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Filed Pursuant to Rule 424(b)(3)
Registration Statement No. 333-45872
PROSPECTUS
October 4, 2000
CHESAPEAKE ENERGY CORPORATION
389,378 SHARES OF COMMON STOCK
The selling shareholder described in this prospectus may offer and sell
from time to time 389,378 shares of our common stock.
We will not receive any proceeds from the sale of shares of common
stock by the selling shareholder, but we will bear all of the expenses, other
than commissions or discounts of broker-dealers.
On October 3, 2000, the last reported sale price of the common stock
(symbol "CHK") on the New York Stock Exchange was $7.44.
SEE "RISK FACTORS" BEGINNING ON PAGE 4 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.
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TABLE OF CONTENTS
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PAGE
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The Company...................................................................................................3
Risk Factors..................................................................................................4
Forward-Looking Statements....................................................................................7
Use of Proceeds...............................................................................................9
Dividend Policy...............................................................................................9
Market Price of Common Stock.................................................................................10
Selected Financial Data......................................................................................11
Management's Discussion and Analysis of Financial Condition and Results of Operations........................13
Quantitative and Qualitative Disclosures About Market Risk...................................................22
Business.....................................................................................................24
Management...................................................................................................36
Executive Compensation.......................................................................................39
Certain Transactions.........................................................................................44
Security Ownership...........................................................................................46
Selling Shareholder..........................................................................................48
Description of the Capital Stock.............................................................................49
Plan of Distribution.........................................................................................57
Legal Matters................................................................................................58
Experts......................................................................................................58
Where You Can Find More Information..........................................................................58
Glossary.....................................................................................................59
Index to Financial Statements...............................................................................F-1
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THE COMPANY
Chesapeake Energy Corporation is an independent energy company focused
on the exploration, development, acquisition and production of onshore natural
gas reserves, principally in the Mid-Continent region of the United States. 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. Our primary operating area is the Mid-Continent region, which
includes Oklahoma, western Arkansas, southwestern Kansas and the Texas
Panhandle. Our other operating areas are:
o the Gulf Coast region consisting primarily of the Austin Chalk
Trend in Texas and Louisiana and the Tuscaloosa Trend in
Louisiana;
o the Helmet area of northeastern British Columbia; and
o the Permian Basin region of West Texas and Southeastern New
Mexico.
During 1999, we produced 133.5 Bcfe, making Chesapeake one of the 15 largest
public independent oil and gas producers in the United States. During the six
months ended June 30, 2000, we produced 68.0 Bcfe.
RECENT DEVELOPMENTS
On September 8, 2000, we entered into an Agreement and Plan of Merger
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 2.5% of Chesapeake's common stock. In
addition, in a series of private transactions from June 27, 2000 through
September 21, 2000, we purchased 99.8% of Gothic's $104 million of 14.125%
Series B Senior Secured Discount Notes for total consideration of $80.8 million,
comprised of $23.3 million in cash and $57.5 million of Chesapeake common stock
(9,858,363 shares valued at $5.825 per share), subject to adjustment. We also
purchased $20 million of the $235 million of 11.125% Senior Secured Notes issued
by Gothic's operating subsidiary for $22 million of Chesapeake common stock
(3,694,939 shares valued at $6.0371 per share, subject to adjustment) in a
private transaction that closed on September 1, 2000.
Gothic's proved reserves, estimated to be 322 Bcfe at June 30, 2000,
are 96% natural gas and 86% proved developed, have an average lifting cost of
less than $0.20 per Mcfe, are located primarily in Chesapeake's core
Mid-Continent operating area, and are unhedged after December 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. In addition, Chesapeake intends to
allocate approximately $20 million of the purchase price to Gothic's undeveloped
leasehold inventory, 3-D seismic inventory, lease operating telemetry system and
other assets. 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 approval by Gothic's shareholders
and other closing conditions. Completion of the transaction is expected in
January 2001.
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.
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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.
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 June 30, 2000, we had long-term indebtedness of $983.2 million
(which included bank indebtedness of $63.0 million) and stockholders' equity was
a deficit of $120.0 million. If our acquisition of Gothic Energy Corporation had
been completed as of June 30, 2000, our long-term indebtedness, on a pro forma
basis, would have been $1.2 billion. Our ability to meet our debt service
requirements throughout the life of our senior notes and, if the acquisition of
Gothic Energy Corporation is completed, the senior notes of Gothic's subsidiary
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.
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Unless we replace the reserves we produce through successful development,
exploration or acquisition, our proved reserves will decline over time. In
addition, approximately 28% by volume, or 20% by value, of our total estimated
proved reserves at December 31, 1999 were undeveloped. By their nature,
undeveloped reserves are less certain. Recovery of such reserves will require
significant capital expenditures and successful drilling operations. We cannot
assure you that we can successfully find and produce reserves economically in
the future.
SIGNIFICANT CAPITAL EXPENDITURES WILL BE REQUIRED TO EXPLOIT RESERVES
We have made and intend to make substantial capital expenditures in
connection with the exploration, development and production of our oil and gas
properties. Historically, we have funded our capital expenditures through a
combination of internally generated funds, equity issuances and long-term debt
financing arrangements and sale of non-core assets. From time to time, we have
used short-term bank debt, generally as a working capital facility. Future cash
flows are subject to a number of variables, such as the level of production from
existing wells, prices of oil and gas, and our success in developing and
producing new reserves. 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.
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 MAY RESTRICT OUR OPERATIONS
Our bank credit agreement and the indentures which govern our senior
notes contain covenants which may 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
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o guaranteeing indebtedness.
From December 31, 1998 through March 31, 2000, we did not meet the debt
incurrence test, and were therefore not able to incur unsecured debt or pay
dividends on our preferred stock. Beginning June 30, 2000, we meet the debt
incurrence test, but significantly lower oil and gas prices or poor operating
results could cause us to fail the test in the future.
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 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.
TRANSACTIONS WITH EXECUTIVE OFFICERS MAY CREATE CONFLICTS OF INTEREST
Our Chief Executive Officer, Aubrey K. McClendon, and our Chief
Operating Officer, Tom L. 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 September 29, 2000, our board of directors and senior management
beneficially owned an aggregate of 25,198,434 shares of common stock (including
outstanding vested options), which represented approximately 16% of our
outstanding shares. The beneficial ownership of Messrs. McClendon and Ward
accounted for 14% 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 Agreement and Plan of Merger they
executed on September 8, 2000. These conditions include the following:
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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;
o fulfillment of the conditions contained in the Bear, Stearns &
Co. Inc. financing commitment; and
o compliance with the conditions precedent to a merger contained
in Gothic's indentures.
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.
THE TWO COMPANIES MAY NOT BE SUCCESSFULLY COMBINED INTO A SINGLE ENTITY
If we cannot successfully combine our operations, we may not realize
the anticipated benefits of the merger. Combining two companies that have
previously operated separately involves a number of risks and could result in
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.
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, Chesapeake's financial position, business strategy and
other plans and objectives for future operations, expected future expenses and
preferred stock dividend payments, 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 Chesapeake,
including, without limitation, factors discussed under "Risk Factors," are:
o substantial indebtedness;
o need to replace reserves;
o substantial capital requirements;
o fluctuations in the prices of oil and gas;
o uncertainties inherent in estimating quantities of oil and gas
reserves;
o projecting future rates of production and the timing of
development expenditures;
o operating risks;
o restrictions imposed by lenders;
o the effects of governmental and environmental regulation;
o pending litigation;
o conflicts of interest our CEO and COO may have; and
o uncertainties relating to the proposed business combination with
Gothic.
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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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USE OF PROCEEDS
We will not receive any proceeds from this offering. We are registering
our common stock on behalf of the selling shareholder. If and when the selling
shareholder sells its stock, it 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.
Our bank credit agreement and two of the indentures governing our
outstanding senior notes contain restrictions on our ability to declare and pay
dividends. Under these indentures, Chesapeake 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 Chesapeake 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
Chesapeake 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, we did not meet the debt
incurrence tests under these indentures and were not able to pay dividends on
our common or preferred stock. We did meet the tests as of June 30, 2000, and
are therefore able to incur unsecured non-bank debt and are eligible to resume
the payment of dividends on our preferred stock. On September 22, 2000, our
board of directors declared a regular quarterly dividend and a special dividend
in the amount of all accrued and unpaid dividends on the preferred stock,
payable on November 1, 2000.
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. These transactions reduced the number of preferred shares from
4.6 million to 1.6 million, 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.
From July 1 to August 16, 2000, we engaged in additional transactions
in which 9.2 million shares of common stock were exchanged for 933,000 shares of
preferred stock with a liquidation value of $46.7 million plus dividends in
arrears of $6.1 million.
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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:
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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
Nine months ending September 30, 2000:
First Quarter 3.31 1.94
Second Quarter 8.00 2.75
Third Quarter 8.25 5.31
</TABLE>
At September 29, 2000 there were 1,041 holders of record of common
stock and approximately 26,000 beneficial owners.
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SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of
Chesapeake for the six months ended June 30, 2000 and 1999, the years 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 and 1996. The data are derived from the audited consolidated
financial statements of Chesapeake, except for periods for the six months ended
June 30, 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 Chesapeake. Acquisitions we made 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.
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SIX MONTHS ENDED
JUNE 30,
----------------------
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 ............................ $ 187,514 $ 120,078
Oil and gas marketing sales .................. 61,610 26,491
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Total revenues .......................... 249,124 146,569
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Operating costs:
Production expenses .......................... 25,126 25,175
Production taxes ............................. 10,933 4,788
General and administrative ................... 6,220 7,292
Oil and gas marketing expenses ............... 59,666 24,958
Oil and gas depreciation,
depletion and amortization ............... 49,360 47,386
Depreciation and amortization of
other assets ............................... 3,702 4,138
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Total operating costs ................... 155,007 113,737
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Income from operations .......................... 94,117 32,832
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Other income (expense):
Interest and other income .................... 2,859 3,840
Interest expense ............................. (42,677) (40,149)
--------- ---------
(39,818) (36,309)
--------- ---------
Income (loss) before income taxes ............... 54,299 (3,477)
Provision (benefit) for income taxes ............ 1,463 326
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Net income (loss) ............................... 52,836 (3,803)
Preferred stock dividends ....................... (6,949) (8,052)
Gain on redemption of preferred stock ........... 11,895 --
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Net income (loss) available to common
shareholders ............................... $ 57,782 $ (11,855)
========= =========
Earnings (loss) per common share:
Basic ...................................... $ 0.53 $ (0.12)
Assuming dilution .......................... $ 0.36 $ (0.12)
Cash dividends declared per common share .......... $ -- $ --
CASH FLOW DATA:
Cash provided by operating activities before
changes in working capital ................. $ 107,753 $ 48,145
Cash provided by operating activities ........... 83,870 47,566
Cash used in investing activities ............... (130,569) (67,345)
Cash provided by financing activities ........... 20,264 14,187
Effect of exchange rate changes on cash ......... (204) 3,625
BALANCE SHEET DATA (at end of period):
Total assets .................................... $ 980,982 N/A
Long-term debt, net of current maturities ....... 983,230 N/A
Stockholders' equity (deficit) .................. (119,980) N/A
</TABLE>
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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)
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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>
12
<PAGE> 13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
The following table sets forth certain operating data of Chesapeake for
the periods presented:
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
JUNE 30, DECEMBER 31,
------------------------- ---------------------------------------
2000 1999 1999 1998 1997
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (MBbl) .................................. 1,655 2,362 4,147 5,976 3,511
Gas (MMcf) .................................. 58,086 52,706 108,610 94,421 59,236
Gas equivalent (MMcfe) ...................... 68,016 66,878 133,492 130,277 80,302
OIL AND GAS SALES ($ IN 000'S):
Oil ......................................... $ 40,588 $ 31,335 $ 66,413 $ 75,877 $ 68,079
Gas ......................................... 146,926 88,743 214,032 181,010 130,331
----------- ----------- ----------- ----------- -----------
Total oil and gas sales ............. $ 187,514 $ 120,078 $ 280,445 $ 256,887 $ 198,410
=========== =========== =========== =========== ===========
AVERAGE SALES PRICE:
Oil ($ per Bbl) ............................. $ 24.52 $ 13.27 $ 16.01 $ 12.70 $ 19.39
Gas ($ per Mcf) ............................. $ 2.53 $ 1.68 $ 1.97 $ 1.92 $ 2.20
Gas equivalent ($ per Mcfe) ................. $ 2.76 $ 1.80 $ 2.10 $ 1.97 $ 2.47
OIL AND GAS COSTS ($ PER MCFE):
Production expenses and taxes ............... $ .53 $ .45 $ .45 $ .45 $ .24
General and administrative .................. $ .09 $ .11 $ .10 $ .15 $ .14
Depreciation, depletion and amortization .... $ .73 $ .71 $ .71 $ 1.13 $ 1.59
</TABLE>
RESULTS OF OPERATIONS
Three Months Ended June 30, 2000 vs. June 30, 1999
General. For the three months ended June 30, 2000 (the "Current
Quarter"), Chesapeake realized net income of $31.6 million, or $0.22 per diluted
common share. This compares to net income of $8.1 million, or $0.04 per diluted
common share, in the three months ended June 30, 1999 (the "Prior Quarter").
Oil and Gas Sales. During the Current Quarter, oil and gas sales
increased 47% to $100.2 million from $68.3 million in the Prior Quarter. For the
Current Quarter, Chesapeake produced 34.1 Bcfe, consisting of 0.8 million
barrels of oil and 29.3 Bcf of natural gas, compared to 1.1 million barrels of
oil and 27.0 Bcf, or 33.6 Bcfe, in the Prior Quarter. Average oil prices
realized were $24.46 per barrel of oil in the Current Quarter compared to $16.01
per barrel in the Prior Quarter, an increase of 53%. Average gas prices realized
were $2.76 per Mcf in the Current Quarter compared to $1.88 per Mcf in the Prior
Quarter, an increase of 47%.
For the Current Quarter, Chesapeake realized an average price of $2.94
per Mcfe, compared to $2.03 per Mcfe in the Prior Quarter. Chesapeake's hedging
activities resulted in decreased oil and gas revenues of $11.0 million, or $0.32
per Mcfe, in the Current Quarter, compared to increased oil and gas revenues of
$2.9 million, or $0.09 per Mcfe, in the Prior Quarter.
The following table shows Chesapeake's production by region for the
Current Quarter and the Prior Quarter:
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED JUNE 30,
--------------------------------------------------
2000 1999
----------------------- -----------------------
OPERATING AREAS MMcfe PERCENT MMcfe PERCENT
-------------------------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Mid-Continent ............ 19,265 57% 17,520 52%
Gulf Coast ............... 8,650 25 10,683 32
Canada ................... 3,579 10 3,134 9
Permian Basin ............ 1,528 5 1,239 4
Other Areas .............. 1,063 3 990 3
---------- ---------- ---------- ----------
Total ............... 34,085 100% 33,566 100%
========== ========== ========== ==========
</TABLE>
Natural gas production represented approximately 86% of Chesapeake's
total production volume on an equivalent basis in the Current Quarter, compared
to 81% in the Prior Quarter.
13
<PAGE> 14
Oil and Gas Marketing Sales. Chesapeake realized $34.2 million in oil
and gas marketing sales to third parties in the Current Quarter, with
corresponding oil and gas marketing expenses of $33.1 million, for a margin of
$1.1 million. This compares to sales of $12.6 million, expenses of $11.7
million, and a margin of $0.9 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 and Chesapeake's initial
marketing of oil which began in June 1999.
Production Expenses. Production expenses increased to $12.6 million in
the Current Quarter, a $1.4 million increase from the $11.2 million of
production expenses incurred in the Prior Quarter. On a unit of production
basis, production expenses were $0.37 and $0.33 per Mcfe in the Current and
Prior Quarters, respectively. Chesapeake 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 $5.7 million and $2.8 million in the Current and Prior
Quarters, respectively. On a per unit basis, production taxes were $0.17 per
Mcfe in the Current Quarter compared to $0.08 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 $24.9 million, compared to $24.2 million in the Prior Quarter. The
DD&A rate per Mcfe increased from $0.72 in the Prior Quarter to $0.73 in the
Current Quarter. Chesapeake expects the DD&A rate will increase moderately from
current levels during the remainder of 2000 and is expected to increase further
upon the completion of the Gothic acquisition.
Depreciation and Amortization of Other Assets. Depreciation and
amortization of other assets ("D&A") was $1.8 million in the Current Quarter
compared to $2.0 million in the Prior Quarter. Chesapeake 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 $3.2 million in the Current Quarter compared to $3.3 million in the Prior
Quarter. Chesapeake capitalized $1.5 million of internal costs in the Current
Quarter directly related to Chesapeake's oil and gas exploration and development
efforts, compared to $0.8 million in the Prior Quarter. The increase in
capitalized internal costs is primarily due to the addition of technical
employees and other related costs. Chesapeake 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 $1.7 million compared to $3.0 million in the Prior Quarter. The
decrease is due primarily to a $1.5 million gain on the sale of certain
marketing assets located in the Mid-Continent in the Prior Quarter.
Interest Expense. Interest expense increased to $21.8 million in the
Current Quarter from $20.3 million in the Prior Quarter as a result of lower
capitalized interest and higher amounts of indebtedness. In addition to the
interest expense reported, Chesapeake capitalized $0.6 million of interest
during the Current Quarter compared to $1.0 million capitalized in the Prior
Quarter.
