registration fee, all
amounts shown are estimates.
Securities Act registration fee $ 36,142
Legal fees 50,000
Accounting fees 25,000
Printing expenses 60,000
Miscellaneous 5,000
--------
Total $176,142
========
ITEM 14. INDEMNIFICATION OF OFFICERS AND DIRECTORS
Section 1031 of the Oklahoma General Corporation Act, under which the
Registrant is incorporated, authorizes the indemnification of directors and
officers under certain circumstances. Article VIII of the Certificate of
Incorporation of the Registrant and Article VI of the Bylaws of the Registrant
also provide for indemnification of directors and officers under certain
circumstances. These provisions, together with the Registrant's indemnification
obligations under individual indemnity agreements with its directors and
officers, may be sufficiently broad to indemnify such persons for liabilities
under the Securities Act of 1933, as amended. In addition, the Registrant
maintains insurance, which insures its directors and officers against certain
liabilities.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES
On April 22, 1998, the Company sold 4,600,000 shares of its 7%
Cumulative Convertible Preferred Stock having a liquidation preference of $50
per share in a private placement to Donaldson, Lufkin & Jenrette Securities
Corporation, Morgan Stanley & Co. Incorporated, Bear, Stearns & Co. Inc., Lehman
Brothers Inc. and J.P. Morgan Securities Inc. (the "Initial Purchasers")
pursuant to the exemption from registration provided by Section 4(2) of the
Securities Act. The Initial Purchasers resold the shares to qualified
institutional buyers, as defined in, and in reliance on the exemption from
registration provided by, Rule 144A under the Securities Act. The aggregate
offering price for the shares was $230 million, and aggregate discounts and
commissions were $6.9 million.
On July 7, 1998, the Company's Board of Directors declared a dividend
distribution of one preferred stock purchase right (a "right") for each
outstanding share of common stock of the Company. The distribution was paid on
July 27, 1998 to the shareholders of record on that date. Each right entitles
the registered holder thereof to purchase from the Company one one-thousandths
of a share of Series A Junior Participating Preferred Stock, par value $0.01 per
share, of the Company at a price of $25.00, subject to adjustment.
During the quarter ended March 31, 2000, the Company exchanged
9,493,750 shares of common stock for 675,000 shares of its outstanding 7%
Cumulative Convertible Preferred Stock held by institutional investors. The
Company exchanged an additional 24.7 million shares of common stock and a cash
payment of $8.3 million for 2,364,363 shares of 7% Cumulative Convertible
Preferred Stock held by institutional investors during the quarter ended June
30, 2000. The exchanges were exempt from registration under Section 3(a)(9) of
the Securities
II-1
<PAGE> 113
Act inasmuch as the Company exchanged securities exclusively with its existing
shareholders and no commission or other remuneration was paid with respect to
the exchanges.
On June 27, 2000, the Company's wholly owned subsidiary Chesapeake
Energy Marketing, Inc. acquired 14 1/8% Series B Senior Secured Discount Notes
of Gothic Energy Corporation having an accreted value of $77.5 million for
9,468,985 shares of newly issued Company common stock and $22.4 million of cash.
The shares were sold pursuant to the exemption from registration provided by
Section 4(2) of the Securities Act. These shares are covered by this
Registration Statement.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits. The following exhibits are filed herewith pursuant to the
requirements of Item 601 of Regulation S-K:
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<S> <C>
2.1* Senior Secured Discount Notes Purchase Agreement dated June 23,
2000 between Chesapeake Energy Marketing, Inc. and Appaloosa
Investment Limited Partnership I, Palomino Fund Ltd. and Tersk
L.L.C
2.2* Senior Secured Discount Notes Purchase Agreement dated June 23,
2000 between Chesapeake Energy Marketing, Inc. and Oppenheimer
Strategic Income Fund, Oppenheimer Champion Income Fund,
Oppenheimer High Yield Fund, Oppenheimer Strategic Bond Fund/VA
and Atlas Strategic Income Fund.
2.3* Senior Secured Discount Notes Purchase Agreement dated June 26,
2000 between Chesapeake Energy Marketing, Inc. and John Hancock
High Yield Bond Fund and John Hancock Variable Annuity High Yield
Bond Fund.
2.4* Senior Secured Discount Notes Purchase Agreement dated June 26,
2000 between Chesapeake Energy Marketing, Inc. and Ingalls &
Snyder Value Partners, L.P., Heritage Mark Foundation and Arthur
R. Ablin.
2.5* Letter of Intent dated June 30, 2000 from Chesapeake Energy
Corporation to Gothic Energy Corporation regarding the proposed
acquisition of Gothic Energy Corporation.