Provision for Income Taxes. Chesapeake recorded income tax expense of
$1.4 million for the Current Quarter and $0.3 million in the Prior Quarter. The
income tax expense recorded in both the Current Quarter and Prior Quarter is
related to Chesapeake's Canadian operations. At June 30, 2000, Chesapeake had a
U.S. net operating loss carryforward of approximately $640 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
U.S. net operating loss carryforwards, will be realized in future years, and
therefore a valuation allowance of $424.3 million has been recorded. However,
management continues to evaluate the deferred tax assets. If oil and gas prices
as well as improvements in Chesapeake's operating performance continue to
strengthen and stabilize in future periods, all or a portion of the valuation
allowance may be reversed.
14
<PAGE> 15
Six Months Ended June 30, 2000 vs. June 30, 1999
General. For the six months ended June 30, 2000 (the "Current Period"),
Chesapeake realized net income of $52.8 million, or $0.36 per diluted common
share. This compares to a net loss of $3.8 million, or a net loss of $0.12 per
diluted common share after deducting preferred dividends of $8.1 million, in the
six months ended June 30, 1999 (the "Prior Period").
Oil and Gas Sales. During the Current Period, oil and gas sales
increased to $187.5 million from $120.1 million, an increase of $67.4 million,
or 56%. For the Current Period, Chesapeake produced 1.7 million barrels of oil
and 58.1 Bcf, compared to 2.4 million barrels of oil and 52.7 Bcf in the Prior
Period. Average oil prices realized were $24.52 per barrel in the Current Period
compared to $13.27 per barrel in the Prior Period, an increase of 85%. Average
gas prices realized were $2.53 per Mcf in the Current Period compared to $1.68
per Mcf in the Prior Period, an increase of 51%.
For the Current Period, Chesapeake realized an average price of $2.76
per Mcfe, compared to $1.80 per Mcfe in the Prior Period. Chesapeake's hedging
activities resulted in decreased oil and gas revenues of $13.2 million, or $0.19
per Mcfe, in the Current Period, compared to increased oil and gas revenues of
$3.2 million in the Prior Period.
The following table shows Chesapeake's production by region for the
Current Period and the Prior Period:
<TABLE>
<CAPTION>
FOR THE SIX MONTHS ENDED JUNE 30,
-------------------------------------------------------
2000 1999
-------------------------- --------------------------
OPERATING AREAS MMcfe PERCENT MMcfe PERCENT
------------------------------ ------------ ----------- ------------ ----------
<S> <C> <C> <C> <C>
Mid-Continent................. 38,294 56% 33,828 51%
Gulf Coast.................... 18,832 28 22,086 33
Canada........................ 6,504 10 5,564 8
Permian Basin ................ 3,127 4 2,469 4
Other areas................... 1,259 2 2,931 4
------- ----- ------- ----
Total......................... 68,016 100% 66,878 100%
======= ===== ======= ====
</TABLE>
Natural gas production represented approximately 85% of Chesapeake's
total production volume on an equivalent basis in the Current Period, compared
to 79% in the Prior Period.
Oil and Gas Marketing Sales. Chesapeake realized $61.6 million in oil
and gas marketing sales to third parties in the Current Period, with
corresponding oil and gas marketing expenses of $59.7 million for a margin of
$1.9 million. This compares to sales of $26.5 million and expenses of $25.0
million in the Prior Period for a margin of $1.5 million. The increase in
marketing sales and cost of sales was due primarily to higher oil and gas prices
in the Current Period as compared to the Prior Period and Chesapeake's initial
marketing of oil which began in June 1999.
Production Expenses. Production expenses decreased to $25.1 million in
the Current Period, a $0.1 million decrease from $25.2 million incurred in the
Prior Period. On a production unit basis, production expenses were $0.37 and
$0.38 per Mcfe in the Current and Prior Periods, respectively.
Production Taxes. Production taxes, which consist primarily of wellhead
severance taxes, were $10.9 million and $4.8 million in the Current and Prior
Periods, respectively. This increase was the result of increased natural gas
production and higher oil and gas prices. On a per unit basis, production taxes
were $0.16 per Mcfe in the Current Period compared to $0.07 per Mcfe in the
Prior Period.
Oil and Gas Depreciation, Depletion and Amortization. DD&A for the
Current Period was $49.4 million, compared to $47.4 million in the Prior Period.
This increase was caused by increased production as well as an increase in the
DD&A rate per Mcfe from $0.71 to $0.73 in the Prior and Current Periods,
respectively.
Depreciation and Amortization of Other Assets. D&A decreased to $3.7
million in the Current Period compared to $4.1 million in the Prior Period.
15
<PAGE> 16
General and Administrative. G&A, which is net of capitalized internal
payroll and non-payroll expenses, was $6.2 million in the Current Period
compared to $7.3 million in the Prior Period. This decrease was primarily due to
cost efficiencies that were generated throughout 1999 and an increase in
capitalized internal costs between periods. Chesapeake capitalized $3.4 million
of internal costs in the Current Period directly related to Chesapeake's oil and
gas exploration and development efforts, compared to $2.0 million in the Prior
Period. The increase in capitalized internal costs is primarily due to the
addition of technical employees and other related costs.
Interest and Other Income. Interest and other income for the Current
Period was $2.9 million compared to $3.8 million in the Prior Period. This
decrease is due primarily to a $1.5 million gain on the sale of certain
marketing assets located in the Mid-Continent in the Prior Period.
Interest. Interest expense increased to $42.7 million in the Current
Period from $40.1 million in the Prior Period as a result of lower capitalized
interest and higher amounts of indebtedness. Chesapeake capitalized $1.3 million
of interest during the Current Period compared to $2.2 million capitalized in
the Prior Period.
Provision for Income Taxes. Chesapeake recorded income tax expense of
$1.5 million for the Current Period, compared to $0.3 million in the Prior
Period. The income tax expense in both Periods is entirely related to
Chesapeake's operations in Canada. Management believes that it cannot be
demonstrated that it is more likely than not that its domestic deferred income
tax assets will be realizable in future years, and therefore a valuation
allowance of $424.3 million has been recorded. However, management continues to
evaluate the deferred tax assets. If oil and gas prices as well as improvements
in Chesapeake's operating performance continue to strengthen and stabilize in
future periods, all or a portion of the valuation allowance may be reversed.
Years Ended December 31, 1999, 1998 and 1997
General. In 1999, Chesapeake 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, and a
net loss of $233.4 million, or a loss of $3.30 per diluted common share, on
total revenues of $302.8 million during the year ended December 31, 1997. 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,
Chesapeake 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 Chesapeake's production by region for 1999,
1998 and 1997:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------
1999 1998 1997
--------------------- --------------------- --------------------
OPERATING AREAS 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 -- --
Permian Basin....................... 5,408 4 3,939 3 1,656 2
All other areas..................... 1,579 1 3,869 3 299 --
-------- ------ -------- ----- ------- ----
Total production.............. 133,492 100% 130,277 100% 80,302 100%
======== ====== ======== ===== ======= ====
</TABLE>
Natural gas production represented approximately 81% of Chesapeake's
total production volume on an equivalent basis in 1999, compared to 72% in 1998
and 74% in 1997.
For 1999, Chesapeake 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. Chesapeake'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.
16
<PAGE> 17
Oil and Gas Marketing Sales. Chesapeake 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.
Impairment of Oil and Gas Properties. Chesapeake 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 Chesapeake's independent engineering
consultants and Chesapeake's 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.
Chesapeake 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 Chesapeake 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 Chesapeake's proved reserves decreased from $17.62
per Bbl of oil and $2.29 per Mcf of gas at December 31, 1997, to $10.48 per Bbl
of oil and $1.68 per Mcf of gas at December 31, 1998. Higher drilling and
completion costs and the evaluation of certain leasehold, seismic and other
exploration-related costs that were previously unevaluated were the remaining
factors which contributed to the writedown in 1998.
Chesapeake 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. Chesapeake incurred a $55 million
impairment charge during 1998. Of this amount, $30 million related to
Chesapeake's investment in preferred stock of Gothic Energy Corporation, and the
remainder was related to certain of Chesapeake'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. 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. Chesapeake did not have operations in Canada prior to 1998.
Depreciation and Amortization of Other Assets. 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.
17
<PAGE> 18
General and Administrative. G&A expenses, which are net of capitalized
internal payroll and non-payroll expenses (see note 11 of the notes to our
audited consolidated financial statements included at the end of this
prospectus), 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
Chesapeake's growth and industry wage inflation. Chesapeake capitalized $2.7
million, $5.3 million and $5.3 million of internal costs in 1999, 1998 and 1997,
respectively, directly related to Chesapeake's oil and gas exploration and
development efforts.
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, Chesapeake 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 Chesapeake'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, Chesapeake capitalized $3.5 million of interest
during 1999, compared to $6.5 million capitalized in 1998, and $10.4 million
capitalized in 1997.
Provision (Benefit) for Income Taxes. Chesapeake 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 Chesapeake's Canadian operations.
At December 31, 1999, Chesapeake 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 was recorded.
RISK MANAGEMENT ACTIVITIES
See "Quantitative and Qualitative Disclosures About Market Risk."
LIQUIDITY AND CAPITAL RESOURCES
Chesapeake had working capital of $2.3 million at June 30, 2000 and a
cash balance (including restricted cash) of $16.8 million. Chesapeake has a $100
million revolving bank credit facility, which matures in July 2002, with a
committed borrowing base of $100 million. As of June 30, 2000, Chesapeake 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. On August 1,
2000, the borrowing base increased to $100 million from $75 million.
In a series of private transactions from June 27, 2000 through
September 21, 2000, we purchased 99.8% of Gothic's $104 million of 14.125%
Series B Senior Secured Discount Notes for total consideration of $80.8 million,
comprised of $23.3 million in cash and $57.5 million of Chesapeake common stock
(9,858,363 million shares valued at $5.825 per share), subject to adjustment.
The discount notes accrete at a rate per annum of 14.125%, compounded
semiannually to an aggregate principal amount of $104.0 million at May 1, 2002.
Thereafter, the discount notes accrue interest at the rate of 14.125% per annum,
payable in cash semiannually in arrears on May 1 and November 1 of each year
commencing November 1, 2002. The discount notes mature on May 1, 2006 and are
secured by the stock of Gothic's operating subsidiary.
On September 1, 2000, we purchased $20 million of the $235 million of
11.125% Senior Secured Notes issued by Gothic's operating subsidiary for $22
million of Chesapeake common stock (3,694,939 shares valued at $6.0371 per
share, subject to adjustment) in a private transaction. The senior secured notes
mature on May 1, 2005, bear interest at the rate of 11.125% per annum, payable
semiannually in cash on May 1 and November 1 of each year and are secured by oil
and gas interests owned by the issuer.
On September 8, 2000, Chesapeake entered into an Agreement and Plan of
Merger to acquire the common stock of Gothic for 4.0 million shares of
Chesapeake common stock. Upon the closing of the transaction, Gothic's
shareholders will own approximately 2.5% of Chesapeake's common stock. The total
acquisition cost to Chesapeake, including the Gothic notes described above, will
be approximately $345 million, plus transaction expenses and adjusted for any
working capital at the time of the merger. The Gothic acquisition is subject to
approval by Gothic's shareholders and other closing conditions. Completion of
the transaction is expected in January 2001.
18
<PAGE> 19
At June 30, 2000, Chesapeake's senior notes represented $919.2 million
of its $999.5 million of long-term liabilities. Debt ratings for the senior
notes are B2 by Moody's Investors Service and B by Standard & Poor's Corporation
as of August 1, 2000. On July 5, 2000, Standard & Poor's Corporation placed its
ratings on Chesapeake on credit watch with positive implications. 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 Chesapeake and its
restricted subsidiaries to incur additional indebtedness. This restriction does
not affect Chesapeake's ability to borrow under or expand its secured commercial
bank facility. As of June 30, 2000, Chesapeake estimates that secured commercial
bank indebtedness of $152.2 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 Chesapeake'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, Chesapeake 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. Chesapeake had accumulated
dividends in arrears of $9.5 million related to its preferred stock as of June
30, 2000. Chesapeake was unable to pay a dividend on the preferred stock on May
1, 2000, the sixth consecutive dividend payment date on which dividends had not
been paid. As a result of Chesapeake's failure to pay dividends for six
quarterly periods, the holders of preferred stock are entitled to elect two new
directors to the Board. Based on the Current Quarter financial results,
Chesapeake was able to pay a dividend on the preferred stock on August 1, 2000,
although the Board of Directors did not declare a dividend that would have been
payable on that date. On September 22, 2000, the Board of Directors declared a
regular quarterly dividend and a special dividend in the amount of all accrued
and unpaid dividends on the preferred stock, payable November 1, 2000.
Between April 1, 2000 and June 30, 2000, Chesapeake engaged in
unsolicited transactions in which a total of 24.7 million shares of common stock
(newly issued shares), plus a cash payment 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.
A total of 34.2 million shares of common stock, plus a cash payment of $8.3
million, have been exchanged for 3,039,363 shares of preferred stock between
January 1, 2000 and June 30, 2000. 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 by $16.8 million to $9.5 million. A gain on redemption of
all preferred shares exchanged through June 30, 2000 of $11.9 million ($1.5
million related to the quarter ended June 30, 2000) is reflected in net income
available to common shareholders in determining basic earnings per share.
Between July 1 and August 16, 2000, Chesapeake engaged in additional
transactions in which 9.2 million shares of common stock (newly issued shares)
were exchanged for 933,000 shares of its issued and outstanding preferred stock
with a liquidation value of $46.7 million plus dividends in arrears of $6.1
million. A $5.3 million loss on the redemption of these preferred shares will be
reflected in net income available to common shareholders in determining earnings
per share in the third quarter.
Chesapeake believes it has adequate resources, including cash on hand
and budgeted cash flow from operations, to fund its capital expenditure budget
for exploration and development activities during 2000, which are currently
estimated to be approximately $160 million. However, low oil and gas prices or
unfavorable drilling results could cause Chesapeake to reduce its drilling
program, which is largely discretionary. Based on current oil and gas prices,
Chesapeake expects to generate excess cash flow that will be available to fund
acquisitions, reduce debt, make preferred stock dividend payments, acquire
Gothic debt securities or a combination of the above.
If the Gothic merger is completed, holders of the 11.125% Senior
Secured Notes issued by Gothic's operating subsidiary will have the right, but
not the obligation, to require Chesapeake to repurchase their senior secured
notes at a purchase price equal to 101% of the principal amount of the senior
secured notes, plus accrued and unpaid interest to the date of repurchase.
Chesapeake presently holds $20 million of the $235 million principal amount of
senior secured notes outstanding.
Bear, Stearns & Co. Inc. has agreed to provide a $275 million standby
commitment, consisting of a $175 million term credit facility and $100 million
revolving credit facility. The term credit facility may be used to repurchase
any 11.125% Senior Secured Notes tendered to Chesapeake. If used, the revolving
credit facility will replace Chesapeake's existing revolving credit facility.
Chesapeake has incurred costs of approximately $3.2 million in obtaining the
commitment and will incur an additional $2.75 million of costs if the facility
is used.
19
<PAGE> 20
Six Months Ended June 30, 2000 and 1999
Cash Flows From Operating Activities. Chesapeake's cash provided by
operating activities increased 76% to $83.9 million during the Current Period
compared to $47.6 million during the Prior Period. The increase was due
primarily to higher oil and gas prices realized during the Current Period.
Cash Flows From Investing Activities. Cash used in investing activities
increased to $130.6 million during the Current Period from $67.3 million in the
Prior Period. During the Current Period Chesapeake expended approximately $68.3
million to initiate drilling on 66 gross (35.6 net) wells and invested
approximately $10.6 million in leasehold acquisitions. This compares to $68.3
million to initiate drilling on 80 gross (48.9 net) wells and $11.1 million to
purchase leasehold in the Prior Period. During the Current Period, Chesapeake
had acquisitions of oil and gas properties of $25.0 million, divestitures of oil
and gas properties of $1.4 million, and a cash payment of $22.4 million related
to the acquisition of the Gothic Discount Notes. This compares to acquisitions
of $6.5 million and divestitures of $17.4 million in the Prior Period.
Cash Flows From Financing Activities. There was $20.3 million of cash
provided by financing activities in the Current Period, compared to $14.2
million in the Prior Period. The activity in the Current Period and the Prior
Period reflects the net increase in borrowings under Chesapeake's commercial
bank credit facility of $19.5 million and $14.0 million in the Current and
Prior Periods, respectively, and 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, Chesapeake 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
20
<PAGE> 21
to acquire oil and gas properties was partially offset by reduced expenditures
during 1998 for exploratory and developmental drilling. During 1998 and 1997,
Chesapeake invested $259.7 million and $471.0 million, respectively, for
exploratory and developmental drilling. Also during 1998, Chesapeake sold its
19.9% stake in Pan East Petroleum Corp. to Poco Petroleums, Ltd. for
approximately $21.2 million. During 1997, Chesapeake 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, Chesapeake 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, Chesapeake 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,
Chesapeake issued $500 million in senior notes and $230 million in preferred
stock. During 1997, Chesapeake 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.
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.
Chesapeake has not yet determined the impact that adoption of FAS 133 will have
on the financial statements. However, Chesapeake believes that its commodity
derivatives will be designated as hedges in accordance with the relevant
accounting criteria.
21
<PAGE> 22
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
Chesapeake's results of operations are highly dependent upon the prices
received for oil and natural gas production.
COMMODITY HEDGING ACTIVITIES
Periodically Chesapeake 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 Chesapeake pays the counterparty and below which Chesapeake
is paid by the counterparty,
(ii) the purchase of index-related puts that provide for a "floor"
price below which the counterparty pays Chesapeake 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 Chesapeake 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 Chesapeake's oil and gas production.
Chesapeake only enters into commodity hedging transactions related to
Chesapeake'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 June 30, 2000, Chesapeake had the following open natural gas swap
arrangements designed to hedge a portion of Chesapeake's domestic gas production
for periods after June 2000:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBtu) (PER MMBtu)
------ ----------- ------------
<S> <C> <C>
July 2000...................................................... 2,790,000 3.03
August 2000.................................................... 2,790,000 3.03
September 2000................................................. 2,100,000 3.07
October 2000................................................... 1,240,000 2.55
</TABLE>
If the swap arrangements listed above had been settled on June 30,
2000, Chesapeake would have incurred a loss of $13.2 million. Subsequent to June
30, 2000, Chesapeake settled the July 2000 natural gas swaps for a loss of $4.5
million, which will be recognized as a price adjustment in July. Additionally,
Chesapeake has closed hedges on 920,000 MMBtu of the August through October
swaps which resulted in a loss of $0.6 million. This loss will be recognized as
price adjustments from August through October 2000.
On June 2, 2000, Chesapeake entered into a natural gas basis protection
swap transaction for 13,500,000 MMBtu for the period of January 2001 through
March 2001. This transaction requires that the counterparty pay Chesapeake if
the NYMEX price exceeds the Houston Ship Channel Beaumont/Texas Index by more
than $0.0675 for each of the related months of production. If the NYMEX price
less $0.0675 does not exceed the Houston Ship Channel Beaumont/Texas Index for
each month, Chesapeake will pay the counterparty. Gains or losses on basis swap
transactions are recognized as price adjustments in the month of related
production.
As of June 30, 2000, Chesapeake had the following open crude oil swap
arrangements designed to hedge a portion of Chesapeake's domestic crude oil
production for periods after June 2000:
<TABLE>
<CAPTION>
MONTHLY NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (Bbls) (per Bbl)
------ ----------- ------------
<S> <C> <C>
July 2000................................................ 125,000 $28.42
August 2000.............................................. 125,000 28.42
September 2000........................................... 125,000 28.42
October 2000............................................. 125,000 28.42
November 2000............................................ 125,000 28.42
December 2000............................................ 125,000 28.42
</TABLE>
22
<PAGE> 23
If the swap arrangements listed above had been settled on June 30,
2000, Chesapeake would have incurred a loss of $1.9 million.
Chesapeake has also closed transactions designed to hedge a portion of
Chesapeake's domestic oil and natural gas production as of June 30, 2000. The
net unrecognized losses resulting from these transactions, $1.4 million as of
June 30, 2000, will be recognized as price adjustments in the months of related
production. These hedging losses are set forth below ($ in thousands):
<TABLE>
<CAPTION>
HEDGING GAINS (LOSSES)
-----------------------------
MONTHS GAS OIL TOTAL
------ -------- ------- --------
<S> <C> <C> <C>
July 2000...................... $ (422) $ (231) $ (653)
August 2000.................... (432) -- (432)
September 2000................. (149) -- (149)
October 2000................... (196) -- (196)
-------- ------- --------
$ (1,199) $ (231) $ (1,430)
======== ======= ========
</TABLE>
In addition to commodity hedging transactions related to Chesapeake'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
Chesapeake also utilizes hedging strategies to manage fixed-interest
rate exposure. Through the use of a swap arrangement, Chesapeake has reduced its
interest expense by $2.7 million from May 1998 through June 2000. During the
Current Quarter, Chesapeake's interest rate swap resulted in a $36,000 increase
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 Chesapeake accordingly. If the floating rate exceeds the fixed rate,
Chesapeake 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 Chesapeake'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.
As of June 30, 2000, based upon prevailing interest rates, the present
value of Chesapeake's estimated future payments under the interest rate swap
agreement, without ascribing any value to the knock-out provision, was $17.7
million. However, because of the knock-out provision discussed above and the
volatility of interest rates, Chesapeake does not believe that this worst-case
scenario is a fair measure of the market value of the swap agreement and,
therefore, would not pay this amount to cancel the transaction. Results from
interest rate hedging transactions are reflected as adjustments to interest
expense in the corresponding months covered by the swap agreement.
The table below presents principal cash flows and related weighted
average interest rates by expected maturity dates. The fair value of the
long-term debt has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
JUNE 30, 2000
---------------------------------------------------------------------------------
YEARS OF MATURITY
---------------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
------ ------ ------ ------ ------- ---------- ------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES: ($ IN MILLIONS)
Long-term debt, including current
portion - fixed rate............. $ 0.4 $ 0.8 $ 0.6 $ -- $ 150.0 $ 770.0 $ 921.8 $ 867.7
Average interest rate............ 9.1% 9.1% 9.1% -- 7.9% 9.3% 9.1% --
Long-term debt - variable rate........ $ -- $ -- $ 63.0 $ -- $ -- $ -- $ 63.0 $ 63.0
Average interest rate............ -- -- 10.0% -- -- -- 10.0% --
</TABLE>
23
<PAGE> 24
BUSINESS
GENERAL
Chesapeake Energy Corporation is an independent energy company focused
on the exploration, development, acquisition and production of onshore natural
gas reserves, principally in the Mid-Continent region of the United States. 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.
Chesapeake's principal executive offices are located at 6100 North Western
Avenue, Oklahoma City, Oklahoma 73118. Our main telephone number is
(405)848-8000 and our website address is www.chkenergy.com.
At the end of 1999, Chesapeake owned interests in approximately 4,700
producing oil and gas wells. Chesapeake's primary operating area is the
Mid-Continent region, which includes Oklahoma, western Arkansas, southwestern
Kansas and the Texas Panhandle. Chesapeake's other operating areas are:
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; and
o the Permian Basin region of west Texas and southeastern New Mexico.
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 we operated. A summary of
our 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
Permian Basin ...... 9 5.5 3,232 727 3,959 -- -- 3,959
All other areas .... 11 7.7 20,874 588 21,462 -- (5,492) 15,970
--------- --------- ---------- --------- --------- ------------ ---------- ----------
Total .......... 211 119.7 $ 129,205 $ 24,063 $ 153,268 $ 52,093 $ (45,635) $ 159,726
========= ========= ========== ========= ========= ============ ========== ==========
</TABLE>
Our 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 the notes to our audited consolidated
financial statements included at the end of this prospectus.
For 2000, we have established a capital expenditure budget of $210
million, including approximately $160 million allocated to drilling, acreage
acquisition, seismic and related capitalized internal costs, and $50 million for
acquisitions, debt repayment and general corporate purposes, excluding the
pending acquisition of Gothic described below. This budget is subject to ongoing
adjustments based on drilling results, oil and gas prices, and other factors.
RECENT DEVELOPMENTS
On September 8, 2000, we entered into an Agreement and Plan of Merger
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 2.5% of Chesapeake's common stock. In addition, in a series of
private transactions from June 27, 2000 through September 21, 2000, we purchased
99.8% of Gothic's $104 million of 14.125% Series B Senior Secured Discount Notes
for total consideration of $80.8 million, comprised of $23.3 million in cash and
$57.5 million of Chesapeake common stock (9,858,363 shares valued at $5.825 per
share), subject to adjustment. We also purchased $20 million of the $235 million
of 11.125% Senior Secured Notes issued by Gothic's operating subsidiary for $22
million of Chesapeake common stock (3,694,939 shares valued at $6.04 per share,
subject to adjustment) in a private transaction that closed on September 1,
2000. The resulting total acquisition cost to Chesapeake will be approximately
$345 million, plus transaction expenses and adjusted for any working capital at
the time of the merger.
Gothic's proved reserves, estimated to be 322 Bcfe at June 30, 2000,
are 96% natural gas and 86% proved developed, have an average lifting cost of
less than $0.20 per Mcfe, are located primarily in Chesapeake's core
Mid-Continent operating area, and are unhedged after December 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. In addition, Chesapeake intends to
allocate approximately $20 million of the purchase price to Gothic's undeveloped
leasehold inventory, 3-D seismic inventory, lease operating telemetry system and
other assets.
24
<PAGE> 25
Gothic's previously announced plan of restructuring, which contemplated
the redemption of our 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 our acquisition
of Gothic.
Gothic presently has approximately 23.3 million common shares
outstanding. 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 approval by Gothic's shareholders
and other closing conditions. Completion of the transaction is expected in
January 2001. 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 AREA
Mid-Continent Region
Chesapeake's Mid-Continent proved reserves of 758 Bcfe represented 63%
of Chesapeake's total proved reserves as of December 31, 1999 and this area
produced 70 Bcfe, or 52% of Chesapeake's 1999 production. During 1999,
Chesapeake invested approximately $56 million to drill 169 gross (95.3 net)
wells in the Mid-Continent.
SECONDARY OPERATING AREAS
Gulf Coast
Chesapeake'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 Chesapeake's
total proved reserves as of December 31, 1999. During 1999, the Gulf Coast
assets produced 45 Bcfe, or 34% of Chesapeake's total production. During 1999,
Chesapeake invested approximately $22 million to drill 10 gross (3.7 net) wells
in the Gulf Coast.
Helmet Area
Chesapeake's Canadian proved reserves of 178 Bcfe represented 15% of
Chesapeake's total proved reserves at December 31, 1999. During 1999, production
from Canada was 12 Bcfe, or 9% of Chesapeake's total production. During 1999,
Chesapeake invested approximately $27 million to drill 12 gross (7.5 net) wells,
install various pipelines and compressors, and to perform capital workovers in
Canada.
Permian Basin
Chesapeake's Permian Basin proved reserves of 33 Bcfe represented 3% of
our total proved reserves as of December 31, 1999 and this area produced 5 Bcfe,
or 4% of our 1999 production. During 1999, Chesapeake invested approximately $3
million to drill 9 gross (5.5 net) wells in the Permian Basin.
OIL AND GAS RESERVES
The tables below set forth information as of December 31, 1999 with
respect to Chesapeake's estimated proved reserves, the estimated future net
revenue therefrom and the present value thereof at such date. Williamson
Petroleum Consultants, Inc. evaluated 50% and Ryder Scott Company L.P. evaluated
16% of Chesapeake's combined discounted future net revenues from Chesapeake's
estimated proved reserves at December 31, 1999. The
25
<PAGE> 26
remaining properties were evaluated internally by Chesapeake's engineers. All
estimates were prepared based upon a review of production histories and other
geologic, economic, ownership and engineering data developed by Chesapeake. The
present value of estimated future net revenue shown is not intended to represent
the current market value of the estimated oil and gas reserves owned by
Chesapeake.
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF DECEMBER 31, 1999 (MBbl) (MMcf) (MMcfe)
----------------------- --------- ---------- ----------
<S> <C> <C> <C>
Proved developed.......................................................... 17,750 763,323 869,823
Proved undeveloped........................................................ 7,045 293,503 335,772
------- ---------- ----------
Total proved.............................................................. 24,795 1,056,826 1,205,595
======= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF DECEMBER 31, 1999(a) DEVELOPED UNDEVELOPED PROVED
-------------------------- ----------- ------------- ----------
($ IN THOUSANDS)
<S> <C> <C> <C>
Estimated future net revenue......................................... $ 1,470,297 $ 420,878 $1,891,175
Present value of future net revenue.................................. $ 867,985 $ 221,511 $1,089,496
</TABLE>
----------
(a) Estimated future net revenue represents estimated future gross revenue to
be generated from the production of proved reserves, net of estimated
production and future development costs, using prices and costs in effect
at December 31, 1999. The amounts shown do not give effect to non-property
related expenses, such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization. The prices used in the external and internal reports yield
weighted average prices of $24.72 per barrel of oil and $2.25 per Mcf of
gas.
The future net revenue attributable to Chesapeake'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 Chesapeake
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.
Chesapeake's ownership interest used in calculating proved reserves and
the estimated future net revenue therefrom were determined after giving effect
to the assumed maximum participation by other parties to Chesapeake'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
Chesapeake. 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 Chesapeake's
proved reserves.
26
<PAGE> 27
The following table sets forth Chesapeake'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 $2.25 per Mcf of gas):
<TABLE>
<CAPTION>
PRESENT
PERCENT VALUE
GAS OF (DISC. @
OIL GAS EQUIVALENT PROVED 10%)
OPERATING AREAS (MBbl) (MMcf) (MMcfe) RESERVES ($ 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
Permian Basin............... 3,480 12,391 33,269 3 62,067
Other areas................. 4,916 17,322 46,817 4 54,339
------- ---------- ---------- ---- ------------
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 the notes to our audited
consolidated financial statements included at the end of this prospectus for
other disclosures about Chesapeake's oil and gas producing activities.
DRILLING ACTIVITY
The following table sets forth the wells drilled by Chesapeake during
the periods indicated. In the table, "gross" refers to the total wells in which
Chesapeake has a working interest and "net" refers to gross wells multiplied by
Chesapeake's working interest therein.
<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, JUNE 30,
-----------------------------------------
1999 1998 1997 1997
------------------- ------------------- ------------------- -------------------
GROSS NET GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
United States
Development:
Productive ............ 167 93.3 158 93.9 55 24.4 90 55.0
Non-productive ........ 17 10.6 9 4.7 1 0.3 2 0.2
-------- -------- -------- -------- -------- -------- -------- --------
Total ................. 184 103.9 167 98.6 56 24.7 92 55.2
======== ======== ======== ======== ======== ======== ======== ========
Exploratory:
Productive ............ 9 3.7 46 23.4 28 15.5 71 46.1
Non-productive ........ 6 4.6 9 6.8 2 0.9 8 5.7
-------- -------- -------- -------- -------- -------- -------- --------
Total ................. 15 8.3 55 30.2 30 16.4 79 51.8
======== ======== ======== ======== ======== ======== ======== ========
Canada
Development:
Productive ............ 11 7.3 11 3.6
Non-productive ........ 1 0.2 1 0.4
-------- -------- -------- --------
Total ................. 12 7.5 12 4.0
======== ======== ======== ========
Exploratory:
Productive ............ -- -- 1 0.3
Non-productive ........ -- -- 7 2.1
-------- -------- -------- --------
Total ................. -- -- 8 2.4
======== ======== ======== ========
</TABLE>
WELL DATA
At December 31, 1999, Chesapeake 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.
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<PAGE> 28
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 Chesapeake's sale of oil and gas for the periods
indicated:
<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 Chesapeake's Canadian gas
production was $1.19 and $1.03 during 1999 and 1998, respectively, and the
Canadian production expenses were $0.18 and $0.24 per Mcfe, respectively.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by Chesapeake in its development, exploration and acquisition
activities during the periods indicated:
<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS
DECEMBER 31, ENDED YEAR ENDED
------------------------------ DECEMBER 31, JUNE 30,
1999 1998 1997 1997
-------------- -------------- ------------ ----------
($ 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 Chesapeake
holds. "Gross" acres are the total number of acres in which Chesapeake owns a
working interest. "Net" acres refer to gross acres multiplied by Chesapeake's
fractional working interest. Acreage numbers are stated in thousands and do not
include options for additional leasehold held by Chesapeake, 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
Permian Basin ...... 5 3 42 23 47 26
Other areas ........ 35 18 597 398 632 416
------- ------- ------- ------- ------- -------
Total .... 1,809 790 2,894 1,698 4,703 2,488
======= ======= ======= ======= ======= =======
</TABLE>
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<PAGE> 29
MARKETING
Chesapeake's oil production is sold under market sensitive or spot
price contracts. Chesapeake'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, Chesapeake 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 Chesapeake'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 Chesapeake from the sale of natural gas
liquids is included in natural gas sales. During 1999, only sales to Aquila
Southwest Pipeline Corporation accounted for more than 10% of Chesapeake's total
oil and gas sales. Management believes that the loss of this customer would not
have a material adverse effect on Chesapeake'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> <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>
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 Chesapeake, its
partners and other oil and natural gas producers in certain geographical areas
in which Chesapeake is active.
HEDGING ACTIVITIES
Periodically Chesapeake 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."
COMPETITION
The oil and gas industry is highly competitive. Chesapeake competes
with major and independent oil and gas companies for the acquisition of
leasehold, proved oil and gas properties, as well as for the services and labor
required to explore, develop and produce such properties. Many of these
competitors have financial, technical and other resources substantially greater
than those of Chesapeake.
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 Chesapeake's cost of doing business and,
consequently, affects its profitability.
Exploration and Production
Chesapeake'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
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<PAGE> 30
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. Chesapeake'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 Chesapeake can produce from its wells and to
limit the number of wells or the locations at which Chesapeake can drill. The
full extent of any impact on Chesapeake of such restrictions cannot be
predicted.
Environmental and Occupational Regulation
General. Chesapeake'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 Chesapeake. Chesapeake 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 Chesapeake's operations could have on its activities.
Activities of Chesapeake 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 Chesapeake 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 Chesapeake's operations could result in
substantial costs and liabilities.
Waste Disposal. Chesapeake 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 Chesapeake 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 Chesapeake 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 Chesapeake's control.
State and federal laws applicable to oil and natural gas wastes and properties
have gradually become more strict. Under such laws, Chesapeake 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.
Chesapeake 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 Chesapeake'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.
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<PAGE> 31
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, Chesapeake may have generated
and may generate wastes that fall within CERCLA's definition of "hazardous
substances". Chesapeake may also be or have been an owner of sites on which
"hazardous substances" have been released. Chesapeake 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 Chesapeake 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
Chesapeake.