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).
3.1.1* Certificates of Elimination filed April 11, 2000, June 20, 2000
and July 6, 2000 with the Secretary of State of the State of
Oklahoma.
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.
</TABLE>
II-2
<PAGE> 114
<TABLE>
<S> <C>
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
issuer, its subsidiaries signatory thereto, 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 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.
4.6* Common Stock Registration Rights Agreement as of June 27, 2000
among the Registrant and Appaloosa Investment Limited Partnership
I, Palomino Fund Ltd., Tersk L.L.C., Oppenheimer Strategic Income
Fund, Oppenheimer Champion Income Fund, Oppenheimer High Yield
Fund, Oppenheimer Strategic Bond Fund/VA and Atlas Strategic
Income Fund.
5.1* Opinion of Winstead Sechrest & Minick P.C. regarding the validity
of the securities being registered.
</TABLE>
II-3
<PAGE> 115
<TABLE>
<S> <C>
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.
10.1.6+ Registrant's 2000 Employee Stock Option Plan. Incorporated herein
by reference to Exhibit 10.1.6 to Registrant's quarterly report
on Form 10-Q for the quarter ended March 31, 2000.
10.1.7 Registrant's 2000 Executive Officer Stock Option Plan.
Incorporated herein by reference to Registrant's quarterly report
on Form 10-Q for the quarter ended March 31, 2000.
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 June 1,
2000 between Marcus C. Rowland and Chesapeake Energy Corporation.
10.2.4+* Amendment to the Employment Agreement between Marcus C. Rowland
and Chesapeake Energy Corporation dated May 24, 2000.
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.
</TABLE>
II-4
<PAGE> 116
<TABLE>
<S> <C>
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. Incorporated
herein by reference to Exhibit 10.11 to Registrant's annual
report on Form 10-K for the year ended June 30, 1997.
21 Subsidiaries of Registrant. Incorporated herein by reference to
Exhibit 21 to Registrant's annual report on Form 10-K for the
year ended December 31, 1999.
23.1* Consent of PricewaterhouseCoopers LLP
23.2* Consent of Williamson Petroleum Consultants, Inc.
23.3* Consent of Ryder Scott Company Petroleum Engineers
24.1* Power of Attorney.
</TABLE>
----------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Financial Statement Schedules. Schedule II, Valuation and Qualifying
Accounts is included with the Company's audited consolidated financial
statements included in the prospectus which is Part I of this Registration
Statement. No other financial statement schedules are applicable or required.
II-5
<PAGE> 117
ITEM 17. UNDERTAKINGS
(a) The Registrant hereby undertakes:
(1) to file, during any period in which offers or sales are being
made, a post-effective amendment to this Registration Statement:
(i) to include any prospectus required by Section 10(a)(3) of
the Securities Act of 1933;
(ii) to reflect in the prospectus any facts or events arising
after the effective date of this Registration Statement (or
the most recent post-effective amendment thereof) which,
individually or in the aggregate, represent a fundamental
change in the information set forth in this Registration
Statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total
dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or high
end of the estimated maximum offering range may be reflected
in the form of prospectus filed with the commission pursuant
to Rule 424(b) if, in the aggregate, the changes in volume
and price represent no more than a 20% change in the maximum
aggregate offering price set forth in the "Calculation of
Registration Fee" table in the effective registration
statement;
(iii) to include any material information with respect to the
plan of distribution not previously disclosed in this
Registration Statement or any material change to such
information in this Registration Statement;
provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not
apply if the information required to be included in a post-effective
amendment by those paragraphs is contained in periodic reports filed
by the Registrant pursuant to Section 13 or Section 15(d) of the
Securities Exchange Act of 1934 that are incorporated by reference in
this Registration Statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall
be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering
thereof.
(3) To remove from registration by means of a post-effective
amendment any of the securities being registered which remain
unsold at the termination of the offering.
(b) The Registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
Registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in this
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered herein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(c) Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of the Registrant pursuant to the foregoing provisions, or
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<PAGE> 118
otherwise, the Registrant has been advised that in the opinion of the Securities
and Exchange Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the
event that a claim for indemnification against such liabilities (other than the
payment by the Registrant of expenses incurred or paid by a director, officer or
controlling person of the Registrant in the successful defense of any action,
suit or proceeding) is asserted by such director, officer or controlling person
in connection with the securities being registered, the Registrant will, unless
in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
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<PAGE> 119
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma
City, State of Oklahoma on July 7, 2000.