Air Emissions. The operations of Chesapeake 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 Chesapeake's operations. However, it
is impossible to predict accurately the effect, if any, of the Clean Air Act
Amendments on Chesapeake at this time. Chesapeake 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 Chesapeake to
forgo construction or operation of certain air emission sources.
OSHA. Chesapeake 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 Chesapeake 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. Chesapeake is also subject to the requirements
and reporting set forth in OSHA workplace standards. Chesapeake 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 Chesapeake,
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 Chesapeake. 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, Chesapeake 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. Chesapeake 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 Chesapeake.
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
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<PAGE> 32
been adopted in several states. Chesapeake is unable to estimate the effect of
these regulations, although based upon Chesapeake's preliminary analysis to
date, Chesapeake 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. Chesapeake'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 Chesapeake, 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. Chesapeake has obtained such
permits for the Class II wells it operates. Chesapeake also has disposed of
wastes in facilities other than those owned by Chesapeake 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. Chesapeake may own such PCB items but does not believe compliance
with TSCA has had or will have a material adverse effect on Chesapeake'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, Chesapeake's title to
oil and gas properties is challenged through legal proceedings. Chesapeake is
routinely involved in litigation involving title to certain of its oil and gas
properties, some of which management believes could be adverse to Chesapeake,
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 Chesapeake 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. Chesapeake's
horizontal and deep drilling activities involve greater risk of mechanical
problems than vertical and shallow drilling operations.
Chesapeake maintains a $50 million oil and gas lease operator policy
that insures Chesapeake 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. Chesapeake also carries comprehensive general liability policies and
a $75 million umbrella policy. Chesapeake and its subsidiaries carry workers'
compensation insurance in all states in which they operate and a $75 million
employment practice liability policy. While Chesapeake believes these policies
are customary in the industry, they do not provide complete coverage against all
operating risks.
EMPLOYEES
Chesapeake had 427 full-time employees as of June 30, 2000. No
employees are represented by organized labor unions. Chesapeake considers its
employee relations to be good.
FACILITIES
Chesapeake owns an office building complex in Oklahoma City totaling
approximately 86,500 square feet and nine acres of land that comprise its
headquarters' offices. Chesapeake also owns field offices in Lindsay and
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<PAGE> 33
Waynoka, Oklahoma and Garden City, Kansas. Chesapeake leases office space in
Oklahoma City and Weatherford, Oklahoma; Fritch and Navasota, Texas; and
Dickinson, North Dakota. Chesapeake also has leased office space in College
Station, Texas; Wichita, Kansas; and Calgary, Alberta, Canada, which has been
sub-leased.
LEGAL PROCEEDINGS
Chesapeake 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
Chesapeake and certain of its officers and directors. The action was brought on
behalf of purchasers of Chesapeake'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 Chesapeake'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
Chesapeake 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 Chesapeake, and underwriters of the
offering. Total proceeds of the offering were $254 million, of which Chesapeake
received net proceeds of $90 million.
Plaintiffs allege that Chesapeake, which owned 30.1% of Bayard's
outstanding common stock prior to the offering, was a controlling person of
Bayard. Plaintiffs also allege that Chesapeake 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)
Chesapeake'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 Chesapeake, (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 Chesapeake 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 Chesapeake. Discovery is
proceeding in the case and trial is presently scheduled to be held in May 2001.
Chesapeake 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 Chesapeake for
its costs of defense as incurred.
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<PAGE> 34
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 Chesapeake had infringed UPRC's patent
covering a "geosteering" method utilized in drilling horizontal wells. Following
a trial to the court in June 1999, the court ruled on September 21, 1999 that
the patent was invalid. Because the patent was declared invalid, the court held
that Chesapeake 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 Chesapeake 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. Chesapeake has appealed the trial court's ruling denying
Chesapeake's request for attorneys' fees.
West Panhandle Field Cessation Cases
A subsidiary of Chesapeake, 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 Chesapeake acquired in April
1998, has owned the leases since January 1, 1997. The co-defendants are prior
lessees.
The plaintiffs in these cases 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 CP 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 CP 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)
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<PAGE> 35
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.
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 CP 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.
Chesapeake 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.
INCORPORATION
Chesapeake was organized as a Delaware corporation on December 26,
1991 and was reincorporated as an Oklahoma corporation on December 31, 1996.
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<PAGE> 36
MANAGEMENT
INFORMATION REGARDING DIRECTORS
Aubrey K. McClendon, age 41, has served as Chairman of the Board, Chief
Executive Officer and a director since co-founding Chesapeake in 1989. From 1982
to 1989, Mr. McClendon was an independent producer of oil and gas in affiliation
with Tom L. Ward, Chesapeake'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 41, has served as President, Chief Operating Officer
and a director of Chesapeake since co-founding Chesapeake in 1989. From 1982 to
1989, Mr. Ward was an independent producer of oil and gas in affiliation with
Aubrey K. McClendon, Chesapeake'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 Chesapeake 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 71, has been a director of Chesapeake 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 Chesapeake
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 Chesapeake 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.
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<PAGE> 37
INFORMATION REGARDING OFFICERS
Executive Officers
In addition to Messrs. McClendon and Ward, the following are also
executive officers of Chesapeake.
Marcus C. Rowland, age 48, was appointed Executive Vice President in
March 1998 and has been Chesapeake'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
Chesapeake, 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.
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 Chesapeake'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 Chesapeake 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
Chesapeake 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
Steven C. Dixon, age 42, 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 Chesapeake during the two years prior
to his joining Chesapeake, 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.
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 Chesapeake, Mr. Winton served as the Director,
Information Services Department, at Union Pacific Resources Company. Prior to
that period Mr. Winton
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<PAGE> 38
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.
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 Chesapeake 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, in January 2000. He
served as Vice President - Contract Administration for Chesapeake 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.
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<PAGE> 39
EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
In 1997 Chesapeake 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) Chesapeake'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 Chesapeake, 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 Chesapeake to any of the named executives in any period
covered by the table.
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<PAGE> 40
(c) Represents Chesapeake's matching contributions to the Chesapeake Energy
Corporation Savings and Incentive Stock Bonus Plan.
(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
Chesapeake'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.
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<PAGE> 41
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
Chesapeake 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 Chesapeake'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 Chesapeake 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 Chesapeake 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 Chesapeake'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,
Chesapeake 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 Chesapeake to approximate what third parties pay for similar
leasehold in the area of the well. Payment is due within 150 days for invoices
received
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<PAGE> 42
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 Chesapeake for marketing the production. As a
result of marketing arrangements with other participants in Chesapeake's wells
to correct the timing of the receipt of revenues, Chesapeake 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. Chesapeake 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 Chesapeake'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
Chesapeake 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 Chesapeake 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 Chesapeake's wells
during 1999 or the first quarter of 2000. However, both resumed participation in
Chesapeake's wells on April 1, 2000.
Chesapeake and Mr. Rowland have agreed to the following terms of his employment
effective August 1, 2000: a 35-month contract term which can be terminated by
either party and an initial minimum annual base salary of $250,000 increasing to
$275,000 on January 1, 2001. Mr. Rowland's employment agreement requires him to
hold 5,000 shares of Chesapeake's common stock throughout the term of the
agreement. Under his employment agreement, Mr. Rowland is permitted to continue
to conduct oil and gas activities individually and through various related or
family-owned entities, but he may not, after August 1, 2000, acquire, attempt to
acquire or aid another person in acquiring an interest in any oil and gas
exploration, development or production activities within five miles of any
operations or ownership interests of Chesapeake or its affiliates.
Chesapeake 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 Chesapeake's common stock throughout
the term of their contract.
Chesapeake 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. Mr. Rowland would be entitled to receive six
months compensation and benefits if terminated without cause by Chesapeake.
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. Rowland,
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. Rowland, Dixon and Lester. Change of control is defined in Messrs.
McClendon and Ward's agreements to include (x) an event which results in a
person acquiring beneficial ownership of securities having 35% or more of the
voting power of Chesapeake's outstanding voting securities, or (y) within two
years of a tender offer or exchange offer for the voting stock of Chesapeake or
as a result of a merger, consolidation, sale of assets or contested election, a
majority of the members of Chesapeake's Board of Directors is replaced by
directors who were not nominated and approved
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<PAGE> 43
by the Board of Directors. In Messrs. Dixon, Lester and Rowland's agreements,
change of control is defined to include (i) the direct or indirect acquisition
by any person of beneficial ownership of the right to vote, or securities of
Chesapeake representing the right to vote, 51% or more of the combined voting
power of Chesapeake's then outstanding securities having the right to vote for
the election of directors, or (2) a merger, consolidation, sale of assets or
contested election or (3) any combination of (1) and (2) which results in a
majority of the members of Chesapeake's board of directors being replaced by
directors who were not nominated and approved by the existing board of
directors.
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 and Chief Executive
Officer of Chesapeake and Mr. Ward is Chesapeake's President and Chief Operating
Officer. Messrs. McClendon and Ward administer Chesapeake'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 Chesapeake's non-employee directors pursuant to a formula award
provision. See "-Directors' Compensation." Messrs. McClendon and Ward also serve
on committees which administer Chesapeake'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 Chesapeake's oil and gas wells
pursuant to the terms of their employment agreements with Chesapeake. 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 Chesapeake. A
subsidiary of Chesapeake 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 Chesapeake
("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.
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<PAGE> 44
CERTAIN TRANSACTIONS
Legal Counsel. Shannon T. Self, a director of Chesapeake, is a
shareholder in the law firm of Self, Giddens & Lees, Inc., which provides legal
services to Chesapeake. During 1997, 1998 and 1999, the firm billed Chesapeake
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., a wholly-owned
subsidiary of Chesapeake, was formed to drill and operate wells in which Messrs.
McClendon and Ward or their affiliates owned working interests. Chesapeake
Operating 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. Chesapeake Operating 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 Chesapeake and
participated in wells drilled by Chesapeake Operating. Chesapeake's non-employee
directors have not acquired from Chesapeake interests in any new wells drilled
by Chesapeake since their election as directors in 1993 and have no present
intention to acquire from Chesapeake interests in any new wells of Chesapeake.
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 Chesapeake 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 Chesapeake and not
disbursed bears interest at 9.125%.
Loans to Executives. In June 1998, Chesapeake 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
Chesapeake 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 Chesapeake'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,
Chesapeake 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
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<PAGE> 45
similar acquisitions of assets from disinterested third parties. See "Executive
Compensation - Employment Agreements."
Miscellaneous. From time to time, Chesapeake has paid various expenses
incurred on behalf of Messrs. McClendon and Ward and their affiliates, creating
accounts receivable of Chesapeake. 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.
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<PAGE> 46
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 Chesapeake'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
Chesapeake's directors and executive officers listed in the Summary Compensation
Table in "Executive Compensation" and by all directors and executive officers of
Chesapeake as a group. Unless otherwise noted, information is given as of
September 22, 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)...................... 10,084,552(b)(c) 1,224,406 11,308,958 7.3%
6100 North Western Avenue
Oklahoma City, OK 73118
Aubrey K. McClendon(1)(2).............. 8,776,847(c)(d) 1,224,406 10,001,253 6.5%
6100 North Western Avenue
Oklahoma City, OK 73118
Franklin Advisers, Inc................. 10,760,100 -- 10,760,100 7.0%
777 Mariners Island Boulevard
San Mateo, CA 94404
Loomis, Sayles & Company, L.P.......... 8,157,070 386,318(e) 8,543,388(e) 5.6%
One Financial Center
Boston, MA 02111
Edgar F. Heizer, Jr.(1)................ 709,650 413,500 1,123,150 (3)
Breene M. Kerr(1)...................... 376,000(f) 190,000(g) 566,000 (3)
Shannon T. Self(1)..................... 31,458(h) 428,166 459,624 (3)
Frederick B. Whittemore(1)............. 481,800(i) 1,192,750(g) 1,674,550 1.1%
Steven C. Dixon(2)..................... 13,716(c) 462,964 476,680 (3)
J. Mark Lester(2)...................... 43,845(c) 109,352 153,197 (3)
Marcus C. Rowland(2)................... 32,548(c) 99,369 131,917 (3)
All directors and executive officers
as a group........................... 20,598,621 4,599,813 25,198,434 16.0%
</TABLE>
----------
(1) Director
(2) Executive officer
(3) Less than 1%
(a) Represents shares of common stock which can be acquired on September 22,
2000 or 60 days thereafter through the exercise of options or conversion of
Chesapeake's convertible preferred stock.
(b) Includes 1,444,860 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.
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<PAGE> 47
(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).
(d) Includes 13,560 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 Chesapeake's preferred stock which is convertible into
386,318 shares of Chesapeake's common stock. 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 Chesapeake'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) Includes 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> 48
SELLING SHAREHOLDER
The selling shareholder, Paribas North America, Inc., beneficially
owned as of the date of this prospectus, and is offering pursuant to this
prospectus, 389,378 shares of Chesapeake common stock. The selling shareholder
does not have, nor within the past three years has it had, any position, office
or other material relationship with Chesapeake or any of its predecessors or
affiliates.
Because the selling shareholder, which term includes any donee,
pledgee, transferee or other successor in interest of the selling shareholder,
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 shareholder upon termination of any
such sale. In addition, the selling shareholder 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 shareholder may sell all, part or none of the shares
listed above.
We agreed with the selling shareholder to file a registration statement
under the Securities Act to register the resale of the shares it received in an
exchange transaction on August 31, 2000. The purchase agreement for this
transaction has an adjustment provision which requires the selling shareholder
to pay us, in cash or shares of our common stock, the difference between the
average of the closing prices for the shares during the 30-day period following
the date of this prospectus and $5.825 per share. The shares covered by this
prospectus will be reduced by any shares used to make this adjustment. We are
obligated to make a corresponding adjustment in cash only if the 30-day average
price is less than $5.825.
We agreed to prepare and file all necessary amendments and supplements
to the registration statement to keep it effective until August 31, 2002 or such
time as all of the shares covered by this prospectus have been sold by the
selling shareholder.
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<PAGE> 49
DESCRIPTION OF THE CAPITAL STOCK
The description of our capital stock set forth below is not complete
and is qualified by reference to our Certificate of Incorporation and Bylaws.
Copies of the Certificate of Incorporation and Bylaws are available from
Chesapeake upon request and both documents have been filed with the Securities
and Exchange Commission.
AUTHORIZED CAPITAL STOCK
Our authorized capital stock 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 624,037 shares are designated the 7% Cumulative
Convertible Preferred Stock and 250,000 shares are designated the Series A
Junior Participating Preferred Stock. As of September 22, 2000, our issued and
outstanding capital stock consisted of 152,896,625 shares of common stock and
624,037 shares of convertible preferred stock. No shares of Series A preferred
stock are currently outstanding. Also, an additional 16,717,235 shares of common
stock were reserved for issuance upon the exercise of outstanding options
granted under our 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 Chesapeake, 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
Our 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."
We have 9,375,963 shares of authorized preferred stock which are
undesignated. The Board of Directors has the authority, without further
shareholder approval, to issue shares of preferred stock from time to time in
one or more new series and to fix the number of shares, designations,
preferences, voting powers, qualifications and special or relative rights or
privileges of each series, including dividend rights, voting rights, redemption
and sinking fund provisions, liquidation preferences and conversion rights.
While providing desirable flexibility for 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, as well as dividend and
liquidation payments on common stock. It also could have the effect of delaying,
deferring or preventing a change in control.
7% Cumulative Convertible Preferred Stock
The Certificate of Designation for the 7% Cumulative Convertible
Preferred Stock authorizes the issuance of 624,037 shares, all of which are
issued and outstanding. The convertible preferred stock is, and any common stock
issued upon the conversion or exchange of convertible preferred stock will be,
fully paid and nonassessable. The convertible preferred stock was issued on
April 22, 1998.
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<PAGE> 50
Ranking. The convertible preferred stock ranks:
o senior to all classes of our common stock and to each other class of
capital stock or series of preferred stock that does not expressly
provide that it ranks senior to or on a parity with the convertible
preferred stock as to dividend distributions and distributions upon
liquidation, winding-up and dissolution;
o on a parity with any class of capital stock or series of preferred
stock issued by Chesapeake that expressly provides that it ranks on a
parity with the convertible preferred stock as to dividend
distributions and distributions upon liquidation, winding-up and
dissolution; and
o junior to each class of capital stock or series of preferred stock
issued by Chesapeake that expressly provides that it ranks senior to
the convertible preferred stock as to dividend distributions and
distributions upon liquidation, winding-up and dissolution.
Dividends. Holders of convertible 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 our stock register on the record date fixed
by the Board for a payment. The record date may not be more than 60 days nor
less than 10 days preceding the payment date.
Dividends payable on the convertible preferred stock for each full
dividend period will be computed by dividing the annual dividend rate by four.
Dividends payable on the convertible 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.
We will not declare and pay any dividends on or redeem or purchase any
of our stock ranking junior to or ratably with the convertible preferred stock,
unless full cumulative dividends on the convertible preferred stock have been
paid or declared and a sum sufficient for the payment of dividends is set apart.
However, regardless of whether we have paid full cumulative dividends on the
convertible preferred stock, we may do the following:
(1) declare and pay a dividend on junior stock payable solely in
shares of junior stock;
(2) redeem or purchase stock ranking junior or ratably with the
convertible preferred stock by conversion into or exchange for
shares of our stock ranking junior to the convertible preferred
stock; and
(3) make cash payments in lieu of fractional shares.
If full dividends have not been declared and paid or set apart on the
convertible preferred stock and any other preferred stock ranking ratably with
the convertible preferred stock as to dividends, dividends may be declared and
paid on the convertible preferred stock and the other ratable preferred stock.
In this case, the dividends shall be declared and paid pro rata so that the
amounts of dividends declared per share on the convertible preferred stock and
the other ratable preferred stock will in all cases bear the same ratio to each
other that accrued and unpaid dividends per share on the shares of the
convertible preferred stock and the other preferred stock bear to each other.
Moreover, if the dividends are paid in cash on the other ratable preferred
stock, dividends will also be paid in cash on the convertible preferred stock.
Holders of shares of convertible 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.
Our ability to declare and pay cash dividends and make other
distributions on our capital stock, including the convertible preferred stock,
may be limited by the terms of our indentures and other financing agreements and
by Oklahoma law. See "Risk Factors - Existing debt covenants restrict our
operations."
Liquidation Preference. Upon any dissolution, liquidation or winding up
of Chesapeake, the holders of convertible preferred stock will be entitled to
receive a liquidation preference of $50 per share, plus accrued and
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<PAGE> 51
unpaid dividends to the date of payment. These amounts will be paid before any
payment or distribution is made to holders of common stock or any other stock
ranking junior to the convertible preferred stock upon liquidation. The holders
of convertible preferred stock and any other shares of stock of Chesapeake that
rank on a parity as to liquidation rights with the convertible preferred stock
are entitled to share ratably, in accordance with the respective preferential
amounts payable on the stock, in any distribution which is not sufficient to pay
in full the amounts to which the holders are entitled. After payment in full of
the liquidation preference on the convertible preferred stock, the holders of
the convertible preferred stock will have no right or claim to any of our
remaining assets. The sale of all or part of our assets and the merger or
consolidation of our company into or with another company will not be considered
a dissolution, liquidation or winding up of Chesapeake unless the sale, merger
or consolidation is in connection with the dissolution, liquidation or winding
up of Chesapeake.
Optional Redemption. The convertible preferred stock may not be
redeemed prior to May 1, 2001. Beginning May 1, 2001, we may redeem the
convertible preferred stock for the prices set forth in the Certificate of
Designation, plus accumulated and accrued dividends. The redemption price is
$52.45 per share during the first year and then declines by $.35 per year until
May 1, 2008 when the price is $50.00. We may use cash, our common stock or a
combination of cash and common stock to redeem the convertible preferred stock.
The number of common shares to be delivered as payment will be determined by the
market value of the shares at the time of redemption.
From and after the applicable redemption date, unless we default in the
payment of the redemption price, dividends on the shares of convertible
preferred stock to be redeemed on the 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 will cease, except the right to receive the
redemption price.
If any dividends on convertible preferred stock are in arrears, no
shares of convertible preferred stock will be redeemed unless all outstanding
shares of the convertible preferred stock are simultaneously redeemed.
Voting Rights. The holders of the convertible preferred stock have no
voting rights except as set forth below or as required by law. In exercising
their voting rights, the holders of convertible preferred stock are entitled to
one vote per share.
If the dividends payable on the convertible preferred stock are in
arrears for six quarterly periods, the holders of the convertible preferred
stock, voting separately as a class with the holders 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 Chesapeake to elect two
additional directors. These voting rights and the terms of the directors so
elected will continue until the dividend arrearage on the convertible preferred
stock has been paid in full.
The affirmative vote or consent of the holders of at least 66 2/3% of
the outstanding convertible preferred stock will be required for us to issue any
class or series of stock (or security convertible into stock) ranking on a
parity or senior to the convertible preferred stock as to dividends, liquidation
rights or voting rights and to amend our Certificate of Incorporation so as to
affect adversely the rights of holders of the convertible preferred stock,
including any increase in the authorized number of shares of preferred stock.
Conversion Rights. The convertible preferred stock is convertible at
any time at the option of the holder into that number of whole shares of our
common stock as is equal to the liquidation preference, plus accrued and unpaid
dividends to the date the shares of convertible preferred stock are surrendered
for conversion, divided by an initial conversion price of $6.95, subject to
adjustment upon the occurrence of dilutive events described in the Certificate
of Designation. A share of convertible preferred stock called for redemption
will be convertible into shares of common stock up to and including the close of
business on the date fixed for redemption, unless we default in payment of our
redemption obligation.
Change of Control. Upon a change of control of Chesapeake, holders of
convertible preferred stock will, if the market value of our common stock is
less than the conversion price, have a one-time option to convert all of their
outstanding shares of convertible preferred stock into shares of common stock at
an adjusted conversion price equal to the greater of (1) the market value of our
common stock as of the date of the change of control and (2)
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<PAGE> 52
$3.66. In lieu of issuing the shares of common stock issuable upon conversion in
the event of a change of control, we may, at our option, make a cash payment
equal to the market value of the common stock otherwise issuable.
The Certificate of Designation for the convertible preferred stock
defines a change of control as any of the following events:
1. the sale, lease or transfer, in one or a series of related
transactions, of all or substantially all of our assets to any
person or group, other than to permitted holders;
2. the adoption of a plan relating to our liquidation or
dissolution;
3. the acquisition, directly or indirectly, by any person or
group, other than permitted holders, of beneficial ownership
of more than 50% of the aggregate voting power of our voting
stock; provided, however, that the permitted holders
beneficially own, directly or indirectly, in the aggregate a
lesser percentage of the total voting power of the voting
stock than such other person and do not have the right or
ability by voting power, contract or otherwise to elect or
designate for election a majority of our Board of Directors;
or
4. during any period of two consecutive years, individuals who at
the beginning of the period constituted our Board of Directors
(together with any new directors whose election by such Board
of Directors or whose nomination for election by our
shareholders was approved by two-thirds of the directors then
still in office who were either directors at the beginning of
the period or whose election or nomination for election was
previously so approved) cease for any reason to constitute a
majority of the Board of Directors then in office. The term
"permitted holders" means Aubrey K. McClendon and Tom L. Ward
and their respective affiliates.
ANTI-TAKEOVER PROVISIONS
Our Certificate of Incorporation and Bylaws 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
Our 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 the person became an interested shareholder, unless
o prior to the date the 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 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 the person
became an interested shareholder, the business combination is approved
by the board of directors of the corporation and authorized at a
meeting
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<PAGE> 53
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.
Stock Purchase Provisions
The Certificate of Incorporation 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
Chesapeake from the interested shareholder at a price in excess of fair market
value, unless the purchase is either (1) made on the same terms offered to all
holders of the same securities or (2) made on the open market and not the result
of a privately negotiated transaction.
Share Rights Plan
The Rights. On July 7, 1998, our Board of Directors declared a dividend
distribution of one preferred stock purchase right for each outstanding share of
common stock. The distribution was paid on July 27, 1998 to the shareholders of
record on that date. Each right entitles the registered holder to purchase from
us 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 these rights. The full description and
terms of the rights are set forth in a Rights Agreement between Chesapeake and
UMB Bank, N.A., as rights agent. Copies of the Rights Agreement and the
Certificate of Designation for the Series A preferred stock are available free
of charge from Chesapeake, and they are filed with the Securities and Exchange
Commission. This summary description of the rights and the Series A preferred
stock is not 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.
Initially, the rights attached to all certificates representing shares
of our outstanding 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 a later date set by 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
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<PAGE> 54
offer or exchange offer upon consummation of which the offeror would,
if successful, become an acquiring person. The earlier of these dates
is 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 our outstanding common stock, but does not include:
o Chesapeake or any subsidiary of Chesapeake or any employee benefit plan
of Chesapeake,
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
of 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 pledgee of any of its rights or
duties as pledgee, other than the exercise of any voting power by the
pledgee or the acquisition of ownership by the pledgee, it becomes a
beneficial owner of the pledged shares, or
o any person (other than the pledgee just described) 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 a second tier shareholder
("second tier holder shares") do not exceed the sum of (A) the holder's
second tier holder shares held on September 11, 1998 and (B) 1% of the
shares of our common stock 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 July 27, 1998, 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 certificate for common stock
outstanding as of July 27, 1998, even without a notation or a copy of a summary
of the rights being attached, will also constitute the transfer of the rights
associated with the common stock represented by the certificate. As soon as
practicable following the distribution date, separate certificates evidencing
the rights will be mailed to holders of record of the common stock as of the
close of business on the distribution date and these 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 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
54
<PAGE> 55
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) Chesapeake is
acquired in a merger or other business combination transaction or more than 50%
of its consolidated assets or earning power is sold, proper provision will be
made so that each holder of a right will thereafter have the right to receive,
upon the exercise of the right at the then current exercise price, 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, if applicable, cash, other equity securities or property of
Chesapeake) having a market value equal to two times the purchase price of the
rights (the "flip-in right"). Any rights that are or were at any time owned by
an acquiring person will then become void.
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 (1) 5:00 p.m., Oklahoma
City, Oklahoma time on the 10th day after the stock acquisition date or (2) the
expiration of the rights, we may redeem the rights in whole, but not in part, at
a price of $0.01 per right; provided, that (a) if the Board of Directors
authorizes redemption on or after the time a person becomes an acquiring person,
then the authorization must be by board approval and (b) 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
Chesapeake. 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 any 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 Chesapeake, including the right to vote or to receive dividends.
While the distribution of the rights will not be taxable to shareholders or
Chesapeake, 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 (a "preferred share fraction") that may be acquired
upon exercise of the rights will be nonredeemable and junior to any other shares
of preferred stock that may be issued by Chesapeake.
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.
55
<PAGE> 56
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 our common stock.
SHAREHOLDER ACTION
Except as otherwise provided by law or in our Certificate of
Incorporation or Bylaws. The approval of a majority of the shares of common
stock present in person or represented by proxy at a meeting and entitled to
vote is sufficient to authorize, affirm, ratify or consent to a matter voted on
by shareholders. Our Bylaws provide that all questions submitted to shareholders
will be decided by a plurality of the votes cast, unless otherwise required by
law, the Certificate of Incorporation, stock exchange requirements or any
certificate of designation. 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
us, and providing for staggered terms of directors and indemnity for directors.
The same vote is required for shareholders to amend, repeal or adopt any
provision of the Bylaws.
Under 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 capital stock entitled to vote been present at a meeting.
If shareholder action is taken by written consent, the rules and regulations of
the Securities and Exchange Commission require us to send each shareholder
entitled to vote on the matter, but whose consent is not solicited, an
information statement containing information substantially similar to that which
would have been contained in a proxy statement.
REGISTRATION RIGHTS
In connection with our purchase of Gothic's 14.125% Series B Senior
Secured Discount Notes and the 11.125% Senior Secured Notes issued by Gothic's
operating subsidiary, we entered into registration rights agreements with the
noteholders. Including the shares offered by this prospectus, we have registered
for resale 9,858,363 shares of our common stock, and we have agreed to register
an additional 3,694,939 shares, pursuant to these registration rights
agreements. Registration of shares on behalf of selling shareholders results in
those shares becoming freely tradeable without restriction. These sales could
cause the market price of our stock to decline.
We are required to bear all of the expenses of registration under these
agreements except underwriting discounts and commissions. We may not publicly
sell or distribute our common stock or any securities convertible into our
common stock during any underwritten offering by the former noteholders of the
shares covered by the registration rights agreements for a maximum period of
ninety days. If we propose to register shares of common stock under the
Securities Act, other than by a registration statement on Form S-8 or Form S-4,
the former noteholders have the right to receive notice of and to include the
shares covered by the registration rights agreements in such registration,
subject to restrictions imposed by the managing underwriter in an underwritten
offering.
TRANSFER AGENT AND REGISTRAR
UMB Bank, N.A. is the transfer agent and registrar for the common stock
and the preferred stock.
56
<PAGE> 57
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 shareholder
(including its respective donees, pledgees, transferees or other successors in
interest) as principal 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 sales 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 the selling
shareholder and underwriters, brokers, dealers or agents, or purchasers. In
connection with sales of the shares or otherwise, the selling shareholder 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 shareholder 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 shareholder has advised us that it has
not entered into any agreements, understandings or arrangements with any
underwriters or broker-dealers regarding the sale of its securities, nor is
there any underwriter or coordinating broker acting in connection with the
proposed sale of shares by the selling shareholder.
If the selling shareholder effects 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 shareholder 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 shareholder 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 shareholder.
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.
Chesapeake 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. Chesapeake has
agreed to indemnify the selling shareholder and any underwriters against certain
liabilities, including liabilities under the Securities Act. Chesapeake will not
receive any of the proceeds from the sale of any of the shares by the selling
shareholder.
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
shareholder and have informed the selling shareholder of the need for delivery
of the prospectus to purchasers at or prior to the time of any sale of its
shares.
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<PAGE> 58
LEGAL MATTERS
The legality of the common stock offered hereby has been passed upon
for Chesapeake by Winstead Sechrest & Minick P.C., Dallas, Texas.
EXPERTS
The consolidated financial statements of Chesapeake 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. These estimates are included in reliance on the authority of each
such firm as experts in such matters.
WHERE YOU CAN FIND MORE INFORMATION
We have filed a registration statement with the Securities and Exchange
Commission relating to the shares of common stock offered by 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 Chesapeake 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 Chesapeake may also be inspected at the offices of the
New York Stock Exchange, 20 Broad Street, New York, New York 10005.
You should rely only on the information included in this prospectus or
any prospectus supplement. We have not authorized anyone to provide you with any
other information. The shares of common stock offered in this prospectus may
only be offered in states where the offer is permitted, and the selling
shareholder is not making an offer of the shares in any state where the offer is
not permitted. You should not assume the information in this prospectus or any
prospectus supplement is accurate as of any date other than the dates on the
front of those documents unless the information specifically indicates that
another date applies.
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<PAGE> 59
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.
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<PAGE> 60
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interest
owned in gross acres or gross wells.
Present Value. When used with respect to oil and gas reserves, present
value means the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect at the determination date,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expense or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
Productive Well. A well that is producing oil or gas or that is
capable of production.
Proved Developed Reserves. Reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved Undeveloped Reserves. Reserves that are expected to be
recovered from new wells drilled to known reservoir on undrilled acreage or
from existing wells where a relatively major expenditure is required for
recompletion.
Royalty Interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.
Tcf. One trillion cubic feet.
Tcfe. One trillion cubic feet of gas equivalent.
Undeveloped Acreage. Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains proved
reserves.