CHESAPEAKE ENERGY CORPORATION
By: /s/ AUBREY K. MCCLENDON
-----------------------------------
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities indicated on July 7, 2000.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<S> <C>
/s/ AUBREY K. MCCLENDON Chairman of the Board, Chief Executive Officer and
-------------------------- Director (Principal Executive Officer)
Aubrey K. McClendon
/s/ TOM L. WARD President, Chief Operating Officer and Director
-------------------------- (Principal Executive Officer)
Tom L. Ward
/s/ MARCUS C. ROWLAND Executive Vice President and Chief Financial Officer
-------------------------- (Principal Financial Officer)
Marcus C. Rowland
/s/ MICHAEL A. JOHNSON Senior Vice President - Accounting
-------------------------- (Principal Accounting Officer)
Michael A. Johnson
/s/ EDGAR F. HEIZER, JR. Director
--------------------------
Edgar F. Heizer, Jr.
/s/ BREENE M. KERR Director
--------------------------
Breene M. Kerr
/s/ SHANNON T. SELF Director
--------------------------
Shannon T. Self
/s/ FREDERICK B. WHITTEMORE Director
--------------------------
Frederick B. Whittemore
</TABLE>
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<PAGE> 120
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<S> <C>
2.1* Senior Secured Discount Notes Purchase Agreement dated June 23,
2000 between Chesapeake Energy Marketing, Inc. and Appaloosa
Investment Limited Partnership I, Palomino Fund Ltd. and Tersk
L.L.C
2.2* Senior Secured Discount Notes Purchase Agreement dated June 23,
2000 between Chesapeake Energy Marketing, Inc. and Oppenheimer
Strategic Income Fund, Oppenheimer Champion Income Fund,
Oppenheimer High Yield Fund, Oppenheimer Strategic Bond Fund/VA
and Atlas Strategic Income Fund.
2.3* Senior Secured Discount Notes Purchase Agreement dated June 26,
2000 between Chesapeake Energy Marketing, Inc. and John Hancock
High Yield Bond Fund and John Hancock Variable Annuity High Yield
Bond Fund.
2.4* Senior Secured Discount Notes Purchase Agreement dated June 26,
2000 between Chesapeake Energy Marketing, Inc. and Ingalls &
Snyder Value Partners, L.P., Heritage Mark Foundation and Arthur
R. Ablin.
2.5* Letter of Intent dated June 30, 2000 from Chesapeake Energy
Corporation to Gothic Energy Corporation regarding the proposed
acquisition of Gothic Energy Corporation.
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).
3.1.1* Certificates of Elimination filed April 11, 2000, June 20, 2000
and July 6, 2000 with the Secretary of State of the State of
Oklahoma.
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.
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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
issuer, its subsidiaries signatory thereto, 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 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.
4.6* Common Stock Registration Rights Agreement as of June 27, 2000
among the Registrant and Appaloosa Investment Limited Partnership
I, Palomino Fund Ltd., Tersk L.L.C., Oppenheimer Strategic Income
Fund, Oppenheimer Champion Income Fund, Oppenheimer High Yield
Fund, Oppenheimer Strategic Bond Fund/VA and Atlas Strategic
Income Fund.
5.1* Opinion of Winstead Sechrest & Minick P.C. regarding the validity
of the securities being registered.
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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.
10.1.6+ Registrant's 2000 Employee Stock Option Plan. Incorporated herein
by reference to Exhibit 10.1.6 to Registrant's quarterly report
on Form 10-Q for the quarter ended March 31, 2000.
10.1.7 Registrant's 2000 Executive Officer Stock Option Plan.
Incorporated herein by reference to Registrant's quarterly report
on Form 10-Q for the quarter ended March 31, 2000.
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 June 1,
2000 between Marcus C. Rowland and Chesapeake Energy Corporation.
10.2.4* Amendment to the Employment Agreement between Marcus C. Rowland
and Chesapeake Energy Corporation dated May 24, 2000.
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.
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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. Incorporated
herein by reference to Exhibit 10.11 to Registrant's annual
report on Form 10-K for the year ended June 30, 1997.
21 Subsidiaries of Registrant. Incorporated herein by reference to
Exhibit 21 to Registrant's annual report on Form 10-K for the
year ended December 31, 1999.
23.1* Consent of PricewaterhouseCoopers LLP
23.2* Consent of Williamson Petroleum Consultants, Inc.
23.3* Consent of Ryder Scott Company Petroleum Engineers
24.1* Power of Attorney.
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* Filed herewith.
+ Management contract or compensatory plan or arrangement.