Working Interest. The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Balance Sheets at June 30, 2000 and December 31, 1999 (Unaudited).................... F-2
Consolidated Statements of Operations for the Three Months and Six Months Ended
June 30, 2000 and 1999 (Unaudited)................................................................ F-3
Consolidated Statements of Cash Flows for the Six Months Ended
June 30, 2000 and 1999 (Unaudited)................................................................ F-4
Consolidated Statements of Comprehensive Income (Loss) for the Three Months and
Six Months Ended June 30, 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-18
Consolidated Balance Sheets at December 31, 1999 and 1998......................................... F-19
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-20
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-21
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-23
Notes to Consolidated Financial Statements........................................................ F-24
Schedule II - Valuation and Qualifying Accounts................................................... F-56
</TABLE>
F-1
<PAGE> 62
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
------------ ------------
($ IN THOUSANDS)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ........................................................ $ 12,019 $ 38,658
Restricted cash .................................................................. 4,754 192
Accounts receivable:
Oil and gas sales .............................................................. 33,380 17,045
Oil and gas marketing sales .................................................... 29,141 18,199
Joint interest and other, net of allowances of $1,714,000 and $3,218,000,
respectively ................................................................. 14,399 11,247
Related parties ................................................................ 3,455 4,574
Inventory ........................................................................ 3,596 4,582
Other ............................................................................ 3,025 3,049
------------ ------------
Total current assets ...................................................... 103,769 97,546
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ............................................... 2,422,373 2,315,348
Unevaluated properties ......................................................... 32,146 40,008
Less: accumulated depreciation, depletion and amortization ..................... (1,719,259) (1,670,542)
------------ ------------
735,260 684,814
Other property and equipment ..................................................... 70,155 67,712
Less: accumulated depreciation and amortization .................................. (35,099) (33,429)
------------ ------------
Total property and equipment .............................................. 770,316 719,097
------------ ------------
INVESTMENT IN GOTHIC ENERGY CORPORATION ............................................ 87,509 10,000
------------ ------------
OTHER ASSETS ....................................................................... 19,388 23,890
------------ ------------
TOTAL ASSETS ....................................................................... $ 980,982 $ 850,533
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt ........................... $ 799 $ 763
Accounts payable ................................................................. 23,768 24,822
Accrued liabilities and other .................................................... 43,103 34,713
Revenues and royalties due others ................................................ 33,753 27,888
------------ ------------
Total current liabilities ................................................. 101,423 88,186
------------ ------------
LONG-TERM DEBT, NET ................................................................ 983,230 964,097
------------ ------------
REVENUES AND ROYALTIES DUE OTHERS .................................................. 8,405 9,310
------------ ------------
DEFERRED INCOME TAXES .............................................................. 7,904 6,484
------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Stock, $.01 par value, 10,000,000 shares authorized; 1,557,037 and
4,596,400 shares of 7% cumulative convertible stock issued and outstanding
at June 30, 2000 and December 31, 1999,
respectively, entitled in liquidation (including dividends in arrears) to
$87.4 million and $249.1 million, respectively ................................. 77,852 229,820
Common Stock, par value of $.01, 250,000,000 shares authorized;
143,297,346 and 105,858,580 shares issued at June 30, 2000 and
December 31, 1999, respectively ................................................ 1,433 1,059
Paid-in capital .................................................................. 862,230 682,905
Accumulated earnings (deficit) ................................................... (1,045,984) (1,093,929)
Accumulated other comprehensive income (loss) .................................... (2,757) 196
Less: treasury stock, at cost; 3,806,185 and 10,856,185 common shares at
June 30, 2000 and December 31, 1999, respectively .............................. (12,754) (37,595)
------------ ------------
Total stockholders' equity (deficit) ...................................... (119,980) (217,544)
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) ............................... $ 980,982 $ 850,533
============ ============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-2
<PAGE> 63
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales ...................................... $ 100,221 $ 68,272 $ 187,514 $ 120,078
Oil and gas marketing sales ............................ 34,242 12,620 61,610 26,491
---------- ---------- ---------- ----------
Total revenues ..................................... 134,463 80,892 249,124 146,569
---------- ---------- ---------- ----------
OPERATING COSTS:
Production expenses .................................... 12,581 11,183 25,126 25,175
Production taxes ....................................... 5,717 2,798 10,933 4,788
General and administrative ............................. 3,188 3,268 6,220 7,292
Oil and gas marketing expenses ......................... 33,122 11,673 59,666 24,958
Oil and gas depreciation, depletion and amortization ... 24,877 24,233 49,360 47,386
Depreciation and amortization of other assets .......... 1,836 1,972 3,702 4,138
---------- ---------- ---------- ----------
Total operating costs .............................. 81,321 55,127 155,007 113,737
---------- ---------- ---------- ----------
INCOME FROM OPERATIONS .................................. 53,142 25,765 94,117 32,832
---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest and other income .............................. 1,667 2,967 2,859 3,840
Interest expense ....................................... (21,813) (20,259) (42,677) (40,149)
---------- ---------- ---------- ----------
Total other income (expense) ....................... (20,146) (17,292) (39,818) (36,309)
---------- ---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES ....................... 32,996 8,473 54,299 (3,477)
---------- ---------- ---------- ----------
INCOME TAX EXPENSE ...................................... 1,362 326 1,463 326
---------- ---------- ---------- ----------
NET INCOME (LOSS) ....................................... 31,634 8,147 52,836 (3,803)
Preferred stock dividends .............................. (2,907) (4,026) (6,949) (8,052)
Gain on redemption of preferred stock .................. 1,481 -- 11,895 --
---------- ---------- ---------- ----------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS ...... $ 30,208 $ 4,121 $ 57,782 $ (11,855)
========== ========== ========== ==========
EARNINGS (LOSS) PER COMMON SHARE:
Basic .................................................. $ 0.26 $ 0.04 $ 0.53 $ (0.12)
========== ========== ========== ==========
Assuming Dilution ...................................... $ 0.22 $ 0.04 $ 0.36 $ (0.12)
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING:
Basic .................................................. 116,466 97,049 108,196 97,049
========== ========== ========== ==========
Assuming dilution ...................................... 146,113 101,450 146,285 97,049
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
<PAGE> 64
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
------------------------
2000 1999
---------- ----------
($ IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ..................................................... $ 52,836 $ (3,803)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization ............................. 51,258 49,923
Amortization of loan costs ........................................... 1,804 1,601
Amortization of bond discount ........................................ 42 35
(Gain) loss on sale of fixed assets and other ........................ (1) 98
Equity in losses (earnings) of equity investees ...................... 131 (35)
Bad debt expense ..................................................... 256 --
Other ................................................................ (36) --
Deferred income taxes ................................................ 1,463 326
---------- ----------
Cash provided by operating activities before changes in
current assets and liabilities .................................. 107,753 48,145
Changes in current assets and liabilities ............................ (23,883) (579)
---------- ----------
Cash provided by operating activities .............................. 83,870 47,566
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties ................. (78,947) (79,303)
Purchases of oil and gas properties ................................... (24,981) (6,484)
Sales of oil and gas properties ....................................... 1,368 17,387
Sales of non-oil and gas assets ....................................... 835 1,306
Additions to other property and equipment ............................. (3,390) (65)
Long-term loans made to third parties ................................. -- (511)
Long-term investments ................................................. (2,000) --
Investment in Gothic senior discount notes ............................ (22,352) --
Other ................................................................. (1,102) 325
---------- ----------
Cash used in investing activities .................................. (130,569) (67,345)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings .................................... 113,000 14,000
Payments on long-term borrowings ...................................... (93,500) --
Purchase of treasury stock ............................................ -- (53)
Cash received from exercise of stock options .......................... 764 240
---------- ----------
Cash provided by financing activities .............................. 20,264 14,187
---------- ----------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH .............................. (204) 3,625
---------- ----------
NET DECREASE IN CASH AND CASH EQUIVALENTS ............................... (26,639) (1,967)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD .......................... 38,658 29,520
---------- ----------
CASH AND CASH EQUIVALENTS, END OF PERIOD ................................ $ 12,019 $ 27,553
========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
<PAGE> 65
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
($ in thousands)
<S> <C> <C> <C> <C>
Net income (loss) .................................................... $ 31,634 $ 8,147 $ 52,836 $ (3,803)
Other comprehensive income (loss) - foreign currency translation
adjustments ........................................................ (2,475) 2,813 (2,953) 3,625
---------- ---------- ---------- ----------
Comprehensive income (loss) .......................................... $ 29,159 $ 10,960 $ 49,883 $ (178)
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
<PAGE> 66
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ACCOUNTING PRINCIPLES
The accompanying unaudited consolidated financial statements of
Chesapeake Energy Corporation and Subsidiaries ("Chesapeake") 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 and six months ended June 30, 2000 are not necessarily
indicative of the results to be expected for the full year.
The accompanying unaudited consolidated financial statements relate to
the three and six months ended June 30, 2000 (the "Current Quarter" and "Current
Period," respectively) and June 30, 1999 (the "Prior Quarter" and "Prior
Period," respectively).
2. LEGAL PROCEEDINGS
Bayard Securities Litigation
This putative class action alleging violations of the Securities Act of
1933 and the Oklahoma Securities Act was first filed in February 1998 against
Chesapeake and others on behalf of investors who purchased common stock of
Bayard Drilling Technologies, Inc. in, or traceable to, its initial public
offering in November 1997. Total proceeds of the offering were $254 million, of
which Chesapeake received net proceeds of $90 million as a selling shareholder.
Plaintiffs allege that Chesapeake, 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
Chesapeake under Section 15 of the Securities Act of 1933 alleging that
Chesapeake 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 Chesapeake. Chesapeake 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 Chesapeake for its costs of defense as incurred.
Patent Litigation
On September 21, 1999, judgment was entered in favor of Chesapeake 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 Chesapeake had infringed a patent belonging to Union Pacific
Resources Company. The court declared the patent invalid, held that Chesapeake
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
Chesapeake and UPRC are pending in the Federal Circuit Court of Appeals.
Chesapeake has appealed the trial court's ruling denying Chesapeake'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 Chesapeake, 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. Chesapeake acquired MC Panhandle, Inc. on April 28,
1998. MC Panhandle, Inc. has owned the leases
F-6
<PAGE> 67
since January 1, 1997, and the co-defendants are prior lessees. Plaintiffs claim
the leases terminated upon the cessation of production for various periods
occurring 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.
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
initially a jury verdict in two of the cases in favor of defendants.
Chesapeake'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 all of these cases. There are three related cases pending in other courts.
One was tried in the U.S. District Court, Northern District of Texas, Amarillo
Division, and resulted in a jury verdict for CP and its co-defendants. Judgment
has not yet been entered in that case.
Chesapeake 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.
Chesapeake 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 Chesapeake.
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 statements of operations for all entities with
complex capital structures. SFAS 128 requires a reconciliation of the numerator
and denominators of the basic and diluted EPS computations.
The following weighted securities were not included in the calculation
of diluted earnings per share, as the effect was antidilutive:
o In the Prior Period, options to purchase 12.8 million shares of common
stock at a weighted average exercise price of $1.77 and the assumed
conversion of the outstanding preferred stock (convertible into 33.1
million common shares) were antidilutive as a result of Chesapeake's loss
for the period.
o For the Prior Quarter, outstanding options to purchase 2.3 million shares
of common stock at a weighted average exercise price of $5.02 were
antidilutive because the exercise prices of the options were greater than
the average market price of Chesapeake's common stock. Additionally, the
assumed conversion of the outstanding preferred stock (convertible into
33.1 million common shares) was not included.
o In the Current Quarter and the Current Period, outstanding options to
purchase 0.7 million and 1.6 million shares of common stock, respectively,
at a weighted average exercise price of $10.57 and $6.76, respectively,
were antidilutive because the exercise prices of the options were greater
than the average market price of Chesapeake's common stock.
F-7
<PAGE> 68
A reconciliation for the Current Quarter, Prior Quarter and Current
Period is as follows:
<TABLE>
<CAPTION>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
---------- ---------- --------
(in thousands)
<S> <C> <C> <C>
FOR THE QUARTER ENDED JUNE 30, 2000:
BASIC EPS
Income available to common stockholders ........ $ 30,208 116,466 $ 0.26
========
EFFECT OF DILUTIVE SECURITIES
Assumed conversion of preferred stock at
beginning of period ....................... 2,907 21,797
Gain on redemption of preferred stock ........ (1,481) --
Employee stock options ....................... -- 7,850
---------- ----------
DILUTED EPS
Income available to common stockholders
and assumed conversions ..................... $ 31,634 146,113 $ 0.22
========== ========== ========
FOR THE QUARTER ENDED JUNE 30, 1999:
BASIC EPS
Income available to common stockholders ...... $ 4,121 97,049 $ 0.04
========
EFFECT OF DILUTIVE SECURITIES
Employee stock options ....................... -- 4,401
---------- ----------
DILUTED EPS
Income available to common stockholders
and assumed conversions ..................... $ 4,121 101,450 $ 0.04
========== ========== ========
FOR THE SIX MONTHS ENDED JUNE 30, 2000:
BASIC EPS
Income available to common stockholders ........ $ 57,782 108,196 $ 0.53
========
EFFECT OF DILUTIVE SECURITIES
Assumed conversion of preferred stock at
beginning of period ....................... 6,949 31,158
Gain on redemption of preferred stock ........ (11,895) --
Employee stock options ....................... -- 6,931
---------- ----------
DILUTED EPS
Income available to common stockholders
and assumed conversions ..................... $ 52,836 146,285 $ 0.36
========== ========== ========
</TABLE>
In the Current Quarter, Chesapeake engaged in a number of unsolicited
stock exchange transactions with institutional investors. Chesapeake exchanged a
total of 24.7 million shares of common stock (newly issued shares), plus a cash
payment of $8.3 million, 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. All preferred shares acquired in these transactions
were cancelled and retired and have the status of authorized but unissued shares
of undesignated preferred stock. A gain on redemption of the preferred shares
equal to $1.5 million was recognized as an increase to net income available to
common shareholders 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, and the cash
payment made, in exchange for the preferred shares.
In the Current Period, a total of 34.2 million shares of common stock,
plus a cash payment of $8.3 million, were exchanged for 3,039,363 shares of
preferred stock. These transactions 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 by
$16.8 million to $9.5 million. A gain on redemption of all preferred shares
exchanged through June 30, 2000 of $11.9 million ($1.5 million related to the
Current Quarter) is reflected in net income available to common shareholders in
determining basic earnings per share.
Subsequent to June 30, 2000, Chesapeake engaged in additional
transactions in which 9.2 million shares of common stock (newly issued shares)
were exchanged for 933,000 shares of its issued and outstanding preferred stock
with a liquidation value of $46.7 million plus dividends in arrears of $6.1
million. A $5.3 million loss on the redemption of these preferred shares will be
reflected in net income available to common shareholders in determining earnings
per share in the third quarter.
Chesapeake may acquire additional shares of preferred stock in the
future through negotiations with individual holders and, beginning May 1, 2001,
it may redeem outstanding shares of preferred stock for $52.45 per share plus
accumulated and unpaid dividends in cash and/or common stock.
F-8
<PAGE> 69
4. SENIOR NOTES
9.625% Notes
Chesapeake 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 Chesapeake and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
9.125% Notes
Chesapeake 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 Chesapeake and
are fully and unconditionally guaranteed, jointly and severally, by the
Guarantor Subsidiaries.
7.875% Notes
Chesapeake 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 Chesapeake
and are fully and unconditionally guaranteed, jointly and severally, by the
Guarantor Subsidiaries.
8.5% Notes
Chesapeake 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 Chesapeake and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
Chesapeake is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. Chesapeake's obligations
under its Senior Notes have been fully and unconditionally guaranteed, on a
joint and several basis, by each of Chesapeake'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 Chesapeake.
The Senior Note Indentures contain certain covenants, including
covenants limiting Chesapeake 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.
Chesapeake 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 Chesapeake'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, Chesapeake 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. Chesapeake had accumulated
dividends in arrears of $9.5 million related to its preferred stock as of June
30, 2000. This restriction does not affect Chesapeake's ability to borrow under
or expand its secured commercial bank facility. Chesapeake was unable to pay a
dividend on the preferred stock on May 1, 2000, the sixth consecutive dividend
payment date on which dividends had not been paid. As a result of Chesapeake's
failure to pay dividends for six quarterly periods, the holders of preferred
stock are entitled to elect two new directors to the Board. Based on the Current
Quarter financial results, Chesapeake was able to pay a dividend on the
preferred stock on August 1, 2000, although the Board of Directors did not
declare a dividend that would have been payable on that date.
F-9
<PAGE> 70
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, Chesapeake's subsidiaries which are not guarantors of
the Senior Notes (the "Non-Guarantor Subsidiaries") and Chesapeake. Separate
financial statements of each Guarantor Subsidiary have not been provided because
management has determined that they are not material to investors.
Chesapeake Energy Marketing, Inc. ("CEMI") was the only Non-Guarantor
Subsidiary for all periods presented. All of Chesapeake's other subsidiaries
were Guarantor Subsidiaries during all periods presented.
F-10
<PAGE> 71
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 2000
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents .............. $ (9,048) $ 5,057 $ 20,764 $ -- $ 16,773
Accounts receivable, net ............... 68,523 29,041 -- (17,189) 80,375
Inventory .............................. 3,375 221 -- -- 3,596
Other .................................. 2,456 28 541 -- 3,025
------------ ------------ ------------ ------------ ------------
Total current assets ................ 65,306 34,347 21,305 (17,189) 103,769
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ................. 2,422,373 -- -- -- 2,422,373
Unevaluated leasehold .................. 32,146 -- -- -- 32,146
Other property and equipment ........... 29,899 20,568 19,688 -- 70,155
Less: accumulated depreciation,
depletion and amortization ........... (1,734,280) (17,974) (2,104) -- (1,754,358)
------------ ------------ ------------ ------------ ------------
Net property and equipment .......... 750,138 2,594 17,584 -- 770,316
------------ ------------ ------------ ------------ ------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES .................. 922,163 -- 432,912 (1,355,075) --
------------ ------------ ------------ ------------ ------------
INVESTMENT IN GOTHIC ENERGY
CORPORATION ............................ 10,000 -- 77,509 -- 87,509
------------ ------------ ------------ ------------ ------------
OTHER ASSETS ............................. 1,438 8,496 17,266 (7,812) 19,388
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ............................. $ 1,749,045 $ 45,437 $ 566,576 $ (1,380,076) $ 980,982
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt .................... $ 799 $ -- $ -- $ -- $ 799
Accounts payable and other ............. 61,540 30,312 26,087 (17,315) 100,624
------------ ------------ ------------ ------------ ------------
Total current liabilities ........... 62,339 30,312 26,087 (17,315) 101,423
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT, NET ...................... 64,028 -- 919,202 -- 983,230
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE
OTHERS ................................. 8,405 -- -- -- 8,405
------------ ------------ ------------ ------------ ------------
DEFERRED INCOME TAXES .................... 7,904 -- -- -- 7,904
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES .................... 1,473,601 (1,531) (1,472,070) -- --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Common stock ........................... 26 1 1,424 (18) 1,433
Other .................................. 132,742 16,655 1,091,933 (1,362,743) (121,413)
------------ ------------ ------------ ------------ ------------
132,768 16,656 1,093,357 (1,362,761) (119,980)
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT) ......... $ 1,749,045 $ 45,437 $ 566,576 $ (1,380,076) $ 980,982
============ ============ ============ ============ ============
</TABLE>
F-11
<PAGE> 72
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1999
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
GUARANTOR NON-GUARANTOR
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) --
------------ ------------ ------------ ------------ ------------
INVESTMENT IN GOTHIC ENERGY
CORPORATION ............................... 10,000 -- -- -- 10,000
OTHER ASSETS ................................ 6,402 8,409 16,765 (7,686) 23,890
------------ ------------ ------------ ------------ ------------
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, NET ......................... 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-12
<PAGE> 73
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- ---------- ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED JUNE 30, 2000
REVENUES:
Oil and gas sales ......................... $ 100,221 $ -- $ -- $ -- $ 100,221
Oil and gas marketing sales ............... -- 79,973 -- (45,731) 34,242
---------- ---------- ---------- ---------- ----------
Total revenues ......................... 100,221 79,973 -- (45,731) 134,463
---------- ---------- ---------- ---------- ----------
OPERATING COSTS:
Production expenses and taxes ............. 18,298 -- -- -- 18,298
General and administrative ................ 2,841 299 48 -- 3,188
Oil and gas marketing expenses ............ -- 78,853 -- (45,731) 33,122
Oil and gas depreciation, depletion
and amortization ........................ 24,876 1 -- -- 24,877
Other depreciation and amortization ....... 1,008 20 808 -- 1,836
---------- ---------- ---------- ---------- ----------
Total operating costs .................. 47,023 79,173 856 (45,731) 81,321
---------- ---------- ---------- ---------- ----------
INCOME (LOSS) FROM OPERATIONS ............... 53,198 800 (856) -- 53,142
---------- ---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest and other income ................. 1,165 467 20,945 (20,910) 1,667
Interest expense .......................... (21,484) -- (21,239) 20,910 (21,813)
---------- ---------- ---------- ---------- ----------
(20,319) 467 (294) -- (20,146)
---------- ---------- ---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES ........... 32,879 1,267 (1,150) -- 32,996
INCOME TAX EXPENSE .......................... 1,362 -- -- -- 1,362
---------- ---------- ---------- ---------- ----------
NET INCOME (LOSS) ........................... $ 31,517 $ 1,267 $ (1,150) $ -- $ 31,634
========== ========== ========== ========== ==========
FOR THE THREE MONTHS ENDED JUNE 30, 1999
REVENUES:
Oil and gas sales ......................... $ 68,272 $ -- $ -- $ -- $ 68,272
Oil and gas marketing sales ............... -- 38,420 -- (25,800) 12,620
---------- ---------- ---------- ---------- ----------
Total revenues ......................... 68,272 38,420 -- (25,800) 80,892
---------- ---------- ---------- ---------- ----------
OPERATING COSTS:
Production expenses and taxes ............. 13,981 -- -- -- 13,981
General and administrative ................ 2,942 324 2 -- 3,268
Oil and gas marketing expenses ............ -- 37,473 -- (25,800) 11,673
Oil and gas depreciation, depletion
and amortization ........................ 24,233 -- -- -- 24,233
Other depreciation and amortization ....... 1,138 20 814 -- 1,972
---------- ---------- ---------- ---------- ----------
Total operating costs .................. 42,294 37,817 816 (25,800) 55,127
---------- ---------- ---------- ---------- ----------
INCOME (LOSS) FROM OPERATIONS ............... 25,978 603 (816) -- 25,765
---------- ---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest and other income ................. 440 2,408 29,188 (29,069) 2,967
Interest expense .......................... (29,009) -- (20,319) 29,069 (20,259)
---------- ---------- ---------- ---------- ----------
(28,569) 2,408 8,869 -- (17,292)
---------- ---------- ---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES ........... (2,591) 3,011 8,053 -- 8,473
INCOME TAX EXPENSE .......................... 326 -- -- -- 326
---------- ---------- ---------- ---------- ----------
NET INCOME (LOSS) ........................... $ (2,917) $ 3,011 $ 8,053 $ -- $ 8,147
========== ========== ========== ========== ==========
</TABLE>
F-13
<PAGE> 74
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ----------- ----------- ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE SIX MONTHS ENDED JUNE 30, 2000
REVENUES:
Oil and gas sales ...................... $ 187,167 $ 347 $ -- $ -- $ 187,514
Oil and gas marketing sales ............ -- 149,098 -- (87,488) 61,610
----------- ----------- ----------- ----------- -----------
Total revenues ...................... 187,167 149,445 -- (87,488) 249,124
----------- ----------- ----------- ----------- -----------
OPERATING COSTS:
Production expenses and taxes .......... 35,979 80 -- -- 36,059
General and administrative ............. 5,561 590 69 -- 6,220
Oil and gas marketing expenses ......... -- 147,154 -- (87,488) 59,666
Oil and gas depreciation, depletion
and amortization ..................... 49,259 101 -- -- 49,360
Other depreciation and amortization .... 2,034 40 1,628 -- 3,702
----------- ----------- ----------- ----------- -----------
Total operating costs ............... 92,833 147,965 1,697 (87,488) 155,007
----------- ----------- ----------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS ............ 94,334 1,480 (1,697) -- 94,117
----------- ----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest and other income .............. 1,963 803 41,912 (41,819) 2,859
Interest expense ....................... (42,439) (34) (42,023) 41,819 (42,677)
----------- ----------- ----------- ----------- -----------
(40,476) 769 (111) -- (39,818)
----------- ----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES ........ 53,858 2,249 (1,808) -- 54,299
INCOME TAX EXPENSE ....................... 1,463 -- -- -- 1,463
----------- ----------- ----------- ----------- -----------
NET INCOME (LOSS) ........................ $ 52,395 $ 2,249 $ (1,808) $ -- $ 52,836
=========== =========== =========== =========== ===========
FOR THE SIX MONTHS ENDED JUNE 30, 1999
REVENUES:
Oil and gas sales ...................... $ 120,078 $ -- $ -- $ -- $ 120,078
Oil and gas marketing sales ............ -- 73,258 -- (46,767) 26,491
----------- ----------- ----------- ----------- -----------
Total revenues ...................... 120,078 73,258 -- (46,767) 146,569
----------- ----------- ----------- ----------- -----------
OPERATING COSTS:
Production expenses and taxes .......... 29,963 -- -- -- 29,963
General and administrative ............. 6,464 781 47 -- 7,292
Oil and gas marketing expenses ......... -- 71,725 -- (46,767) 24,958
Oil and gas depreciation, depletion
and amortization ..................... 47,386 -- -- -- 47,386
Other depreciation and amortization .... 2,476 40 1,622 -- 4,138
----------- ----------- ----------- ----------- -----------
Total operating costs ............... 86,289 72,546 1,669 (46,767) 113,737
----------- ----------- ----------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS ............ 33,789 712 (1,669) -- 32,832
----------- ----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest and other income .............. 707 2,845 58,328 (58,040) 3,840
Interest expense ....................... (57,415) -- (40,774) 58,040 (40,149)
----------- ----------- ----------- ----------- -----------
(56,708) 2,845 17,554 -- (36,309)
----------- ----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES ........ (22,919) 3,557 15,885 -- (3,477)
INCOME TAX EXPENSE ....................... 326 -- -- -- 326
----------- ----------- ----------- ----------- -----------
NET INCOME (LOSS) ........................ $ (23,245) $ 3,557 $ 15,885 $ -- $ (3,803)
=========== =========== =========== =========== ===========
</TABLE>
F-14
<PAGE> 75
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE SIX MONTHS ENDED JUNE 30, 2000
CASH FLOWS FROM OPERATING ACTIVITIES ............ $ 88,395 $ (4,753) $ 228 $ -- $ 83,870
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ........................ (104,075) 1,515 -- -- (102,560)
Proceeds from sale of assets .................. 835 -- -- -- 835
Investment in Gothic senior discount notes .... -- (22,352) -- -- (22,352)
Other investments ............................. -- -- (2,000) -- (2,000)
Other additions ............................... (2,570) (46) (1,876) -- (4,492)
------------ ------------ ------------ ------------ ------------
(105,810) (20,883) (3,876) -- (130,569)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ...................... 113,000 -- -- -- 113,000
Payments on borrowings ........................ (93,500) -- -- -- (93,500)
Cash received from exercise of stock options .. -- -- 764 -- 764
Intercompany advances, net .................... (8,527) 10,284 (1,757) -- --
------------ ------------ ------------ ------------ ------------
10,973 10,284 (993) -- 20,264
------------ ------------ ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH ....................................... (204) -- -- -- (204)
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash ............... (6,646) (15,352) (4,641) -- (26,639)
Cash, beginning of period ..................... (7,156) 20,409 25,405 -- 38,658
------------ ------------ ------------ ------------ ------------
Cash, end of period ........................... $ (13,802) $ 5,057 $ 20,764 $ -- $ 12,019
============ ============ ============ ============ ============
FOR THE SIX MONTHS ENDED JUNE 30, 1999
CASH FLOWS FROM OPERATING ACTIVITIES ............ $ 22,128 $ 8,119 $ 17,319 $ -- $ 47,566
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ........................ (68,400) -- -- -- (68,400)
Proceeds from sale of other assets ............ 1,306 -- -- -- 1,306
Other additions ............................... 427 308 (986) -- (251)
------------ ------------ ------------ ------------ ------------
(66,667) 308 (986) -- (67,345)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ...................... 14,000 -- -- -- 14,000
Cash paid for purchase of treasury stock ...... -- (53) -- -- (53)
Cash received from exercise of stock options .. -- -- 240 -- 240
Intercompany advances, net .................... 33,665 2,217 (35,882) -- --
------------ ------------ ------------ ------------ ------------
47,665 2,164 (35,642) -- 14,187
------------ ------------ ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH ....................................... 3,625 -- -- -- 3,625
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash ............... 6,751 10,591 (19,309) -- (1,967)
Cash, beginning of period ..................... (17,319) 7,000 39,839 -- 29,520
------------ ------------ ------------ ------------ ------------
Cash, end of period ........................... $ (10,568) $ 17,591 $ 20,530 $ -- $ 27,553
============ ============ ============ ============ ============
</TABLE>
F-15
<PAGE> 76
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE THREE MONTHS ENDED JUNE 30, 2000:
Net income (loss) ......................... $ 31,517 $ 1,267 $ (1,150) $ -- $ 31,634
Other comprehensive income (loss) -
foreign currency translation ............ (2,475) -- -- -- (2,475)
------------ ------------ ------------ ------------ ------------
Comprehensive income ...................... $ 29,042 $ 1,267 $ (1,150) $ -- $ 29,159
============ ============ ============ ============ ============
FOR THE THREE MONTHS ENDED JUNE 30, 1999:
Net income (loss) ......................... $ (2,917) $ 3,011 $ 8,053 $ -- $ 8,147
Other comprehensive income (loss) -
foreign currency translation ............ 2,813 -- -- -- 2,813
------------ ------------ ------------ ------------ ------------
Comprehensive income (loss) ............... $ (104) $ 3,011 $ 8,053 $ -- $ 10,960
============ ============ ============ ============ ============
FOR THE SIX MONTHS ENDED JUNE 30, 2000:
Net income (loss) ......................... $ 52,395 $ 2,249 $ (1,808) $ -- $ 52,836
Other comprehensive income (loss) -
foreign currency translation ............ (2,953) -- -- -- (2,953)
------------ ------------ ------------ ------------ ------------
Comprehensive income ...................... $ 49,442 $ 2,249 $ (1,808) $ -- $ 49,883
============ ============ ============ ============ ============
FOR THE SIX MONTHS ENDED JUNE 30, 1999:
Net income (loss) ......................... $ (23,245) $ 3,557 $ 15,885 $ -- $ (3,803)
Other comprehensive income (loss) -
foreign currency translation ............ 3,625 -- -- -- 3,625
------------ ------------ ------------ ------------ ------------
Comprehensive income (loss) ............... $ (19,620) $ 3,557 $ 15,885 $ -- $ (178)
============ ============ ============ ============ ============
</TABLE>
F-16
<PAGE> 77
5. INVESTMENT IN GOTHIC ENERGY CORPORATION ("GOTHIC")
On June 27, 2000, CEMI purchased in a series of private transactions
96% of Gothic's $104 million of 14.125% Series B Senior Secured Discount Notes
for consideration of $77.5 million, comprised of $22.4 million in cash and $55.2
million of Chesapeake common stock (9,468,985 shares valued at $5.825 per
share), subject to adjustment. The acquired discount notes accrete at a rate per
annum of 14.125%, compounded semi-annually to an aggregate principal amount of
$99.7 million at May 1, 2002. Thereafter, the discount notes accrue interest at
the rate of 14.125% per annum, payable in cash semi-annually in arrears on May 1
and November 1 of each year commencing November 1, 2002. The discount notes
mature on May 1, 2006.
On June 30, 2000, Chesapeake entered into a letter of intent to acquire
the common stock of Gothic for 4.0 million shares of Chesapeake common stock.
Upon the closing of the transaction, Gothic's shareholders will own
approximately 2.7% of Chesapeake's common stock. The total acquisition cost to
Chesapeake will be approximately $345 million, including $235 million of Senior
Secured Notes issued by Gothic's operating subsidiary. The Gothic acquisition is
subject to the completion of definitive documentation and approval by Gothic's
shareholders. Completion of the transaction is expected by year-end 2000.
Also included in Chesapeake's investment in Gothic is Chesapeake's
April 1998 investment in Gothic's 12% Preferred Stock with a carrying value of
$10.0 million.
6. REVOLVING CREDIT FACILITY
At June 30, 2000, Chesapeake had a $75 million revolving bank credit
facility, maturing in July 2002, with a committed borrowing base of $75 million.
As of June 30, 2000, Chesapeake 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. On August 1, 2000, the revolving bank credit facility and
the borrowing base were increased to $100 million.
7. 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.
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.
Chesapeake has not yet determined the impact that adoption of FAS 133 will have
on the financial statements. However, Chesapeake believes that its commodity
derivatives will be designated as hedges in accordance with the relevant
accounting criteria.
F-17
<PAGE> 78
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 ("Chesapeake") 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 Chesapeake'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-18
<PAGE> 79
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
ASSETS
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
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
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-19
<PAGE> 80
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-20
<PAGE> 81
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-21
<PAGE> 82
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, Chesapeake issued a $2.2 million note payable as
consideration for the acquisition of certain oil and gas properties.
Chesapeake 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, Chesapeake recognized income tax benefits of $4,808,000
related to the disposition of stock options by directors and employees of
Chesapeake. 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, Chesapeake declared a dividend of $0.02 per
common share, or $1,486,000, which was paid on January 15, 1998. On June 13,
1997 Chesapeake declared a dividend of $0.02 per common share, or $1,405,000,
which was paid on July 15, 1997.
The accompanying notes are an integral part of these
consolidated financial statements.
F-22
<PAGE> 83
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) AND
COMPREHENSIVE INCOME (LOSS)
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31, SIX MONTHS ENDED YEAR ENDED
--------------------------- DECEMBER 31, JUNE 30,
1999 1998 1997 1997
------------ ------------ ------------ ------------
($ 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-23
<PAGE> 84
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Company
Chesapeake 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.
Chesapeake'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"). Chesapeake changed its fiscal year end from June 30 to December
31 in 1997. Chesapeake'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 ("Chesapeake"). All significant intercompany accounts and
transactions have been eliminated. Investments in companies and partnerships
which give Chesapeake 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, Chesapeake
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
Chesapeake invests in various equity securities and short-term debt
instruments including corporate bonds and auction preferreds, commercial paper
and government agency notes. Chesapeake 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 Chesapeake 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-24
<PAGE> 85
Oil and Gas Properties
Chesapeake follows the full-cost method of accounting under which all
costs associated with property acquisition, exploration and development
activities are capitalized. Chesapeake 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 Chesapeake's proved reserve value (based
on SEC PV10%) was evaluated by independent petroleum engineers, with the balance
evaluated by Chesapeake's engineers. In addition, Chesapeake'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. Chesapeake 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. Chesapeake 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.
Chesapeake 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 Chesapeake'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 Chesapeake'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
Chesapeake'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-25
<PAGE> 86
Income Taxes
Chesapeake 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 antidilutive. A
reconciliation for 1999 is as follows:
<TABLE>
<CAPTION>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ------
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999:
BASIC EPS
Income available to common stockholders.. $ 16,555 97,077 $ 0.17
=======
EFFECT OF DILUTIVE SECURITIES
Employee stock options................... -- 4,961
-------- --------
DILUTED EPS
Income available to common stockholders
and assumed conversions............... $ 16,555 102,038 $ 0.16
======== ======== =======
</TABLE>
Gas Imbalances -- Revenue Recognition
Revenues from the sale of oil and gas production are recognized when
title passes, net of royalties. Chesapeake follows the "sales method" of
accounting for its gas revenue whereby Chesapeake recognizes sales revenue on
all gas sold to its purchasers, regardless of whether the sales are
proportionate to Chesapeake's ownership in the property. A liability is
recognized only to the extent that Chesapeake has a net imbalance in excess of
the remaining gas reserves on the underlying properties. Chesapeake's net
imbalance positions at December 31, 1999 and 1998 were not material.
Hedging
Chesapeake 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 Chesapeake's oil and gas
production, in oil and gas marketing sales to the extent related to Chesapeake'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-26
<PAGE> 87
Comprehensive Income
In 1998, Chesapeake 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, Chesapeake 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 Chesapeake 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. Chesapeake 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, Chesapeake 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 Chesapeake at any time prior to March 15, 2004
at the make-whole prices determined in accordance with the indenture.
Also on March 17, 1997, Chesapeake 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 Chesapeake 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, Chesapeake 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 Chesapeake 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, Chesapeake issued $90 million principal amount of
10.5% Senior Notes due 2002 ("10.5% Senior Notes"). In April 1998, Chesapeake
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.
Chesapeake is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. Chesapeake'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 Chesapeake'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 Chesapeake.
The senior note indentures contain certain covenants, including
covenants limiting Chesapeake 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.
Chesapeake 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 Chesapeake'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
F-27
<PAGE> 88
December 31, 1999, Chesapeake 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. Chesapeake had
accumulated dividends in arrears of $19.3 million related to its preferred stock
as of February 29, 2000. Subsequent payments will be subject to the same
restrictions and are dependent upon variables that are beyond Chesapeake's
ability to predict. This restriction does not affect Chesapeake's ability to
borrow under or expand its secured commercial bank facility. If Chesapeake fails
to pay dividends for six quarterly periods, the holders of preferred stock will
be entitled to elect two new directors to the Board. Based on current
projections of cash flow and fixed charges, Chesapeake does not expect to be
able to pay a dividend on the preferred stock on May 1, 2000, which would be the
sixth consecutive dividend payment date on which dividends have not been paid.
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, Chesapeake's subsidiaries which are not guarantors of
the Senior Notes (the "Non-Guarantor Subsidiaries") and Chesapeake. Separate
audited financial statements of each Guarantor Subsidiary have not been provided
because management has determined that they are not material to investors.
Chesapeake Energy Marketing, Inc. ("CEMI") was a Non-Guarantor
Subsidiary for all periods presented. The following were additional
Non-Guarantor Subsidiaries: Chesapeake Acquisition Corporation during the
Transition Period and Chesapeake Canada Corporation during fiscal 1997. All of
Chesapeake's other subsidiaries were Guarantor Subsidiaries during all periods
presented.
F-28
<PAGE> 89
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1999
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
NON-
GUARANTOR GUARANTOR
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-29
<PAGE> 90
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1998
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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-30
<PAGE> 91
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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
============ ============ ============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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-31
<PAGE> 92
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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)
============ ============ ============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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-32
<PAGE> 93
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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
============ ============ ============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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-33
<PAGE> 94
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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
============ ============ ============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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-34
<PAGE> 95
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT 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-35
<PAGE> 96
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
Chesapeake 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 Chesapeake received net proceeds of $90 million as a selling
shareholder. Plaintiffs allege that Chesapeake, 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
Chesapeake under Section 15 of the Securities Act of 1933 alleging that
Chesapeake 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 Chesapeake. Chesapeake 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 Chesapeake for its costs of defense as incurred.
Patent Litigation
On September 21, 1999, judgment was entered in favor of Chesapeake 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 Chesapeake had infringed a patent belonging to Union Pacific
Resources Company. The court declared the patent invalid, held that Chesapeake
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
Chesapeake and UPRC are pending in the Federal Circuit Court of Appeals.
Chesapeake has appealed the trial
F-36
<PAGE> 97
court's ruling denying Chesapeake'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 Chesapeake, 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. Chesapeake 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. Chesapeake'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.
Chesapeake 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.
Chesapeake 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 Chesapeake.
Chesapeake 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, Chesapeake and its
subsidiaries are exposed to possible environmental risks. Chesapeake has
implemented various policies and procedures to avoid environmental contamination
and risks from environmental contamination. Chesapeake is not aware of any
potential material environmental issues or claims.
F-37
<PAGE> 98
5. INCOME TAXES
The components of the income tax provision (benefit) for each of the
periods are as follows:
<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 Chesapeake 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, Chesapeake 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. Chesapeake 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 Chesapeake's Canadian deferred tax assets. During 1999, this
valuation allowance was eliminated as part of a purchase price reallocation
related to a 1998 acquisition.
At December 31, 1999, Chesapeake 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. Chesapeake
F-38
<PAGE> 99
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 Chesapeake within a
three-year period (an "Ownership Change") would place an annual limitation on
Chesapeake's ability to utilize its existing tax carryforwards. Under
regulations issued by the Internal Revenue Service, Chesapeake 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 Chesapeake have
acquired working interests in certain of Chesapeake'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, Chesapeake 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 Chesapeake 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, Chesapeake
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
Chesapeake 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 Chesapeake for up
to 10% of the employee's annual salary with Chesapeake's common stock purchased
in the open-market. The amount of employee contribution is limited as specified
in the plan. Chesapeake may, at its discretion, make additional contributions to
the plan. Chesapeake 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> <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>
F-39
<PAGE> 100
Management believes that the loss of any of the above customers would
not have a material impact on Chesapeake's results of operations or its
financial position.
Chesapeake 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, Chesapeake began foreign operations in Canada. The geographic
distribution of Chesapeake'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, Chesapeake's Board of Directors approved the expenditure
of up to $30 million to purchase outstanding Company common stock. As of August
25, 1998, Chesapeake 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, Chesapeake acquired by merger the Mid-Continent
operations of DLB Oil & Gas, Inc. ("DLB") for $17.5 million in cash, 5 million
shares of Chesapeake's common stock, and the assumption of $90 million in
outstanding debt and working capital obligations.
On April 22, 1998, Chesapeake issued $230 million (4.6 million shares)
of its 7% Cumulative Convertible Preferred Stock, $50 per share liquidation
preference, resulting in net proceeds to Chesapeake of $223 million.
On March 10, 1998, Chesapeake acquired Hugoton Energy Corporation
("Hugoton") pursuant to a merger by issuing approximately 25.8 million shares of
Chesapeake's common stock in exchange for 100% of Hugoton's common stock.
On December 16, 1997, Chesapeake 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, Chesapeake 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 Chesapeake 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
Chesapeake's 1992 Incentive Stock Option Plan (the "ISO Plan")
terminated on December 16, 1994. Until then, Chesapeake 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,
F-40
<PAGE> 101
and the exercise price may not be less than the fair market value of the shares
underlying the options on the date of grant (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 Chesapeake'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 Chesapeake. 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 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 Chesapeake'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
Chesapeake 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 Chesapeake's 1999 Stock Option Plan (the "1999 Plan"),
nonqualified stock options to purchase Common Stock may be granted to employees
and consultants of Chesapeake 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.
Chesapeake 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 Chesapeake 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 Chesapeake'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 Chesapeake's employee stock options have characteristics
significantly different from those of traded options, and because
F-41
<PAGE> 102
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.
Chesapeake'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 Chesapeake'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 Chesapeake's stock option activity and related
information follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------- SIX MONTHS ENDED
1999 1998 DECEMBER 31, 1997
------------------------- -------------------------- ----------------------------
WEIGHTED-AVG WEIGHTED-AVG WEIGHTED-AVG
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
---------- -------------- ----------- -------------- ---------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding Beginning of Period... 11,260,375 $ 1.86 8,330,381 $ 5.49 7,903,659 $ 7.09
Granted........................... 3,210,493 1.11 14,580,063 2.78 3,362,207 8.29
Exercised......................... (622,120) 0.99 (108,761) 1.35 (219,349) 3.13
Cancelled/Forfeited............... (990,319) 1.87 (11,541,308) 5.64 (2,716,136) 13.87
----------- -------- ----------- -------- ---------- -------
Outstanding End of Period......... 12,858,429 $ 1.76 11,260,375 $ 1.86 8,330,381 $ 5.49
----------- -------- ----------- -------- ---------- -------
Exercisable End of Period......... 5,040,302 3,535,126 3,838,869
----------- ----------- ----------
Shares Authorized for Future Grants 2,560,687 1,761,359 4,585,973
----------- ----------- ----------
Fair Value of Options Granted During
the Period.......................... $ 0.77 $ 2.34 $ 4.98
-------- -------- -------
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
1997
--------------------------
WEIGHTED-AVG
OPTIONS EXERCISE PRICE
---------- --------------
<S> <C> <C>
Outstanding Beginning of Year...... 7,602,884 $ 4.66
Granted............................ 3,564,884 19.35
Exercised.......................... (1,197,998) 1.95
Cancelled/Forfeited................ (2,066,111) 22.26
---------- -------
Outstanding End of Year............ 7,903,659 $ 7.09
---------- -------
Exercisable End of Year............ 3,323,824
----------
Shares Authorized for Future Grants 5,212,056
----------
Fair Value of Options Granted During
the Year.............................. $ 7.51
-------
</TABLE>
F-42
<PAGE> 103
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 Chesapeake 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 taxes with respect to such tax benefits.
During 1999, 1998 and the Transition Period, Chesapeake did not recognize any
such tax benefits.
10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Chesapeake 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. Chesapeake'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 Chesapeake to
credit risk from its counterparties and to basis risk. Chesapeake does not
expect that the counterparties will fail to meet their obligations given their
high credit ratings.
Hedging Activities
Periodically Chesapeake 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 Chesapeake pays the counterparty and below which
Chesapeake is paid by the counterparty,
(ii) the purchase of index-related puts that provide for a "floor"
price below which the counterparty pays Chesapeake 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 Chesapeake 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 Chesapeake's oil and gas production.
Chesapeake only enters into commodity hedging transactions related to
Chesapeake'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, Chesapeake had the following open natural gas
swap arrangements designed to hedge a portion of Chesapeake's domestic gas
production for periods after December 1999:
F-43
<PAGE> 104
<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, Chesapeake would have incurred a gain of $0.5 million.
As of December 31, 1999, Chesapeake had no open oil swap arrangements.
Chesapeake has also closed transactions designed to hedge a portion of
Chesapeake's domestic oil and natural gas production. The net unrecognized
losses resulting from these transactions, $3.9 million as of December 31, 1999,
will be recognized as price adjustments in the months of related production.
These hedging gains and losses are set forth below ($ in thousands):
<TABLE>
<CAPTION>
HEDGING GAINS (LOSSES)
---------------------------------------
MONTH GAS OIL TOTAL
----- ------------- ------------ ----------
<S> <C> <C> <C>
January 2000................... $ -- $ (995) $ (995)
February 2000.................. -- (1,061) (1,061)
March 2000..................... 689 (851) (162)
April 2000..................... 71 (647) (576)
May 2000....................... 73 (668) (595)
June 2000...................... 71 (647) (576)
July 2000...................... 73 (231) (158)
August 2000.................... 73 -- 73
September 2000................. 71 -- 71
October 2000................... 73 -- 73
-------- ------- --------
$ 1,194 $(5,100) $ (3,906)
======== ======= ========
</TABLE>
Subsequent to December 31, 1999, Chesapeake entered into the following
natural gas swap arrangements designed to hedge a portion of Chesapeake'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, Chesapeake entered into the following
crude oil swap arrangements designed to hedge a portion of Chesapeake'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 Chesapeake'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
Chesapeake also utilizes hedging strategies to manage fixed-interest
rate exposure. Through the use of a swap arrangement, Chesapeake believes it can
benefit from stable or falling interest rates and reduce its current
F-44
<PAGE> 105
interest expense. During 1999, Chesapeake'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 Chesapeake accordingly. If the floating rate exceeds the fixed rate,
Chesapeake will pay the counterparty. The interest rate swap agreement contains
a "knock-out 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 Chesapeake'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, Chesapeake would have been required to pay the counterparty approximately
$16.7 million. However, because of the knock-out provision discussed above and
the volatility of interest rates, Chesapeake does not believe that this
worst-case scenario is a fair measure of the market value of the swap agreement
and, therefore, would not pay this amount to cancel the transaction. Results
from interest rate hedging transactions are reflected as adjustments to interest
expense in the corresponding months covered by the swap agreement.
The table below presents principal cash flows and related weighted
average interest rates by expected maturity dates. The fair value of the
long-term debt has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
----------------------------------------------------------------------------------------
YEARS OF MATURITY
----------------------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
-------- -------- -------- -------- ------- ----------- -------- ----------
($ IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES:
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 Chesapeake to
concentrations of credit risk consist principally of cash, short-term
investments in debt instruments and trade receivables. Chesapeake'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 Chesapeake. The industry concentration has the potential to impact
Chesapeake'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. Chesapeake 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
Chesapeake 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.
F-45
<PAGE> 106
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. Chesapeake estimates the fair value of its long-term (including
current maturities), fixed-rate debt using primarily quoted market prices.
Chesapeake'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 debt approximates its fair value as interest rates are primarily
variable, based on prevailing market rates. Chesapeake estimates the fair value
of its convertible preferred stock, which was issued in April 1998, using quoted
market prices. Chesapeake'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 $48.9 million, respectively.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to Chesapeake's oil
and gas producing activities are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
U.S. CANADA COMBINED
-------------- ------------- ------------
($ 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
========== ========== ==========
DECEMBER 31, 1998
U.S. CANADA COMBINED
-------------- ------------- ------------
($ IN THOUSANDS)
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. Chesapeake capitalized
approximately $3.5 million, $6.5 million, $5.1 million and $12.9 million of
interest during 1999, 1998, the Transition Period and fiscal 1997, respectively,
on significant investments in unproved properties that were not yet included in
the amortization base of the full-cost pool. Chesapeake will continue to
evaluate its unevaluated properties; however, the timing of the ultimate
evaluation and disposition of the properties has not been determined.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999
U.S. CANADA COMBINED
-------------- ------------- ------------
($ 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-46
<PAGE> 107
<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
========== ========== =========
</TABLE>
<TABLE>
<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
========== ========== =========
</TABLE>
<TABLE>
<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)
Chesapeake'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 Chesapeake's oil and gas producing activities. It does not include any
allocation of Chesapeake's interest costs and, therefore, is not necessarily
indicative of the contribution to consolidated net operating results of
Chesapeake'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
========== ========== =========
</TABLE>
<TABLE>
<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) $(483,600)
========== ========== =========
</TABLE>
F-47
<PAGE> 108
<TABLE>
<CAPTION>
SIX MONTHS ENDED DECEMBER 31, 1997
U.S. CANADA COMBINED
-------------- ------------- ------------
($ 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)
========== ========== =========
</TABLE>
<TABLE>
<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 Chesapeake'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 Chesapeake'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 Chesapeake's petroleum engineers.
o As of December 31, 1999, Williamson Petroleum Consultants, Inc.
("Williamson"), Ryder Scott Company L.P. ("Ryder Scott"), and
Chesapeake's internal reservoir engineers evaluated 50%, 16%, and 34%
of Chesapeake's combined discounted future net revenues from
Chesapeake's estimated proved reserves, respectively.
o As of December 31, 1998, Williamson, Ryder Scott, H.J. Gruy and
Associates, Inc. and Chesapeake's internal reservoir engineers
evaluated 63%, 12%, 1% and 24% of Chesapeake's combined discounted
future net revenues from Chesapeake'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 Chesapeake's combined
discounted future net revenues from Chesapeake's estimated proved
reserves, respectively.
o As of June 30, 1997, the reserves evaluated by Williamson constituted
approximately 41% of Chesapeake's combined discounted future net
revenues from Chesapeake'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. Chesapeake emphasizes that reserve
estimates are inherently imprecise. Chesapeake's reserve estimates were
generally based upon extrapolation of historical production trends, analogy to
similar properties and 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.
F-48
<PAGE> 109
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 Chesapeake's oil and gas reserves were located in
the United States.
Presented below is a summary of changes in estimated reserves of
Chesapeake 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
========== ========== ========== ========== ========== ==========
</TABLE>
<TABLE>
<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
========== ========== ========== ========== ========== ==========
</TABLE>
<TABLE>
<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>
<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>
F-49
<PAGE> 110
During 1999, Chesapeake acquired approximately 101 Bcfe of proved
reserves through purchases of oil and gas properties for consideration of $52
million. Chesapeake also sold 59 Bcfe of proved reserves for consideration of
approximately $46 million. During 1999, Chesapeake 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 Chesapeake'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, Chesapeake 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, Chesapeake 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 Chesapeake'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, Chesapeake 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. Chesapeake estimates that it
acquired approximately 26.4 Bcfe in connection with this acquisition.
For the fiscal year ended June 30, 1997, Chesapeake 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, Chesapeake recorded
aggregate downward adjustments to proved reserves of 159 Bcfe for the Knox,
Giddings and Louisiana Trend areas.
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. Chesapeake 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.
F-50
<PAGE> 111
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect Chesapeake'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 Chesapeake'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
============ ============ ============
</TABLE>
<TABLE>
<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>
<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
============ ============ ============
</TABLE>
<TABLE>
<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
$2.12 per Mcf of gas.
F-51
<PAGE> 112
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
U.S. CANADA COMBINED
------------ ------------ ------------
($ 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>
<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
============ ============ ============
</TABLE>
<TABLE>
<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
============ ============ ============
</TABLE>
F-52
<PAGE> 113
<TABLE>
<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>
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.
F-53
<PAGE> 114
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
</TABLE>
<TABLE>
<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 value of future
net revenues for Chesapeake'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, Chesapeake 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 Chesapeake's
investment in preferred stock of Gothic Energy Corporation, and the remainder
was related to certain of Chesapeake's gas processing and transportation assets
located in Louisiana.
14. ACQUISITIONS
During 1998, Chesapeake 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 $20 million of other acquisition related
costs.
In March 1998, Chesapeake acquired Hugoton Energy Corporation
("Hugoton") pursuant to a merger by issuing 25.8 million shares of Chesapeake's
common stock in exchange for 100% of Hugoton's common stock. The acquisition of
Hugoton was accounted for using the purchase method as of March 1, 1998, and the
results of operations of Hugoton have been included since that date.
The following unaudited pro forma information has been prepared
assuming Hugoton had been acquired as of the beginning of the periods presented.
The pro forma information is presented for informational purposes only and is
not necessarily indicative of what would have occurred if the acquisition had
been made as of those dates. In addition, the pro forma information is not
intended to be a projection of future results and does not reflect the
efficiencies expected to result from the integration of Hugoton.
F-54
<PAGE> 115
Pro Forma Information (Unaudited)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
1998 1997
----------- -------
($ 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>
Chesapeake 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 Chesapeake's
consolidated results of operations.
15. SUBSEQUENT EVENTS
In January and February 2000, Chesapeake engaged in five separate
transactions with two institutional investors in which Chesapeake 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:
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 $50
million liquidation amount of Gothic Series B preferred stock,
including dividends in arrears, and 2.4 million shares of Gothic common
stock, for a permanent assignment to Chesapeake of certain undeveloped
leasehold interests that were originally subject to a reassignment
obligation to Gothic.
F-55
<PAGE> 116
SCHEDULE II
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ 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 Chesapeake'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-56
